Earthstone Energy Inc

F:BSC2

Earnings Call Transcript 2020-Q2

[Operator]

Good morning, and welcome to Earthstone Energy's Second Quarter 2020 Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. Joining us today from Earthstone are Robert Anderson, President and Chief Executive Officer; Mark Lumpkin, Executive Vice President and Chief Financial Officer; and Scott Thelander, Vice President of Finance. Mr. Thelander, you may begin.

[Scott Thelander, executive]

Thank you, and welcome to our second quarter conference call. Before we get started, I would like to remind you that today's call will contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 as amended, and Section 21E of the Securities Exchange Act of 1934 as amended. Although management believes these statements are based on reasonable expectations, they can give no assurance that they will prove to be correct. These statements are subject to certain risks, uncertainties and assumptions as described in the earnings announcement we released yesterday and in our 2019 annual report on Form 10-K and subsequent quarterly filings. These documents can be found in the Investors section of our website, www.earthstoneenergy.com. Should one or more of these risks materialize or should underlying assumptions prove incorrect, actual results may vary materially.

This conference call also includes references to certain non-GAAP financial measures, which include adjusted diluted shares, adjusted EBITDAX, adjusted net income, all-in cash costs, cash G&A and free cash flow. Reconciliations of these non-GAAP financial measures to the most directly comparable measure under GAAP are contained in our earnings announcement released yesterday.

Also, please note, information on this call speaks only as of today, August 6, 2020. Thus, any time-sensitive information may no longer be accurate at the time of any replay or transcript reading. A replay of today's call will be available via webcast by going to the Investors section of Earthstone's website and also by telephone replay. You can find information about how to access those on our earnings announcement released yesterday.

Today's call will begin with comments from Robert Anderson, our CEO, followed by remarks from our CFO, Mark Lumpkin, regarding financial measures and -- financial matters and performance and then some closing comments from Robert. I'll now turn the call over to Robert.

[Robert Anderson, executive]

Thank you, Scott, and good morning, everyone, and appreciate everyone's attendance for our call today. Thanks for making time to join us for our second quarter conference call.

In the midst of the current pandemic, we continue to take appropriate caution and maintain focus on keeping our personnel safe while continuing to efficiently manage our operations. Achieving our strong second quarter results in the face of this unprecedented oil price collapse and difficult operating environment is evidence of the resiliency of our business plan and the solid commitment of our people. Throughout these trying times, we have worked to quickly adjust to the rapidly changing conditions and align our costs with our business activity as well as preserve our strengths.

As we have discussed last quarter, and in any updates along the way, stating we would be free cash flow positive from the second quarter on for 2020, we had significant free cash flow of $35 million in this quarter. This was driven by several factors, including: limited capital expenditures in the quarter as we completed our drilling and completion program for the year; strong hedge position that delivered over $29 million of realizations; and significantly lower operating costs, partially as a result of our May shut-in and curtailment program, but also sustainable reductions.

Including the impact of our shut-in program, our average daily sales volume in the second quarter was 13,555 barrels of oil equivalent, or BOE, per day. Even with reduced volumes and a 44% drop in average realized price per BOE in the second quarter, our cost management efforts, combined with the strong hedge position, allowed us to generate higher quarter-over-quarter adjusted net income and adjusted EBITDAX. I suspect we are one of a very small group of our peers who can say that. We expect to generate substantial free cash flow throughout the balance of the year, which should result in a decreasing debt balance and help us achieve our target of being below 1x debt-to-EBITDAX for the year.

As we previously discussed, in response to the sharp decline in oil prices in April and very low forecasted May oil prices, we made the decision in late April to shut in the large majority of our operated production for the month of May, which resulted in approximately 60% of our total net production being shut in during May. With a forecast of significantly improved June oil prices, which ultimately were more than double our April and May oil price realizations, we returned to full production in June.

We had a very successful quarter in focusing on cost reductions, which saw us reduce total lease operating expense, or LOE, in the second quarter by 40% from the prior quarter. Despite reduced production volumes due to our shut-in program in May, our teams continued focus on cost reductions resulted in a 30% decrease in LOE per BOE in the second quarter to $4.53 versus $6.51 in the first quarter. This was the major driver of the overall 33% reduction in all-in cash costs during the quarter.

On a per-unit basis, our all-in cash costs went from near $13 per BOE in the first quarter to near $10 per BOE in the second quarter for a total 22% reduction. This is all-in cash cost, folks, which includes operating costs, corporate G&A costs and all of our interest costs on our debt.

To dive a little deeper into how we achieved the 40% decrease in LOE, let me outline some of the key factors.

First, as much of our peers have done, we were successful in negotiating price reductions with vendors across the broad range of our lease operating expenses from chemicals to maintenance rigs, saltwater disposal contracts and compression costs.

Second, we are benefiting from our long-term practice of spending a little more money as we go repairing wells, facilities and associated equipment to reduce frequency of maintenance, which is resulting in a continued decrease in nonroutine LOE repair needs.

Third, workover repairs have trended down, resulting from our optimization of lift method, chemical program improvements and general approach of fixing things right the first time. The limited offset frac activity also reduced frac hit-related workover expenses.

Fourth, we have been successful in getting the utility companies to perform electrical upgrades sooner than scheduled, which has allowed us to eliminate generator usage on some of our newer locations.

Lastly, with limited drilling and completion activity, we have also been able to refocus our field employees towards lease maintenance, which has allowed us to reduce contractor labor.

All of these items and many other subtleties of operating were in progress as our team has a history of continually driving down costs. We will remain focused on continuing to reduce costs across the board as we expect the oil price environment that we have observed since late 2014, including increased volatility, to persist which only stresses the need to structure our business to be profitable across a much lower oil price range.

I'd really like to commend our operations team, which did a fantastic job of both shutting in production in May and bringing production back fully online in June while also achieving these cost reductions. For the first time in my career and our team's history, we had to tell our guys to produce as little as possible every single day. We executed this shut-in operations, and our field personnel did a great job of efficiently returning wells to production with little to no incremental expense and no adverse effects on our producers. Our wells have returned to their previous volumes with some wells producing at increased rates for a period of time. Plus, the 3 wells in Southeast Reagan County that were brought online in April, prior to the curtailments and were shut in during May, are now back online and have fully cleaned up and are performing well versus the type curve.

I mentioned, we concluded our 2020 drilling program in late May and released our contracted rig operating in the Midland Basin. So our planned capital expenditures are minimal for the balance of the year. Given that our program ended with 11 wells drilled but not completed, and with our ample liquidity, we have optionality on completion timing depending on market conditions.

With production return to full capacity, we have entered the second half of this year with expectations for no further drilling or completion activity this year. We can maintain approximately flat year-over-year production in 2020 compared to 2019. As a reminder, we recently updated our 2020 full year production guidance ranging from 13,000 to 14,000 BOE per day, which compares to 2019 full year average of 13,429 BOE per day.

Further, with our 11 drilled but uncompleted wells in Upton County, we intend to carefully monitor commodity pricing, appropriate service availability and service cost conditions to determine if it makes sense to bring in a completion crew later this year or wait until early next year. Depending on the timing, we anticipate the completion of those 11 wells would enable us to maintain similar year-over-year production for 2021 with only a modest capital program for the completions, which we currently estimate at around $30 million.

With that overview, I'll now turn the call over to Mark to review the financials. Have at it, Mark?

[Mark Lumpkin, executive]

Thank you, Robert. As we have in the past 2 consecutive quarters, I'd like to first discuss our cash position and our balance sheet. As Robert mentioned, we are pleased to have achieved our goal of generating substantial free cash flow in the quarter with a total of $35.1 million of free cash flow. As we referenced in our first quarter call, our plan was first to reduce our working capital deficit, which we calculate excluding derivatives. And we're able to do this by a little over $50 million during the second quarter and then to begin to pay down our revolver debt.

The borrowing base under our senior secured revolving facility, which was set in late March, remains unchanged at $275 million and should remain there until our regularly scheduled fall redetermination process.

Our outstanding borrowings under the credit facility at quarter end totaled $168.6 million, and we had $1.8 million in cash. With $106.4 million of unused borrowing capacity, that gave us approximately $108 million of liquidity at quarter end. I would note that as of July 31, we had paid down our revolver by $14.3 million compared to quarter end, reducing our debt balance now to about $154.3 million, and we do expect to apply free cash flow the remainder of the year primarily to pay down the revolver.

During the second quarter, our capital expenditures totaled $3.2 million, and year-to-date, we have spent $45 million of our annual 2020 capital budget of $50 million to $60 million. As Robert mentioned, we concluded our 2020 drilling program in May. So we anticipate minimal expenditures during the remainder of the year and will likely end up toward the low end of our guidance range.

Now looking at our second quarter income statement. Starting with the top line, revenues for the second quarter of 2020 were $21.7 million compared to $45.1 million in the first quarter. The decline was driven by a 54% decrease in oil revenues to $18.9 million, which made up about 87% of total revenues, and NGL revenues fell by 44% while natural gas revenues rose slightly.

Our average price in the second quarter for all 3 commodities was $17.56 per barrel of oil equivalent, which was down by nearly half of our average price during the first quarter. By commodity, our average realized price per crude oil in the second quarter was $23.56 per barrel. Natural gas averaged $0.83 per Mcf, and NGLs averaged $8.10 per barrel of oil equivalent.

From a production standpoint, our second quarter sales volumes averaged 13,555 barrels of oil equivalent per day, which was comprised of 65% oil, 18% natural gas and 17% natural gas liquids. As highlighted, this does include having curtailed about 60% of total production in May.

On the expense side, as Robert also highlighted, we did drive down our all-in cash costs from $12.92 per BOE in the first quarter to $10.11 per BOE in the second quarter. We achieved this through nearly $2 per BOE reduction in our lease operating expense to $4.52 per BOE for the quarter.

On the general and administrative side, we reduced our absolute cash G&A expense by about 7% versus the first quarter, which resulted in per-unit cash G&A expense of $3.34 per BOE. As you know, we reduced our cash G&A guidance in May to $15.5 million to $16.5 million for the full year and expect to be somewhere in that range, which at the bottom end, is a 25% reduction versus our initial full year plan.

In addition to some of the statements we articulated last quarter, we continue to focus on, and have had success, in reducing expenses really any and everywhere, including reduced usage of third party consultants, reducing vendor rates and managing our costs tightly.

From an income standpoint, we reported GAAP net loss in the second quarter of $35.9 million or $0.55 per share, which included a pretax unrealized loss of $50 million on our derivative contracts. Our adjusted net income was $12.8 million or $0.20 per diluted share -- adjusted diluted share for the second quarter. We reported adjusted EBITDAX of $39.8 million in the second quarter, which as Robert mentioned, is actually an increase quarter-over-quarter.

Now let me take a minute to update you on our commodity hedge results in the second quarter.

As highlighted, we realized $29.4 million gain on our commodity hedges for the quarter. This is largely reflective of our hedge position entering the quarter and are locking in some really nice gains on hedges when we made the decision to curtail production and did that when second quarter NYMEX prices were about at the lowest point. The hedge realizations also include a gain of about $5.7 million from an unwind of 1,000 barrels of oil a day for the second half of 2020.

We remain really well hedged for the balance of the year with an average of 6,500 barrels per day of oil swapped at a NYMEX price of $58.35, stepping down to 4,000 barrels a day for full year 2021 at a NYMEX price of $55.16 per barrel with basis hedges in place on similar volumes.

On the natural gas side, we have 7,000 MMBtu per day of swaps at a Henry Hub price of $2.85 for the second half of this year, stepping up to 8,000 MMBtus per day at a price of $2.71 for full year 2021 with basis hedges in place on the same volumes. Hedge remains a critical component of our financial strategy, and we expect to continue layering on hedges as we get more visibility around the resumption of our drilling and completion activity going forward.

Stepping back and looking at our expectations for full year 2020, we reinstated our production guidance in July, and we've reinstated LOE and production and ad valorem tax guidance with our earnings release yesterday. Our reinstated production ad valorem tax guidance of $6 -- of 6.25% to 7.25% is identical to what it was at the onset of our 2020 guidance provided in January, as is the case for our reinstated LOE guidance of $5.50 to $6 per BOE. Although we have had recent sustainable LOE reductions and came in well below this range in the second quarter, without the advantage of bringing on new wells, we have kept our guidance range where it was at the beginning of the year when we anticipated bringing 16 new wells online.

With that, I'll turn it back over to Robert.

[Robert Anderson, executive]

Thank you, Mark. We are really pleased with the results and confident in a bright future for Earthstone. While we are sorry to see our industry in such distress, it is creating more M&A opportunities than we have seen in quite some time. We are actively evaluating a number of situations and expect to have more to consider throughout the rest of the year as prices remain low and distressed situations continue to increase. We believe that our strong balance sheet and track record as a successful consolidator positions us well to increase the scale of our company and add value to our shareholders.

With that, operator, we'll now open the floor for questions.

[Operator]

[Operator Instructions] Our first question comes from the line of Brad Heffern with RBC Capital Markets.

[Brad Heffern, analyst]

I guess on the 2021 color that you gave about being able to keep production flat with the 11 DUCs, is that more just meant to be instructive? Or is that actually how you're thinking about the 2021 plan as we sit here today?

[Robert Anderson, executive]

Yes. A little bit of both, Brad. It does depend on where commodity prices head towards the end of the year, whether we want to pick up a rig or not. I think we've been pretty vocal or consistent about our message that we need mid-$45 to $50 oil to want to go back to spending large capital dollars. But outside of that, at some point, end of this year or early next year, completing those wells will allow us to main production flat year-over-year.

[Brad Heffern, analyst]

Okay. Got it. And then obviously, you made the comment on M&A. Can you go into a little more detail about sort of what opportunities you're seeing? And also any thoughts you have about inability to fund them?

[Robert Anderson, executive]

The opportunities are increasing, and size is variable from small to quite large, as you've seen distressed and bankrupt companies. I think all of this will result in further opportunities in terms of larger companies selling assets. It is difficult with no public equity and, for that matter, debt markets open or open only to a very few. Maybe we're one of those few. But we've had discussions with financial parties who are interested in participating with us on acquisitions. And much like we've done in our history, we'll bring in parties at the right time to look at buying assets, and we're going to maintain a very healthy leverage amount and keep ourselves from getting into distress no matter where we are in the cycle. So I think we're just going to see more and more opportunities, and we'll figure out how we can finance those and make sure we keep our balance sheet clean.

[Operator]

Our next question comes from the line of Neal Dingmann with Truist Securities.

[Neal Dingmann, analyst]

First question also on that same line on '21 expectations. And I was just wondering why I realized this plan really, I think, at least the ones you just initial laid out, assumes no new wells. Really, what's -- I'm just wondering what's driving this low cost? Or another way maybe to ask is, how you think about maintenance CapEx given just so low? Because if I recall, I thought Frank already had you all cancel all those country club and other memberships. I just know what else is there.

[Robert Anderson, executive]

Yes. There's no country club memberships up here. I mean the 11 wells we have are in really good areas, and they will help us keep production relatively flat at $30 million. Now is that sustainable? Absolutely not. We still have a relatively high decline rate, and it does depend on when we brought those wells online. If we wait until the very end of '21, we're going to have a hard time keeping production relatively flat. If we brought them on today, we might have the same problem because we get all this flush production from these new wells. So maintenance -- to maintain 13,000 BOE a day kind of level longer term, we're going to have a rig running. And a 1-rig program, I don't know what it would exactly cost us today. But generally speaking, is $120 million to maybe $140 million depending on lateral length and working interest and things like that. This is just a very preliminary -- if the world stays the same and we're at 40-ish -- low $40 environment, we're not spending any drilling capital. These 11 DUCs will help us keep production flat.

[Neal Dingmann, analyst]

Okay. And then you kind of hit on my last one. Just on, how do you think about sort of PDP decline on a go-forward it is -- now that you've been slowing a bit, is that too going to go down? Or I mean, I guess, to look at it another way, is it -- are you able to give us how many wells would offset that? I mean any way you can kind of give us a color on how kind of you're thinking about that in '21 on broader terms.

[Robert Anderson, executive]

Yes. I think we've been consistent in telling everyone that our sort of base decline starting today, we'll call it, is about 30% in the first year and then it gets into the mid -- maybe 26% or 27% the next year and then low 20s or high teens after that. And so I don't think that's changed any. And if we didn't spend any capital, then you can kind of forecast what our blowdown production would look like even if we didn't do those 11 wells. But again, with those 11 wells, it will help keep '21 flat. And then going forward in '22 and beyond, it's all going to depend on price.

[Operator]

Our next question comes from the line of Jeff Grampp with Northland Capital Markets.

[Jeffrey Grampp, analyst]

I was wondering, Robert or maybe for Mark, how important do you guys are you saying free cash flow positive in the context of evaluating whether to go after the DUCs and then potentially drilling rig at some point in time? Would you view that as kind of a must, if you will? Or would you guys have any level of comfort with any near-, medium-term outspend if it helps -- if the returns were good and it would help kind of jump start the return to growth?

[Mark Lumpkin, executive]

Sure. Maybe I'll try to answer that one, and Robert can add on if he wants to. We keep things pretty simple. At the end of the day, we feel like our responsibility is to make good individual decisions at the wellhead. And that's why we were quick to put the rig down and start completing in March and April is because the economics didn't make a whole lot of sense then. Do the DUCs make sense right now? I mean economically, you definitely could go complete the DUCs right now and have pretty nice IRRs for the incremental cost to complete them. In terms of, are we so focused on quarter-to-quarter, year-to-year free cash flow that we won't outspend? No, we're not. And from a practical matter -- and we're just going to be free cash flow positive this year and next year, kind of irrespective of anything else that happens with prices, if all we're doing is completing the DUCs.

At some point, we do anticipate taking the rig back up. And there's a bit of, obviously, a lag there between the cost you expend to drill in the complete wells versus the cash flow. Does that mean over the course of the year we're not free cash flow positive? No, not necessarily. But we're not so fixated on checking that box every quarter. We want to make smart economic decisions at the wellhead that will flow into the bigger picture. And having some outspend for some period of time, we still think is supported by the economics. At the same time, we're not ones just to go keep drilling and completing because we have hedges in place or for other reasons. We're just trying to be as good as we can of the individual decisions we're making at the wellhead.

[Robert Anderson, executive]

Yes. The only thing I'll add, Jeff, is I think we can run a 1-rig program with the level of production and cash flow we have today and be cash flow neutral on an annualized basis. Obviously, there's a -- jump-starting the program, we're going to be cash flow negative for a period of time, but I think longer term, over a year time frame, again, depending on what the price is.

[Jeffrey Grampp, analyst]

Sure. Understood. And for my follow up, I know you guys still have a decent amount of non-op exposure in the Permian. Are you guys seeing any activity levels there? And more on the land side, is there any traction or conversations on swapping any of that out to increase the operated exposure there?

[Robert Anderson, executive]

Still working on the trades, but people have been hunkered down in the bunker for quite some time now since at least March. And so nothing's moving very quickly there. We have no -- we have not heard anything different from our partners in terms of activity in the near term being kind of the remainder of this year. So we'll have to see as we get closer to year-end what their view might be for activity in 2021.

[Operator]

Our next question comes from the line of Duncan McIntosh with Johnson Rice.

[Duncan McIntosh, analyst]

I had a quick question over on the balance sheet. You are doing a great job and the free cash outlook looks great, paying it down. Wondering have you been in conversations with the bank as we head into the fall redetermination? Back in March, you were early and getting it done in the spring. But back then, it looked like things would be pretty dire again in the fall, and it's not as bad here. And particularly with the line of sight you'll have on the free cash, kind of how -- any conversations with them to give you any indication as to what the fall redetermination could look like?

[Mark Lumpkin, executive]

Sure. I mean probably too early to [ circle ] anything around numbers, but we do pretty [ really ] talk to banks and we do that normal course, irrespective of the environment. The one thing I'd say, I mean, for us, we are expecting a decrease in the borrowing base, and obviously, we're not drilling and completing new wells and hedges roll off. Fortunately, we feel like we've got enough ability to pay down debt to outpace that decrease. And really, we don't see any scenarios that we think are realistic that would be concerning in that regard.

Now I will say like, does the environment feel better now than it did 3 months ago? Absolutely. And maybe some of that's the shock of seeing minus $37 oil and teen realizations for the months of April and May. At the end of the day, it's still on a very good price environment for companies in general. And the banks, maybe they feel a little better because we're at $45 or $42 versus somewhere in the teens. But they still have a lot of issues to deal through -- to deal with. And obviously, there's been a lot of E&P companies that have gone bankrupt, and there's certainly more that will. So the banks still have their hands full, and they're still working through all these situations. Yes, I think there is a lot of trepidation in the banks' part in general. And yes, I don't frankly see them letting up a whole bunch in the fall.

Now that being said, that's a general statement. We've got onetime leverage and liquidity and generally are viewed as having done the right thing from a financial standpoint, and our assets are better than many. We probably feel like we've got a pretty supportive bank group that is going to be reasonable and fair. And historically, that's been the case, but too early to circle a number.

[Duncan McIntosh, analyst]

Thanks, Mark. And then I guess just for my follow up, Robert, you gave some really good color on -- and noted some pretty creative things to get LOE down in the second quarter. I know you talked about how it's going to come back up a little bit here in the back half of the year towards a more historical range. But any of those initiatives that you took? Do you think that you could -- can carry forward to kind of help mitigate that LOE creep?

[Robert Anderson, executive]

Definitely, Dun. There's -- it's just a constant progression of a well's life cycle to adjust artificial lift. A lot of our wells are on gas lift, so relatively expensive compressors. Over time, that gets changed out to other lift methods. In some cases, rod pump. In other cases, plunger lift, what have you. So we're continuing to work through that, and that will definitely help reduce LOE. And then some of the things that we were fortunate in getting done in the quarter, working with the utility company to get meters set and get ahead of the schedule there or got moved up in the schedule from some good relationships, we ended up getting generators off of our payroll, and those are very, very expensive. So we didn't have a whole lot, but they still show up as a big expense. So some of these things we did in the second quarter are sustainable, and we'll continue doing the right things in the way we operate our business and continue to watch costs like a hawk.

[Operator]

[Operator Instructions] Our next question comes from the line of Noel Parks with Coker & Palmer.

[Noel Parks, analyst]

I was thinking about having the DUC inventory that, where it works out that just completing those next year can help you keep production flat. That's a lot of really great flexibility you have there. And I mean, was that just sort of a result of the timing of everything kind of falling off the rails with COVID and OPEC Russia? Or was that sort of part of the plan as you were just trying to continue to pivot to emphasis on free cash flow heading into next year?

[Robert Anderson, executive]

I'd love to tell you, Noel, that we had this great plan that no matter what happened in the world, oil going to 20 or sub-20 that we could keep production flat for 3 years running with various amounts of capital. If you go back and think about the beginning of the year and the call we had related to the fourth quarter earnings and full year, we had a 1-rig program. We were going to average for the entire year a tiny bit of free cash flow. And those 11 wells would have been completed, I don't know by now, I can't remember, but pretty darn close. So I'd say it's a fallout of what's happened here and just being very conservative with our capital expenditures and cash and making sure that we come out of this down -- this near-term down cycle. We've been in a down cycle since 2014, but at least this recent piece of it that we survive nicely through it and come out the other side and can continue to find ways to consolidate and grow.

[Noel Parks, analyst]

Great. And just a housekeeping question. And sorry if you touched on this earlier and I missed it. For the free cash flow calculation, if I looked at the numbers right, it looked like this is one of those periods where there was a pretty big delta between, I guess, I'd say, cash CapEx and sort of CapEx incurred in the quarter. And I was just wondering, for the free cash flow calculation going forward, just kind of which one of those is more important for us to use as we just try to model that?

[Robert Anderson, executive]

We always use accrued cash from a calculation standpoint because not all the bills necessarily have hit, but we know what generally they are. So it's in the presentation on the last page or something like that.

[Noel Parks, analyst]

Okay. So -- and one other thing I -- and I just don't have the release in front of me. And as far as change in working capital, you -- is that something also that you would routinely include the -- well, include the impact of and free cash calculation? Or would you exclude that?

[Mark Lumpkin, executive]

Yes. So we don't include that, and I recognize there's multiple different ways to look at that. I mean the way we've been approaching it is, okay, adjusted EBITDAX is the best proxy for really sort of cash flow for the period. We back out interest expense, and then we back out capital expenditures for activity during that period. Now when you're stopping or starting, there is going to be a bigger delta between calculating free cash flow the way we do versus if you're using a cash CapEx number. The second quarter was very atypical from the standpoint of here, we're reporting $35 million of free cash flow, yet our debt balance went up. And the reason for that is because -- and of course, this is tied to the cash CapEx. It's just the time of the payments. We reduced the negative -- the working capital deficit by about $50 million during the quarter. Now we're to a point where that working deficit -- working capital deficit is pretty low and probably won't fluctuate a whole bunch one way or the other until we pick activity back up. At which point, you'd expect as you start completions and drilling again, you start getting bills, but there's some lag between the activity and when you get the bills and when you pay them. So very typical quarter.

As we mentioned in the press release, we had about $169 million of debt at quarter end. In the month of July, we paid down a little more than $14 million. That's not the run rate, by the way. It's not $14 million a quarter. That was high because of timing, but we do expect -- I mean really every month this year that we're paying down some debt without any big changes in the working capital status.

[Operator]

Ladies and gentlemen, that concludes our question-and-answer session. I'll turn the floor back to Mr. Anderson for any final comments.

[Robert Anderson, executive]

Well, we appreciate everybody joining us, and we'll continue to update as we need to, and we'll see you next quarter. Thanks.

[Operator]

Thank you. This concludes today's conference. You may disconnect your lines at this time. Thank you for your participation.