Callon Petroleum Company

Good day and welcome to the Callen Petroleum Company's 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, and a replay of the call will be archived on the company's website for approximately one year. I would now like to turn the call over to Mark Brewer, Director of Investor Relations, for opening remarks. Please go ahead, sir.

Thank you, Cole. Good morning, everyone, and thank you for taking the time to join our conference call. With me this morning are Joe Gatto, our President and Chief Executive Officer, Dr. Jeff Ballmer, our Chief Operating Officer, and Jim Alm, our Chief Financial Officer. During our prepared remarks, we'll be referencing the earnings results presentation we posted yesterday afternoon to our website. So I encourage everyone to download the presentation if you haven't already. You can find the slides on our events and presentations page located within the investor section of our website at www.calend.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 that refer to estimates and plans. Actual results could differ materially due to the factors noted on these slides and in our periodic FDC filings. We'll also refer to some non-GAAP financial measures today, which we believe help to facilitate comparisons across periods and with our peers. For any non-GAAP measures we reference, we provide a reconciliation to the nearest corresponding GAAP measure. You may find these reconciliations in the appendix to the presentation slides and in our earnings press release, both of which are available on our website. Following our prepared remarks, we'll open the call for Q&A. With that, I'd like to turn the call over to Joe Gatto. Joe?

Thanks, Mark. Our team posted impressive numbers for the second quarter amidst a very challenging commodity environment in our rapid change in our daily work routines. Development and operating costs saw meaningful declines. Synergy realization was ahead of targets and ahead of schedule. And importantly, Calend was 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 109,000 VOE per day on operational CapEx of just 85 million. In addition, our lease operating expense dropped 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 right-size the combined organization and reductions in compensation for our leadership team and board of directors, we've reached an all-time low in cash G&A expense per BOE of 69 cents per BOE and an all-in total cash G&A, inclusive of capitalized costs. of $1.37 per BOE for the second quarter. In aggregate, our total operating costs plus full cash G&A were under $9.60 per BOE, yet another reflection of the benefits of a scaled operating model and the focus of the entire organization in 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 IRRs of $35 to $40 per barrel. The added ability to pivot based on varying 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 and the structural well cost savings we have delivered underpins our outlook for durable cash flow generation as we are able to reduce our 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 basin exposure that provides pricing point optionality and a natural hedge against unforeseen offtake disruptions or pricing point dislocations that we've seen occur on several occasions in recent years. Moving to slide six, a few comments here. This year has certainly forced 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 were undertaking in response to rapidly changing market conditions, including a complete halt 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 Eagleford and Permian after investments made during the first few months of the year. Beginning later this month, we will return to a reduced level of activity with a focus on working through that duct 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 plan for the second half dovetails with our 2021 outlook for approximately $400 million of 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 100,000 BOE per day of projected average annual volumes for 2020. All the free cash flow we generate over this period of six quarters, which we currently estimate to be roughly $150 million, a $40 per barrel flat WTI, will be dedicated to credit facility repayment and complement potential proceeds from our asset monetization initiatives. While 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 usage, and meaningful changes to our governance and compensation policies. Last year, we premiered the sustainability portion of our corporate website 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 the initiatives are advanced in partnership with our investors over time. Moving to slide eight, much has been said about the need to right-size the G&A burden across the industry. We are firmly aligned with that sentiment and effected a meaningful reduction in our cost structure through the consolidation transaction with Carrizo. We've 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. The left-hand chart captures a variety of payroll, non-payroll, and related synergy cost realizations, ultimately leading to projected cash G&A reduction, inclusive of our capitalized costs of $75 million over 2019. These are changes that we expect to endure as they are largely structural in nature and represent longer-term adjustments to Callan's cost structure. At this point, I'm going to turn the call over to Jeff to discuss operations.

Great. Thanks, Joe. Good morning, everybody. Our 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 as part of our increased focus on sustainability. And, of course, we're on slide nine right now. Total LOE, inclusive of workovers, is down over 10% from the pro forma quarterly run rate in 2019, coming in at roughly $50 million in the second quarter. Those savings really come from five primary drivers, our push towards field electrification, expanding our in-house chemical management process, improved electric submersible pumps, that management we call those ESPs, expansion and optimization of our water disposal network and then overall just improved field oversight which takes into account things like compressor optimization work over 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 the 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 Callen, our investors, and the communities that we work in. On slide 10, the progress we've made in the Delaware over the past 18 months is simply phenomenal. Costs are down close to $400 per lateral foot, a 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, in turn, are increasing savings beyond the simple efficiency uptick from the multi-well, multi-pad based development. While we've seen some softening of costs from vendors to some extent, the vast majority of our gains have come from improved practices and beneficial well-designed changes. And of course, we'll employ these practices on Delaware, Midland, Eagleford drilling and completions in the second half of the year. On the next slide, slide 11, I think 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 in 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 more robust than the Delaware, reflecting a 17% improvement from our previous figure. The right-hand portion of the slide captures some of the primary drivers behind the capital efficiency improvements and are 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-well Duncan Horton Wright project, which is a Midland Basin project that was placed on production at Wild Horse in June, has significantly outperformed the offset four-well pad from 2019 in the same area, despite having multiple partially bound wells in this new development. And then in the lower chart, the Dorothy Sampson seven-well pad in Eastern Reeves County that we brought on earlier in the quarter, have performed quite well against the original Crowley-St. Clair offset wells that compose the project that we have in the past referred to as the six. The partially bound Wolf Camp A and B wells in this area on this development are performing on par or ahead of the unbounded offsets. That wraps up the operations slides, 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 be desired our unhedged oil realizations were down 55 percent the duplicative impact of an oil price war and a global pandemic that shut down economies across the globe was evident in our operating revenues for the quarter fortunately we have always maintained a strong hedge book and we're able to restructure our hedges in march and ended up with an almost $100 million 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 Eagleford during the quarter, but have since rolled those back into our MEH 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 half of the year. As is shown on the slide on page 13, as we look forward into third quarter, both WAHA and NGL pricing has improved, and we believe that oil realizations are likely to rebound north to roughly 95 percent of the WTI 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 Brent and MEH-based instruments as we begin utilizing our new firm transportation and associated term deals. On slide 15, I mentioned that as Joe described earlier, we now see a path to nearly $150 million in free cash flow over the next six quarters. This, along with the 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 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 expect 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 for the majority of our cost categories, as we believe this provides a better perspective on expense run rates versus derived per unit guidance measures. While it's a bit too early to provide the full range of expectations 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 mild declines in production from now until the early portion of next year, our activity levels in 2021 should drive a 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 Q&A, I just wanted to take a second and commend our team who's worked extremely hard to endure our integration process. It proved to be a success early time here. Again, some backdrop has been completely changed since we charted our course as a newly combined company earlier in the year. Results in our outlook provide very tangible evidence of that success. But we also recognize it's been a difficult few months for not only the people of Callen, but our nation as a whole. We will continue to do what's necessary to protect our employees, partners in the communities of Houston, Midland, and South Texas. These ongoing efforts are squarely aligned with the interests of shareholders and Calend's improving outlook as we navigate this period of uncertainty for the industry. With that, Cole, I'd like to open the line for Q&A.

Thank you. And we will now begin the question and answer session. If you would like to ask a question, please press stars and one. If you would like to withdraw your question, please press stars and two. We kindly ask that you please limit yourself to one question and one follow-up. And our first question today will come from Brad Heffern with RBC Capital Markets. Please go ahead.

Hey, good morning, everyone. Thanks for taking the questions. I wanted to start off with just a question on capital allocation across the area. So you made a lot of progress in terms of well costs in the Midland and the Delaware and some in the Eagleford, but the costs there have stayed more flat than the other areas. So I'm just curious if that changes how you think about capital allocation to the Eagleford and if we could see a sort of larger portion going to the other areas than maybe we have in the past.

I guess, Brad, from a high level, and let me start out and get Jeff's perspective here as well, but Eagleford, you know, I think started with a very compelling portfolio. cost structure going into the combined entity. They had firmly moved as Carrizo into larger scale development, utilizing central processing facilities, had really gotten into manufacturing mode in a lot of ways, a great example of where we wanted to take the Permian. And we had a great tangible anecdote there in the Eagleford. So we will continue to drive down costs there with best practices and some of the things that Jeff talked about. But overall, it fits very well within to 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 is 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 Delaware into the Eagle Fur, 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 can give sort of for the fall redetermination? I'm just thinking about it from the standpoint of it seems like the PDP base is likely going to be lower based on the plan, but then at the same time, you know, theoretically the price deck could be higher. So any thoughts about how those two things sort of interplay?

Yeah, Jim, I'll try. Yeah, I'll take that. And then if you want to, I'll kind of pitch it back to you. You know, the focus that we had during the spring redetermination was on adequate liquidity and an appropriate runway to execute on the deleveraging plans we had. And we did that really in a period of extremely heightened volatility in late April. As we look back on that redetermination, kind of the statistics show over 85% of oil-weighted borrowers saw a greater than 25% decline in their borrowing base. So as we look into 4Q to address your question specifically, I think it's probably a little bit too early to make a prediction on what might happen in November. You know, we went through that in late April, and there was a day that crude went negative. So I'm reluctant to make an absolute prediction for you, but I will say I think there are some real positives that we have heading into that redetermination. The generation of free cash flow in 2020, and as Joe mentioned, the visible path for sustainability the banks recognized. establishing a post-merger track record of the operational successes will be helpful to us. The cost improvement and the synergy realizations 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 You know, we are actively hedging through 2021, and that should give some benefit in the upcoming redetermination. The last thing I would kind of say is that there was, you know, kind of broader sector volatility as well. Hopefully a lot of that, you know, has been dealt with in the first half of 2020, and, you know, we'll be prepared for the redetermination. Joe, anything you would add to that?

Yeah, I think just one quick point. I think you brought up the PDP volumes, and one thing to take into consideration with that, we went into our redetermination with a reserve report at the end of the first quarter. We brought a fair amount of wells on after that, as well as 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're included in that reserve report, they do get risked for early time performance. So, you know, with reduction in activity, you might say, well, maybe PDP is going to be a bit less. But when you take into those factors, it's not as simple as that. But, you know, you have to take it all as a combined outlook. And a lot of the points that Jim brought up are equally as important.

Okay, thank you.

And our next question will come from Gabe Dow with Cowan. Please go ahead.

Hey, good morning, guys. Thanks for all the color thus far. I was hoping maybe we could start with the $400 million in operational CapEx for 2021. Just curious, I guess, how many ducks does that plan contemplate you guys drawing down throughout the year and then I guess how does that maintenance capital number change as you move throughout 21 and entering 2022?

Jeff, you want to kick us off there?

Sure. The majority of the back half of the 2020 program will in part be focused on reducing the amount of duct inventory that we have on hand right now. So we've got about 70. We do have 70 ducts split about half in the Eagleford and then half in the Permian. So we'll be working off a number of those projects relatively quickly. When we hit here in the next month or so, we're going to resume some drilling operations and, you know, continue to build up at least a modest duck inventory. The one completion crew, although it's going to be, and I say one, it means the about an average of one into 2021, we'll be working in both basins. And we'll be able to, for the most part, keep up with the inventory that we'll put together from the two to three drilling rigs.

Thanks, Jeff. That's helpful.

And then just to follow up, Joe, maybe just hitting asset sales, 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 an expected proceeds number?

Yeah. Again, I put them into two buckets, as we talked about over the last few months. In an environment like this, you really need the right assets for this market. So we've been mostly focused on override mineral-type structure as well as water JV structures and really appealing to a yield-based investor who's not necessarily completely energy-focused, maybe looking for yield in a world without yield. So we've been progressing those over the last few months. Obviously, there's a tough few months in there and Where we are now, I mean, given the outlook in terms of free cash flow and maintaining a maintenance capital program, it's quite compelling. It helps in our discussions with some of these potential buyers because they could see, all right, you have the wherewithal and the staying power to execute your plan and really deliver the underlying value proposition in some of these structures. So I think that's resonated quite well, and we've kept those discussions going. It's hard to pinpoint timing, but I think we're making good progress on there. Overall, we came into this year with a target for $300 million to $400 million of asset monetization proceeds more broadly. We are 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, some non-op assets, some non-core assets in the Delaware and Eagle Fork. you know, 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, you know, I think about those as, you know, our ranger assets, if you recall, in Southern Midland Basin, that we were out with a package in late 2018. Things were going extremely well. And then December of 18 happened and, you know, 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, it's having a lot of ways to be right. Got it. Thanks, Jeff.

And our next question will come from Neil Digman with Truth Securities. Please go ahead.

Morning, all. My first question, probably, Joe, for you or Jim, and just around your debt, you guys have hit around this, but you guys certainly are doing a nice job. You've mentioned prepared remarks about improving the 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. My question would be more towards your bonds. You know, for you or Jim, do you believe that the credit market you think now or do you think by the end of the year would be open for another shot at refinancing or some type of transaction that would decrease or shore up your maturities? I mean, it certainly appears as pricing, but I just, again, don't have a good look into that credit market as you all would.

Go ahead, Jim.

Yeah, I think the kind of the first point I would lead with, Neil, is our nearest maturity is in 2023. And so obviously we have watched carefully as bond prices traded down in the second quarter. We also watched 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, you know, 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 kind of other high-level points you would want to add to that?

I think, again, from a high level, Neil, things have moved a a great deal in this last couple of months. And I characterize it as our opportunities that have expanded quite a bit. It doesn't mean that everything has the highest probability of success, but there's opportunities in both public and private capital markets that we see out there that we have been investigating and continue to work pretty hard. So I think there's 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. The second question I think for Joe, for you or Jeff around the operational plans, I'm just wondering, you mentioned are you all able to achieve what you would like to have or forecast to be the optimal pad economics given somewhat of a constraint on maintenance capex? still are doing a great job. You can tell by, you know, just the returns, the margins, the improvements that you all went through. I'm just wondering, you know, again, the sort of, you know, rational spending that you all and most industry is facing, does that impact, you know, what you're thinking on optimal pad design?

Yeah, that's actually an outstanding question. Our development philosophy has pretty much remained unchanged so that, We are still committed to large or at least full-scale developments in the Delaware and in the Midland, anywhere where you have multiple targets, both vertically and laterally. We have had some very extremely beneficial and highly technical information that we've combined the two geologic models and our predictive forecasting that gives us some very interesting insight 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 wait and come back in certain zones, which is not necessarily 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, which 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 the recovery and the profitability from there. So this little bit of a break where we weren't doing as much drilling and completion of the wells has given us this tremendous opportunity 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 and stacking and parent-child relationships. So we really continue to make tremendous progress in those areas. But I don't see it as a detriment at all. I see it as just a renewed commitment to what we were doing before, but even better than what we were doing a couple months ago.

Great details.

Thanks, Doctor.

And our next question will come from Derek Whitfield with Stiefel. Please go ahead.

Thanks. Good morning, all, and great update. Perhaps beginning on the capital cost side with you or Jeff, how should we think about the durability of your oil cost improvements that you outline on page 11 in a normalized oil price environment?

And I think, are you saying if oil goes back up, would these costs change, or if oil kind of hangs in there where it is right now, is Is that kind of the ballpark?

Yeah, Jeff, let me frame it this way. So when you think about, let's just take your, assuming your synergy target for the Permian for 2019 and the Eagle for really 2019, how much of the spread between then and now is structural versus market?

Great. Okay. Yep. Thanks for that clarification. 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, you know, fuel, and there's some big ticket items. Sand has come down a lot. But really, their efficiencies, their best practices, and their design changes that come into it, the large-scale things such as the day rates, the pressure pumping, which are the two primary cost drivers of the DNC, have remained relatively similar from where we finished the year in 2019 and began the year in 2020. So 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, you know, vendor price reductions in our partners. But again, the majority of those are structural changes relative to just doing things better and getting the same or better well for less money.

Great. That's very helpful. And then, Jeff, just to stand with you 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 those respective areas on a go-forward basis? And maybe just one perhaps tack on with the Delaware, what do you attribute to the strong outperformance versus the previous unbounded results?

Yeah, again, that's the billion-dollar question, right? I believe very strongly that these are representative, certainly that 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 what we call the six, which was a very highly technical assessment of multiple zones with micro seismics. We take a look at how the fracks 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 into the Delaware development and the Dorothy-Samsom. And essentially, that gave us clarity on the appropriate spacing and stacking and proved that we were able to go in and have exceptionally good performance with a high degree of certainty on what the results were going to be, coupled with the reduction in the cost side means the profitability of these projects has even been three months ago, much less six or nine months ago. So that is definitely an opportunity 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's certainly a very encouraging opportunity set of information that's actually proven on both the cost and the production side. And in the Midland Basin, the wild horse project, there are some very similar items that we put into place for 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 the Duncan Unit A221H, which is the Wolf Camp B well, that is an extremely well-performing Wolf Camp B well. And so it Again, is it a guarantee that we'll be able to do this consistently everywhere? I sure hope so, but I wouldn't stick my neck out probably that far. But is it representative of all the learnings and efforts that the technology group and our REs and GOs have put in, along with marrying it up to the completions group and DNC? It absolutely is representative of... what our goals were as far as improving the well performance.

That's helpful, Jeff. Well done, guys.

Thanks, sir.

And the next question will come from Brian Downey with Citigroup. Please go ahead.

Good morning. Thanks for taking the questions. I guess I'll follow up one on some of the monetization questions. Is there anything within your asset package where you believe there's a very large conspiratorial positive delta between the potential value you can get in the A&D market and what valuation credit you're currently getting on the credit facility? I'm assuming that's baked into the list you laid out, Joe, but curious if there's anything in particular that you can comment on.

Yeah, again, I think in this environment, it's going to be certainly pinned on any of the override type structures and any of the water infrastructure will give not only an inflow of proceeds, but also a credit enhancing outcome.

Got it. And then we, I guess we spent a lot of time discussing talking on the capital front into next year. I'm just curious if there's anything additional on the LOE and the initiatives that you've undertaken that could be underappreciated as we think about those costs in the 21.

And 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 drop down the operating expenses and then how does that translate into 2021? So I'll go with that.

Yeah, I mean, if there's anything, you know, ESPs or chemicals or anything like that for next year.

Yep, yeah, great. You're exactly right. Those are – they will be – we will be able to maintain very strong operational expense rates going forward into the back half of 2020 and 2021. And this is really a terrific example of two teams coming together and really assimilating and committing to, you know, being together in the new company. So whether it's best practices on how we're drilling out wells or flowing back wells on the capital side, or chemical management and best practices on how we lift the wells, whether it's gas lift, rod pump, or natural flow, when should we put the tubulars in, all those kinds of things. It really is a remarkable, if you think of the circumstances of us combining the companies in December, having a couple months together and then having to, you know, essentially separate to some extent from the COVID-19, it's really been a wonderful commitment from everybody to try to make these things happen. So, we've got pure being ESP run times of over a year. So, if you think about that, we put these submersible pumps down in the wells and 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 to shut the wells in, not having to spend the cost of working them over. And then if you look at some of the larger scale items on field electrification, where we're getting rid of some of 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 ESG and sustainability goals that the company has, as well as simultaneously dropping our operating expense down 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 to ask a question, please press stars and one. And the next question will come from Will Thompson with Barclays. Please go ahead.

Hey, good morning. Maybe for Jim, it sounds like the impact from working capital is behind you. Just to make sure, should we assume accrued CapEx would be more aligned with cash CapEx and 3Q?

Yeah, thanks, Will. That's a good question. Obviously, You know, second quarter, we've been very focused on our net working capital position, and 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, you know, reducing our capital program. There was a short-term lag in that to safely and appropriately reduce shut down, if you will, and that took us into early May. So that timing lag created the issue for us in second quarter that we're working through. As we look at the second half of 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've talked about throughout the call. And this was pretty evident to us in July that where we saw materially higher payments that we realized in April and May. We saw probably a plus or minus 50% decrease from our February oil and gas receipts into, you know, late June. And by July, we were seeing more of a 70% increase. And that's, you know, due to both prices, differentials and such. And that really has a compounding effect on current assets versus current liabilities. You know, the pivot that you mentioned, we do anticipate in third quarter, given the higher prices, the completion of the 1Q unwind, and the modified development plans that we have in the second half of 20. A couple other quick high-level points on working capital. Some of the liabilities are less sensitive to drilling and activity levels. You know, the accrued senior note interest, the semiannual payments were in the June 30 numbers. You also have non-cash working capital numbers at June 30. That was probably a negative working capital amount, over $30 million, due to the accounting treatment for operating leases and ARO, which, as I said, are non-cash. And then we also were wrapping up some of the one-time merger payments. You know, as we look 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 increasing receivables and the reduced activity levels. You know, that all ties into the free cash flow comment 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 past the second quarter here, you know, you are going to start seeing the accrued versus cash CapEx, you know, align and, you know, the accrued free cash flow and actual cash free cash flow, you know, doing similar things.

Okay. That's incredibly helpful, Carl. And then, and then, In terms of hedging, correct me if I'm wrong, but I guess I interpret your comment that you guys do want, seem to want some exposure to what is improving strip in 2021. So, you just tell me, understand how you balance kind of getting exposure to improving forward curve and then how the borrowing base plays a role in terms of how much coverage you want in 2021.

Yeah, great, great question. I'll start and then Joe can help complement the answer. You know, 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 started earlier on 2021, and I think you'll see us get to target levels sooner. We looked really starting in the April, May period, timeframe. Um, we liked natural gas, um, and we've had probably, you know, two thirds of, of 2021. We then started to work our way into an NGL position. Um, we still weren't comfortable with where WTI and oil was. So we, we paused and waited on improvement. Um, we saw Brent and MEH move up closer to the $40 level. So we, we put some hedges in there. And then within the last several weeks, we saw WTI break through $40, and that is an impactful level for us. We started doing swaps in the $42.50 range, costless collars in the $40 by $45 range to allow price participation. And so the goal will be to 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 end of the year. I think we'll focus on swaps and two-way collars for price participation. And my belief is that at those levels that we've hedged, it will likely be accretive to bank price cases. So I'll pause there and see if Joe has any other color to add.

Yeah, again, a lot of good detail there. Again, from a high level, we're looking to protect free cash flow. We've laid out a plan at $40 flat that is quite compelling, so we have a lot of leverage to the upside. So we want to protect free cash flow and open up some upside where we can. As it relates to the borrowing base and bank cases, it's a consideration, but it's not going to be a key driver of how we think about our hedging policy. We do get benefits, but look back to our recent redetermination this spring. You know, on paper, you said, well, look at this huge benefit. But the fact of the matter is the banks typically roll forward six months from the date of our determination. So the only credit we got for hedging was if it was past November of 2020 at that point. So, you know, there is some impact there, but it can't be a key, you know, the sole driver. It has to be more philosophical in terms of we're protecting free cash flows for long term.

All right. Thank you. And this will conclude our question and answer session. I'd like to turn the conference back over to Joe Gatto for any closing remarks.

Thank you, Cole. Thanks, everyone, for joining. And we'll look forward to updating you on our progress over the next few months.

Have a great day. And the conference is now concluded. Thank you for attending today's presentation. You may now disconnect your lines at this time.