Q2 2020 Callon Petroleum Co Earnings Call
[music].
Good day and welcome to the College Petroleum Company second quarter, 2020 financial and operating results Conference call all participants will be in listen only mode.
As a reminder, this call is being webcast at a replay of the called will be archived on the company's website for approximately one year.
I'd now like turn the call every two marker director of Investor Relations for opening remarks. Please go ahead Sir.
Thank you call a good morning, everyone and thank you for taking the time to join our conference call with me. This morning hard Joe Gatto, Our President and Chief Executive Officer, Dr. Jeffs Palmer, our Chief operating Officer, Joe Mom, our Chief Financial Officer.
In your prepared remarks will be referencing to earnings results presentation, we posted yesterday afternoon to our website. So I encourage everyone to download the presentation that you haven't already.
On the slides on our events and presentations page located within the Investor section of our website at Www Dot Cowen Dot com.
Before we begin I'd like to remind everyone to review our cautionary statements disclaimers and important disclosures included on slide two and three of today's presentation.
We'll make some forward looking statements during today's call refer to estimate to the plans actual results could differ materially due to factors noted on the slides and in our periodic yet you see filings.
We'll also refer to some non-GAAP financial measures today, which we believe helped facilitate comparisons across periods with our peers any non-GAAP measures. We reference provided reconciliations to the nearest corresponding GAAP measure let me find these reconciliations in the appendix to the presentation slides in our earnings press release both away.
Which are available on our website.
Following our prepared remarks, well open the call for acuity.
With that I'd like to turn the call over to Joe Gotta go.
Thanks Mark.
Our team posted impressive numbers from the second quarter, Mr very challenging commodity environment, a rapid change in our daily work routines.
Development in operating cost saw meaningful declines generate synergy realization was ahead of targets and ahead of schedule and importantly, countless free cash flow positive setting the stage for future quarters of free cash flow for debt reduction.
Our strong operational start to the year as a combined company continued to show its impact in the second quarter with an 8% sequential production gain to just under 109000 Boe per day operational Capex I've, just 85 million.
In addition, our lease operating expense drop quarter over quarter, despite having placed more than 60, new wells on production since the beginning of the year.
With the proactive changes we've made to rightsize, the combined organization and reductions in compensation for our leadership team and board of directors reached an all time low and catching expense could be we have 69 cents per BLE in an all in total cash DNA inclusive of capitalized cost $1.37 per be away for the second quarter.
In aggregate, our total operating costs plus full cash DNA were under $9.60 per Boe week.
Yet another reflection of the benefits for scaled operating model and the focus of the entire organization and lowering our cost structure for the future.
Flipping to slide five we've created a balanced portfolio of development opportunities that provides a high degree of Optionality with respect to capital allocation, while we enjoy a deep inventory of larger scale projects across the asset base with strong ire ours at $35 to $40 per barrel.
The added ability to pivot based on bearing cash conversion cycles and capital intensity profiles provides us with the tools to navigate volatile markets and generate sustained cash flows and associated returns on capital.
This flexibility combined with mature production base in the structural well cost savings, we have delivered underpins our outlook for durable cash flow generation as we're able to reduce aren't reinvestment rate.
While maintaining production levels in a low price environment.
Importantly, all of our core operating areas reside in Texas, and we have no exposure to federal lands.
Within the state of Texas, We also benefit from diversified base and exposure to provides pricing point optionality in a natural hedge against unforeseen uptake disruptions or pricing point dislocations that we've seen occur on several occasions in recent years.
Moving to slide six.
Comments here. This year is certainly for us our team in the sector to radically shift gears and embrace a very different outlook.
During our first quarter call. We detailed the initiatives we are undertaking in response to rapidly changing market conditions, including a complete hall in drilling completion activities during the second quarter.
As we sit here today, we have an inventory of approximately 70 drilled uncompleted wells across the Eagle Ford in Permian After investments made during the first few months in the year.
Beginning later this month, we will returns were reduced level of activity with a focus on working through that DUC inventory and setting the stage for a maintenance capital plan in 2021.
We plan to utilize one full time completion crew and two to three drilling rigs over the remainder of 2020 as part of our modified development plan that calls for operational capital expenditures of approximately $150 million.
This activity planned for the second half dovetails with our 2021 outlook for approximately $400 million investment with average annual production levels expected to be in line with average daily volumes for the fourth quarter of 2020.
And a 2021 exit rate similar to the 100000 Boe per day of projected average annual volumes for 2020.
All of the free cash flow, we generate over this period of six quarters, which we currently estimate to be roughly $150 million at $40 per barrel flat WT.
Will be dedicated the credit Phyllis facility repayment and complement potential proceeds from our asset monetization initiatives.
Well, we have been constantly focused on driving down costs and streamlining our organization.
We've also been determined to make sure that our sustainability efforts are improving at the same pace.
If not faster.
On slide seven you can see that we continue to raise the bar for safety metrics water recycling capacity in usage and meaningful changes to our governance and compensation policies.
Last year, we premiered the sustainability portion of our corporate web site to quantify and expound on our ESG practices.
Next month, we will publish our first formal sustainability report, which will set a new baseline for our reporting practices and disclosures as these initiatives are advanced in partnership with our investors over time.
Moving to slide eight.
Much has been set about the need to rightsize the June a burden across the industry.
We are firmly aligned with that sentiment and affected a meaningful reduction our cost structure through the consolidation transaction with credo.
We have maintained momentum on this front in the first half of 2020 and implemented several measures to drive further reductions without impeding our ability to execute our future development plans and strategic initiatives.
So let can't shark captures a variety of payroll non payroll and related synergy costs realizations ultimately leading to projected cash DNA reduction inclusive of our capitalized cost of $75 million over 29 team.
These are changes that we expect to endure as they are largely structural in nature and represent longer term adjustments to cowens cost structure.
At this point I'm going to turn the call over to Jeff to discuss operations.
Great. Thanks, Joe Good morning, everybody.
Team has been working hard to identify opportunities for improvement across the expanded asset base.
And we've made some meaningful changes that are driving down costs, while also helping to achieve the environmental initiatives, Joe mentioned already and as part of our increased focus on sustainability and of course, Ron on slide nine right now.
Total elouise inclusive of Workovers as down over 10% from the pro forma quarterly run rate in 2019 coming in at roughly $50 million second quarter.
Those savings really come from five primary drivers are pushed towards field electrification.
Expanding our in house chemical management process.
Improved electric submersible pumps man that management, we call those dsps.
Expansion and optimization of our water disposal network and then overall just improved field oversight, which takes into account things like.
Compressor optimization, Workover planning and timing analytics, and then of course, our our vendor partnerships.
In the upper right hand portion of the slide we've shared some of that direct impacts from these changes, which not only benefit the company financially, but contribute to a lower environmental impact as well and so this is really and truly an area, where we can claim a win win win for Callon, our investors and the communities.
Is that that we work in.
On slide 10, the progress we've made in the Delaware over the past 18 months is is simply phenomenal.
Costs are down close to $400 per lateral foot or reduction of roughly 35%.
At the same time, we continue to gain a better understanding of how to create improved well performance.
The scale development model is driving efficiencies that result in long term structural savings and those are being complemented by improvements to our well design and drilling and completion practices. These intern are increasing savings beyond simple efficiency uptick from the multi well multi pad based development.
While we've seen some softening of cost from vendors to some extent the vast majority of our gains have come from improved practices and beneficial well design changes.
And of course will employ these practices on Delaware and Midland Eagle Ford drilling and completions in the second half of the year.
On the next slide Slide 11, and I think we've we've.
Shown this slide before but you can see that in each of the three asset areas.
We've continued to see improvements during the second quarter and it should come as no surprise and one of our primary focus areas in the Delaware that the greatest rate of change still lies in the Delaware.
But you May note that our improvement in the Midland Basin for instance of $100 per lateral foot is actually even wrote more robust in the Delaware.
Reflecting a 17% improvement from our previous figure.
The right hand portion of the slide capture some of the primary drivers behind the capital efficiency improvements in our consistent with some of the things that we've mentioned earlier in the presentation.
On slide 12.
The progress that we've made has not been limited simply to cost reductions.
Strong recent well performance helps to showcase the design modifications and choke management process that we're using in the Delaware and our completion changes and spacing modifications in the Midland Basin.
The nine wells Duncan Korten, right project, which is a Midland Basin project that was placed on production Wild horse in June.
Significantly outperformed the offset four well pad from 29, keeping the same area. Despite having multiple partially bound wells in this new development.
And then in the lower chart, Dorothy Sampson seven well pad in Houston Reeves County that we brought on earlier in the quarter have performed quite well against the original Crowley Sinclair offset wells they.
Tim closed a project that we have in the past referred to as the six.
The.
The partially bound Wolfcamp, a and B wells in this area on this development are performing on par or ahead of the unbounded offsets.
That wraps up the operation sides, so I'm going to turn things over to Jim.
Thank you very much Jeff and good morning, everyone.
You could say the commodity prices during the second quarter left something to do desired our unhedged oil realizations were down 55% the duplicative impact of an oil price war and the global pandemic that shutdown economies across the globe was evident in our operating revenues for the quarter.
Fortunately, we've always maintained a strong hedge book and we were able to restructure our hedges in March and ended up with an almost 100 million dollar cash hedge settlement gain during the second quarter that helped to mitigate some of the impact of falling prices.
From a marketing standpoint, we used some fixed price contracts in the Eagle Ford during the quarter.
But essentially all of those back into our EMEA age related pricing agreements our decision to minimize shut ins during the quarter did leave us with the benefit of not holding any commodity imbalances with buyers, which otherwise would have needed to be fulfilled with additional volumes at those second quarter prices during the second.
And half of the year.
As shown on the slide on page 13, as we look forward into third quarter, both Walheim NGL pricing.
Has improved and we believe that oil realizations are likely to rebound nor to roughly 95% of the W.T.I. benchmark.
On the next page Slide 14. It shows we recently converted some of our 2020 swaps back into two way callers, allowing us to participate in oil upside to $45 a barrel in the second half of the year.
We have also actively begun layering in positions for 2021.
Although we believe that oil prices could rise further and consequently have focused on extending our natural gas positions and hedges for ethane.
If you compare the second half of 2020 oil chart with the 2021 positions below it you will note we are shifting more of our hedging exposure to brand in EMEA H. based instruments as we begin utilizing our new firm transportation.
And associated deal term deals.
On slide 15.
You mentioned that as Joe described earlier, we now see a path to nearly a 150 million in free cash flow over the next six quarters. This along with a normalization in our working capital balance is forecast to methodically reduce our credit facility borrowings into 2021.
We continue to look at various opportunities to further reduce our leverage leverage and engage with parties that have shown interest in a number of our different monetization candidates between our operating cost improvements free cash flow generation Monetizations and hedging program We act.
Back to have ample opportunity to improve our liquidity position.
Page 16, the final slide I have provides an update on our annual guidance expectations, which we are updating and reinstituting as of this quarter.
Please note that we have shifted to providing guidance on an absolute dollar basis through the majority of our cost categories. As we believe this provides a better perspective on expense run rates versus derive per unit guidance measures, while it's a bit too early to provide the full range of X.
Spectator runs for 2021, our preliminary plans point toward 400 million of operational capital for average daily production of 90 to 95 Mboe per day.
While we expect mile declines in production from now until the early portion of next year our activity levels in 2021 should drive the trajectory that balances full year production with our fourth quarter 2020 expectations, while continuing to generate free cash flow throughout the year.
At this point I would like to turn the call back over to Joe.
Thanks, Jim.
Before we get to QNX wanted to take a second in command our team.
We're extremely hard winter our integration process the proved to be a success.
Early time here against a backdrop has been completely changed since we charted our course as a newly combined company earlier in the year.
Results in our outlook to provide very tangible evidence of that success.
We also recognize it's been a difficult few months for not only the people Cowen but our nation as a whole.
We will continue to do whats necessary protect our employees partners and the communities of Houston Midland in South Texas.
His ongoing efforts are squarely aligned with the interest of shareholders and cowens improving outlook as we navigate this period of uncertainty for the industry.
With that coal like to open the line for acuity.
Thank you and we will now begin the question and answer session.
If you like you ask your question. Please press Star then one.
If you'd like to withdraw your question. Please press Star then too.
We currently I think you please limit yourself to one question and one follow up.
First question today will come from Brad Heffern with RBC capital markets. Please go ahead.
Hey, good morning, everyone. Thanks for taking my questions.
I wanted to start off with a just a question on capital allocation across the area. So it made a lot of progress in terms of well costs than in the Midland and Delaware and some in the Eagle her but the costs our state more flat than the other areas. So just curious if that changes how you think about capital allocation to the Eagle Ford and if we can see sort.
Of larger portion going to the other areas than maybe we have in the path.
Yeah, I guess, Brad front from a high level and let me start out and get jeffs perspective here as well but.
Eagleford.
I think started with a very compelling.
Cost structure going into.
Combined equity they firmly moved as credo into larger scale development utilizing central processing facilities, and really gotten into manufacturing mode and a lot of ways.
Great example of where we wanted to take the Permian and we had.
Great tangible anecdote there in the Eagle Ford So.
You will continue to drive down costs, there with best practices and some of the things that the Jeff talked about but.
Overall, it fits very well within two our capital allocation scheme that I talked about in terms of a mix of.
Cash conversion cycle projects as well as capital intensity, so the Eagle Ford.
Certainly a big part of the puzzle and going into some of the weakness we saw earlier this year, we actually shifted some more capital from.
The Delaware into the Eagleford and we expect that to continue.
For the coming quarters.
Okay, Great and then I guess on the borrowing base. So are there any expectations you again sort of for the fall Redetermination I'm just thinking about it from the standpoint of it seems like the PDP basins like we're going to be lower based on the plan, but then at the same time.
Theoretically the price that could be higher so any thoughts about how the same thing sort of interplay.
Yes.
I am all tried yeah I'll take that and then if you want to kind of pitch it back to you.
The focus.
That we had during the spring Redetermination was on adequate liquidity and an appropriate runway to execute on the de leveraging plans. We have we did a really in a period of extremely high volatility in late April in as we as we look back on that Redetermination.
None of the statistics show over 85% of oil weighted borrowers saw you know a greater than 25% decline in their borrowing base. So as we look into for Q2 address your question, specifically I think it's probably a little bit too early to make a prediction on what might happen in.
November.
We went through that in late April and there was a day that crude went negative so I'm reluctant to to make an absolute prediction for you, but I will say I think there's some real positives that we have heading into that redetermination. The generation of free cash flow in 2020 and as Joe men.
In the visible path for sustainability the banks recognize.
Establishing a post merger track record of the operational successes will be helpful to us all the cost improvement and the synergy realization will now have.
Multiple months to show to the Bank group.
Rising commodity prices will matter normalized basis differentials and I think we're already starting to see improvements in bank price decks.
We also talked during the call that.
We are actively hedging or through 2021.
And that should give some benefit in the in the upcoming Redetermination. The last thing I would kind of say is that there was.
Kind of broader sector volatility as well hopefully a lot of that.
Has been dealt with in the first half of 2020, and we'll we'll be we'll be prepared for the Redetermination, Joe any anything you would add to that.
Yeah, I think just one quick point. Thank you brought up that the PDP volumes and one thing to take into consideration with that we went into our redetermination with it.
Reserve report at the end of the first quarter.
We brought up a fair amount of wells on after that as well as you know.
We don't get specifically involved in the process, but we know that.
Typically when you have wells come on sort of at the end of the first quarter. While they are included in that reserve report they do get risks for early time performance. So.
You know, which reduced reduction in activity might say, well, maybe PDP is going to be a bit less but we've taken those factors, it's not as simple as that but you'd have to take it all as of the combined.
Outlook and a lot of points that Jim brought up.
Equally the board.
Okay. Thank you.
And our next question will come from Gabe Daoud with Cowen. Please go ahead.
Hey, good morning, guys. Thanks for all the color. Thus far was hoping maybe we could start with the.
400 million and operational.
Capex for 2021, just curious I guess, how many ducs is that plan contemplate you guys drawing down throughout the year and then I guess, how does that number that maintenance capital number change as you move throughout 21 and then during 2022.
Jeff you want them.
Kicks off there.
Sure. The the majority of the back half of that 2020 program will.
In part be focused on reducing the amount of DUC inventory that we have on hand right. Now. So we've got about 70, we do have 70 ducts split about half in the Eagle Ford and then path in the Permian. So we'll be working off a number of those projects relatively quickly when we hit.
Here and then the next month or so we're going to resume some drilling operations.
And.
Continue to build up at least a modest DUC inventory. The one completion crew, although it's going to be and I say, one new being about an average of one into 2021 will be working in both basins.
And we'll be able to you for the most part keep up with the inventory that will put together from the two to three drilling rigs.
They show US that's a that's helpful. And then just a follow up Joe maybe just hitting asset sales or is there any more color I guess that you guys can provide at this point on the process either on maybe timing assets that are on the market or even kind of unexpected proceed.
It's number.
Yeah.
Again, I put them into two buckets as we talked about.
Over the last few months and.
Environment like this you really need right assets for the for this market. So we've been mostly focused on.
[music].
Override mineral type structure as well water.
JV structures.
And really appealing to a yield base investor who is not necessarily completely.
Energy focus maybe looking for yield in a world without yield.
So we've been progressing those over the last few months, obviously it was a tough few months in there and.
Where we are now and given the outlook in terms of free cash flow and maintaining.
Maintenance capital program is quite compelling it helps in our discussions with some of these potential buyers because they could see are you have the.
Wherewithal and the staying power to execute your plan and really deliver the underlying value proposition somebody structure. So.
I think thats resonated quite well and we've kept those discussions going and so hard to pinpoint in timing, but I think we're making good progress on their overall, we came into this year with a target for $3 million to $400 million of asset monetization proceeds more broadly we're still focused on that number.
I think.
We still have a good path towards it we are also monitoring more of your classic working interest sales.
As well.
Non op assets, some non core assets.
Delaware in Eagle Ford, they're probably going to take a little bit more time to play out we're not going to force anything in the market, but I think about those is.
Our Ranger assets for your call in Southern Midland Basin that were out with a package in late 2018.
Things were going extremely well and then December of 18 happened and hit pause, but we kept in touch with the lead bidders.
Through that time and as prices recovered we were in a position to move very quickly and get something done in spring of 19. So.
As I think about it basically having a lot of ways to be right.
Yeah.
Got it thanks.
Yes.
And our next question will come from Neal Dingmann with Trust Securities. Please go ahead.
My first question right Joe for you or Jim is just around your debt you guys and hit around this but you guys certainly did a nice chartered you've mentioned her prepared remarks about improving that organic free cash flow that probably will need something maybe a bigger boost as you mentioned just on the last comment about maybe doing some asset monetizations or my question lean more towards your bonds.
For you or Jim do you believe that that is the credit market do you think now where do you think by the ended the year would be opened for another side of refinancing or some type of transaction that would decrease or for a good maturities made it certainly appears pricing, but I just again don't have a good luck into that credit market as you all it.
I'm sorry go ahead Jim.
Yes, I think the kind of the first point I could lead with deal is our nearest maturities in 2023 and.
So obviously, we have watched carefully is as bond prices traded down.
In the second quarter, we also watch them trade up materially as commodity prices improved you're starting to see generally.
You know transactions start to open up here in the third quarter and.
Again, I think our focus is going to be on how do we reduce leverage.
Through the RBL with free cash flow and the selected transactions Joe described.
Joe any any kind of other high level point, you would want to add to that.
Again from a high level, Neil things have moved to.
Great deal and just last couple of months and I characterize it as our opportunity set is expanded quite a bit and doesn't mean that everything has a.
The highest probability of success, but theres.
Opportunities in both public and private capital markets that.
We see out there that where.
We have been investigating and continue to work pretty hard so I think theres certainly signs of thawing and I think you overlay that on the asset base.
And what we've been able to deliver and show here today in terms of the go forward plan will only help that.
Very good that second question I think for Joe for you or Jeff around the operational plans I'm. Just wondering you mentioned youre able to exceed what she would like to have are forecast to be the optimal pad economics, given somewhat of a constraint on maintenance Capex you, obviously still are done a great job.
You can tell by you know just the the return can margins a the improvements that you all went through I'm, just wondering again, but just sort of.
Rational spending that you all in most industry is facing does that impact you know what you're thinking on optimal pad design.
Yeah that that's actually and outstanding question that our development philosophy is pretty much remained unchanged. So that we are still committed to large larger or at least full scale development I'm in the Delaware and in the Midland anywhere where you have multiple target.
Yes.
Both vertically and laterally.
We have had some very.
Extremely beneficial and highly technical information that we combined the two.
Geologic models in our predictive forecasting that gives us some some very interesting insights into some of the areas that may not need to be co developed immediately with other zones and so at least it allows you to have a little bit of flexibility if you choose.
To either way can come back in certain zones.
Which is not.
Yes, the standard normally the vast majority of everything needs to be it's more beneficial if you get it when you're out there the first time.
But it does give us some additional flexibility.
So what we've been able to do.
Is put together a program for the back half of 2020 and into 2021.
It's really sticks to our guns as far as optimizing.
The development program on each.
Drilling units that we have in the portfolio.
And and optimize both a recovery and the profitability from there so.
This this little bit of a break where we weren't doing as much drilling and completion of the wells.
Given us is tremendous opportunity due to redouble our efforts on what types of programs that we can put in place and how can we ascertain even more clearly the correct spacing in stacking and parent child relationships. So we have really continue to make tremendous progress in those areas, but I do.
I don't see it as a detriment at all I see it does.
Just to repeat renewed commitment to what we're doing before but even better than what we're doing a couple of months ago.
Great detail state Thanks Doctor.
And our next question will come from Derrick Whitfield with Stifel. Please go ahead.
Thanks, Good morning on Great update.
Perhaps.
Again, and on the capital cost side, but with dealer Jeff.
How should we think about the durability of your low cost improvements that you outlined on page 11 in a normalized oil price environment.
And I think it are you, saying to us if oil goes back up with these costs change or if oil kind of hangs in there where it is right now.
Is that kind of the ballpark.
Yes, Jeff Let me, let me frame it this way so when you when you think about.
Let's just take you're assuming your synergy target for the Permian.
For 2019 in the Eagle Ford really.
29 team how much of the spread between then and now a structural versus market.
Great. Okay, yeah, thanks for that clarification.
But the nice thing about it is if you think about where we were well let me give you. The short answer first the majority of the improvements that we've seen on the cost side have been structural.
We have seen some reduction in some of the vendor partnerships that we've had to some extent some of the ancillary things such as fuel and then there's some big ticket items are saying just come down a lot.
But really.
Their efficiencies their best practices in their design changes that come into it the did a large scale.
Things such as you know that the day rates the pressure pumping, which are the key primary cost drivers of the DMC.
I have remained relatively similar from where we finished the year in 2019 and began the year in 2020, so that that first quarter.
Blue line on page 11 is a pretty good indicator of.
Structural changes that we've been able to put in place.
The second half of 20 incorporates additional opportunities that we have to drop down.
A portion of which would be vendor price reductions in our partners, but again the majority of those are structural changes relative to just doing things are better and getting the same or better well for less money.
Great. That's very helpful. And then Jeff just stand with you on on page 12.
Both your Midland and your Delaware Co development projects are performing exceptionally well are they in your view representative of what you can attain in their respective areas on a go forward basis, and maybe just one perhaps tacked on what the Delaware.
What do you attribute to the strong outperformance versus the previous unbounded results.
Yeah that again, that's the $1 billion question right, but I believe very strongly that these are representative certainly they're in good geologic areas and all rock is not created equal. So then when we look at.
Each.
Opportunistic development program. So we look at each development scenario independently of course, we use data from everywhere, but one size does not fit all especially when you're looking at multiple flow units.
We took advantage of.
Some excellent work that legacy Carrizo had done on that what we call. The six which was a very highly technical assessment of.
Multiple zones with Microseismic, So we do.
We take a look at how the fracs propagate within the rock and how in relation to the other existing wells and new wells.
And we were able to leverage that learnings and put it in to the Delaware development in the Dorothy Samsung.
And essentially that they gave us clarity on the appropriate spacing and stacking and prove that we were able to go in.
And have exceptionally good performance.
With a high degree of certainty on the what the results were going to be.
Coupled with the you know the reduction in the cost side means of profitability of the project.
As even been three months ago, much less six or nine months ago.
So that that is definitely an opportunity to perhaps to have us continue to repeat that it's a minor subset. So it's not like we've gone out and drilled 50, or 60 or 70 wells, but it certainly very encouraging.
Set of information, that's actually prove and on both the costs in the production side.
And in the Midland Basin, the Wild Horse project.
There are some.
Very similar items that we put into place for that the Duncan Horton rights that were also captured.
In the Delaware project, obviously, a different basin and so we were able to.
Again make a fit for purpose development program.
But if you think about that you know that's a nine well development program, where we had existing bounded wells, partially bounded meaning we had some parent wells.
Proximal on one side of some of these new wells that we put into place.
And the other interesting thing is if you look at the Red line, which is that the dunking unit eight to 21 age which is the Wolfcamp B wells.
That is an extremely well performing wolfcamp, b, well and and so again it is it a guarantee that.
That will be able to do this consistently everywhere.
I sure hope, so, but I wouldn't I wouldn't stick my neck out probably that bar.
But is it representative of all the learnings and efforts are that the technology group and our our ease of use of put in a along with.
Marrying it up to the completion group and DMZ.
It absolutely is representative of.
What our goals or as far as improved well performance.
That's helpful, Jeff well done guys.
Thanks, Sir.
The next question will come from Brian Downey with Citigroup.
Ahead.
Good morning, Thanks for taking the questions I guess, a follow up one on some of the monetization questions is there anything within your asset package, where you believe there's a very large experienced positive tests up between the potential value you can get Yankee market and what valuation credit you're currently getting on the credit facility, Yeah I'm assuming that's.
Baked into the list you laid out show, but but curious if there's anything in particular.
[laughter].
Yeah again, I think in this environment, it's going to be certainly pinned on any of the the overall type structures and any of the water infrastructure will give.
Not only a inflow of proceeds, but but also a credit enhancing outcome.
Got it and then I.
I guess, we spend a a lot of time I'm talking on the capital front into next year I'm just curious if there's anything additional on the Ela, we are and and so.
Other initiatives that you've undertaken at that they could be under appreciated as we as we think about those cost in the in the 21.
And then I'm glad to answer that.
The question my phone was cutting out a little bit so I believe that what you're asking about is how we've been able to to drop down the operating expenses and then how does that translate into it into 2021.
So I'll just add to.
Yeah, I mean, if there's anything you know fps or chemicals or anything like that for next year.
Yep, Yeah, great that you're exactly right those are.
They will be Nate, we will be able to maintain very strong operational expense.
Going forward into the back half of 2020 and 2021.
And this is.
This is really had a terrific example of.
[music] teams coming together and really assimilating and committing to.
Being together and the new company so whether its.
Best practices on on how we're drilling out wells are flowing back wells in the capital side or a chemical management and best practices on how we lift the wells, whether its gas lift rod pump or natural flow when should we put the tubulars and all those kinds of things.
It really is a remarkable if you think of the circumstances.
Oh, let's combine the company's in December adding a couple of months together and then having to essentially separate to some extent from the Kogas 19.
It's really been a wonderful commitment from everybody to try to make these things happen. So we've got pure sure being yes, the run times of over a year. So if you think about that we we put these submersible pumps down in the in the wells.
We monitor them, we take care of them and those pumps can run for over a year on the average runtime which of course helps you from consistent production not having you shut the wells and not having to spend the cost of of working them over.
And then if you look at some of the larger scale items on.
Field electrification, where we're getting ready to rid of some of the the diesel generated power. We're looking at and have improved our water recycling capacities and our ability to move water all that matches up extremely well with the BSG and sustainability goals at the company has.
As as well as simultaneously I'm dropping our operating expense down to up to an extremely low level and it's going to be consistent 2021 should be very very solid from an operating expense perspective.
I appreciate it.
And once again, if you would like Jeffs question. Please press Star then one.
And the next question will come from real Thompson with Barclays. Please go ahead.
Hey, good morning, maybe for Jim It sounds like the impact from working capital is behind you and just to make sure should we should we assume accrued capex will be more in line with cash Capex and thank you.
Yeah, Thanks, well that's a good question obviously.
You know second quarter.
We've been very focused on our net working capital position at all I'll go into a little bit of detail here.
You know we focused clearly because we saw the rapid drop in commodity prices that impacted revenues very quickly in March. We also reacted to that fall by reducing our capital program. There was a short term lag in that to safely inappropriate.
We are shut down if you will and that took us into early may so that that timing lag created the issue for us in second quarter that we're working through.
As we look at the second half the 2020 and 2021 to your point, we're realizing the benefits of improved realized prices.
We've seen the lower costs and synergy achievements, we talked about throughout the call and this was pretty evident to us in July where we saw materially higher payments that we that we realized in April and May we we saw probably a plus or minus 50% decrease from.
Our February oil and gas receipts.
Into too.
Late June and by July we were seeing more about 70% increase in that you know due to both prices differentials and such and that really has a compounding effect on current assets versus current liabilities. You know dependent that you mentioned, we do anticipate in third quarter.
Given the higher prices the completion of the one Q unwind and the modified development plans that we have in the second half. The 20 couple other quick high level points on working capital.
Some of some of the liabilities are less sensitive to drilling and activity levels. You know the agreed senior note interest the semi annual payments were in the June 30 numbers.
You also have noncash working capital numbers.
At June 30 that was probably a on a negative working capital amount over 30 million bogs due to.
The accounting treatment for operating leases in a aro, which as I said are noncash and then we also were wrapping up or some other onetime merger payments. So you know as we looked at it I think it's a much different picture than just current assets versus current liabilities I think we'll be positively impacted by.
Hi, increasing receivables and the reduced activity levels.
You know that all ties into the free cash flow palm common and the ability to reduce the RBL balance throughout the remainder of the year, Joe I don't know if you have anything else to add on that.
Yeah, I think there's a lot of good detail there, but I think in summary, as we get passed the second quarter. Here. You know you are going to start seeing the accrued versus cash capex.
A line and you know the.
Accrued free cash flow and actual cash free cash flow.
Doing similar things.
Okay. That's incredibly helpful color and then and then in terms of hedging correct me, if I'm wrong, but I got to interpret your comment that you guys. Do you want seem to seem to want some exposure to read is improving strip and 2021. So you just help me understand how how you balance kind of getting exposure to improving proving toward curve.
And then how the borrowing base might as well.
Much coverage you want in 2021.
Yeah, Great Great question I'll start and then Jochen can help complement the answer.
Yeah, historically, we have tried to hedge and have been hedged greater than 60% within a calendar year as we looked into 2021, we saw kind of an increased importance on supporting free cash flow generation. So we we started earlier on 2021 and I. Thank you.
You'll see us get to target levels sooner.
We looked really starting in the April may timeframe, we liked natural gas and we've hedged probably you know two thirds of 2021. We then started to work our way into an NGL position, we still we're comfortable with where.
They are W.T.I., an oil was so we paused and waited on improvement.
We saw brands and Emmy H. move up closer to the $40 level. So we we put some hedges in there and then within the last several weeks, we saw W. T. I break through $40 and that is an impactful level for us we started doing swaps in the 42.
50 range.
Costless collars and the 40 by 45 range to allow price participation and so the goal will be.
So really you know within the third quarter be closer to 50% hedged depending on how the market moves and again back to our traditional 60% level by the ended the year and I think we'll focus on swaps and two way collars for price participation.
And my my belief is that at those levels that we've hedged it it will likely be accretive or to bank price cases, so I'll pause there and see if Joe has any other color or to add.
Yeah again lot lot of good detail.
Yeah again from a high level, we're looking to protect free cash flow, we've laid out a plan $40 flat that's quite compelling. So we have a lot of leverage to the upside so want to protect free cash flow and open up some upside where where we can.
Yeah as it relates to to the borrowing base and bank cases, you know, it's a consideration, but it's not going to be a key driver. How we think about our hedging policy, we do get benefits, but you know look back to our recent Redetermination spring.
You know on paper, you said well look at this huge benefit, but the fact matter as the banks typically roll forward six months from the date of every termination. So the only credit we got for hedging was it was passed November of 2020 at that point. So you know there is some impact there, but it can't be.
Keith you know this whole driver it has to be more philosophical in terms of we're protecting free cash flows for long term.
Alright, thank you.
And this will conclude our question and answer session I'd like to turn back over to Joe Gatto for any closing remarks.
Thank you call. Thanks, everyone for joining and we'll look forward to updating you on our progress over the next few months.
Great to.
And the conference has now concluded. Thank you for attending today's presentation. You may now disconnect your lines at this time.