Earthstone Energy Inc

F:BSC2

Earnings Call Transcript 2020-Q1

[Operator]

Good morning, and welcome to Earthstone Energy's Conference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this conference call is being recorded.

Joining us today from Earthstone are Robert Anderson, Chief Executive Officer and President; Mark Lumpkin, Executive Vice President and Chief Financial Officer, and Scott Thelander, Vice President of Finance.

Mr. Thelander, you may now begin.

[Scott Thelander, Vice President of Finance]

Thank you, and welcome to our first 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 and quarterly report on Form 10-Q that we released yesterday, and in our annual report on Form 10-K for 2019. 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. 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 recorded on this call speaks only as of today, May 7, 2020. Thus, any time-sensitive information may no longer be accurate at the time of any replay. 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, regarding near-term strategy and operations, followed by remarks from our CFO, Mark Lumpkin, regarding financial matters and performance and then some closing comments from Robert.

I'll now turn the call over to Robert.

[Robert Anderson, President and Chief Executive Officer]

Thank you, Scott, and good morning, everyone. We appreciate you're joining us for our first quarter conference call. Like many of you, we are working remotely from our homes this morning or with very limited staff in our offices as we follow the guidelines of health experts and regulatory agencies.

The safety of our employees is top priority, and we are pleased that we've been able to manage and conduct both field and non-field functions effectively thus far. Non-field personnel have been working remotely since middle of March using information technology we previously invested in. Our field personnel that must go to a work location are following the safety protocols that we put in place and are performing their job responsibilities with no issues so far.

We appreciate the diligence of our team and service provider partners. These are challenging times, and I thank our staff for their continued focus on achieving our goals and objectives and for doing their part to keep themselves and the community safe. We had a good first quarter and hit on our internal targets for production, adjusted EBITDAX and cash costs, which Mark will discuss in more detail shortly. But I'd like to highlight that our low-cost business practices and our prudent balance sheet management have continued to serve us well, especially in the current environment.

With the energy industry facing unprecedented challenges due to the COVID-19 pandemic and resulting historic low oil prices, we are fortunate to have a very strong hedge position, consisting of fixed price swaps that afford the maximum downside protection and low leverage with ample liquidity.

We also have no long-term service contracts, no minimum volume commitments, and earlier in the year, we negotiated extensions on all our 2020 drilling obligations, which gives us the flexibility to actively adjust our capital program and curtail production as we see fit. We expect to focus on cash flow generation and reducing debt for the remainder of 2020.

With the deterioration of oil prices, we began shutting in low volume, high-cost producers in mid-April. As prices declined further in late April to what looked like single-digit net oil prices for May, we decided to voluntarily reduce a significant portion of production from our operated wells for the near-term.

We currently expect to curtail or shut in 70% to 80% of our net operated May production. Where we are a non-operated partner, the shut-ins appear to be a little lower and therefore, we estimate that shut-ins for May could range from 55% to 70% of total net company production volumes.

We made this decision in spite of the fact that our direct operating costs across all our assets averaged $6.50 per BOE in the first quarter, and with production taxes, get approximately $8.60 per BOE of operating costs. As you can appreciate, this has been a moving target over the past week or two and is subject to further change. While it seems to us as though a significant volume of voluntary curtailments is occurring across the industry and that forced shut-ins seem less likely in the near-term, we cannot guarantee such will be the case for all of May or in future months as storage potentially fills up, and demand recovery remains uncertain.

Our actions for June shut-ins will be determined based on prices later this month as well as how these other factors look to be playing out. Accordingly, we have withdrawn our 2020 production guidance as well as our per unit cost guidance, and we will revisit this later in the year as we gain further clarity on production volumes and oil prices.

As a brief operational update in March, we announced that we reduced our capital program to a range of $50 million to $60 million for 2020, and we're not making any changes to that guidance. In the first quarter, we reported capital expenditures of $41.8 million. So the annual spend is largely complete. In late May, we expect to release our one operated rig, which is in the Permian Basin, drilling on our six well pad in our Ratliff project in Upton County, Texas.

Obviously, we are quite disappointed that this crisis is causing us to lose the strong momentum we have worked hard to create in the Permian Basin. As an example of our continued focus on capital efficiency during the first quarter, we completed and brought online three gross and net operated wells that were drilled in late 2019 on our WTG project in Reagan County.

These three wells achieved an all-in drilling, completion and equipment cost per lateral foot of about $760, about a 10% reduction over the 2019 average cost per foot. We also had 15 gross or 3.1 net non-operated wells brought online in Martin County during the quarter. Also during the first quarter, we finished drilling a five-well project on our Hamman 30 Unit that was in process at year-end.

And as I mentioned, we plan to finish drilling the six well Ratliff pad, which is in progress now, but we will delay the completions of all 11 wells and the drilling of future wells until there is an improvement in oil prices. So our adjusted capital budget results in bringing online three operated wells and the 3.1 net non-operated wells. At this point, we expect no additional new wells coming online in 2020.

With that, I'll turn it over to Mark to review the financials.

[Mark Lumpkin]

Thank you, Robert. As we did in the fourth quarter call, we're going to start today with a recap of our balance sheet and liquidity, particularly given the current market conditions. On March 27, 2020, our borrowing base under our senior secured revolving credit facility was set at $275 million.

Despite the much lower price deck assumed by the banks in the recent determination, the borrowing base was only reduced by 15% from our previous borrowing base, which we think is a reflection of the quality of our assets and financial profile.

As of March 31, our outstanding borrowings under the credit facility were $152 million, a reduction of 11% compared to the $170 million in outstanding borrowings as of December 31. And I'll remind you that the debt we have drawn under the credit facility is our only outstanding debt.

As of March 31, we had approximately $5.1 million in cash and approximately $123 million unused borrowing capacity for a total of approximately $128.1 million of funds available. In response to the dramatic incline in oil prices in March, we reduced our 2020 capital plan by 67% to a range of $50 million to $60 million.

While heavily hedged for 2020 before the COVID-19 crisis impacted oil prices, we have continued to build our hedge book, including having added incremental oil hedge volumes in March for the second quarter and the third quarter to more closely match our PDP profile.

Given that nearly all of our PDP oil production is hedged at a WTI price of $57 per barrel for 2Q through 4Q and that we have initiated actions to reduce our 2020 cash G&A by a targeted 25% from our previous plan, we do expect to generate significant cash flow beginning in the second quarter of 2020. So this puts us in a strong financial position to improve our working capital position and further reduce our borrowings in our credit facility to provide additional financial cushion and flexibility.

As an aside, on use of expected free cash flow in the near-term, I would expect that during the second quarter, we will work down our working capital deficit, not considering hedge assets and liabilities quite a bit. And I would expect to have a bit higher debt balance at quarter end 2Q versus at quarter end 1Q on that basis.

Now looking at our 2020 first quarter financial metrics and starting with the topline, revenues for the first quarter were $45.1 million, with oil contributing about 91% of revenues.

From a production standpoint, our first quarter sales volumes averaged 15,767 barrels of oil equivalent per day and were comprised of approximately 61% oil with 19% natural gas and 19% natural gas liquids.

Now let me take a minute to discuss our hedge position in a bit more detail. As of quarter end, we had approximately 8,000 barrels of oil per day swapped for the remainder of the year at an average WTI price of $57. This is a bit sculpted, starting at 9,000 barrels per day in 2Q, stepping down to 8,000 barrels per day in 3Q and then down to 7,000 barrels per day in 4Q. And we have 4,000 barrels per day of oil swapped in 2021, above $55 WTI prices.

We also largely have the underlying basis differential swapped and on the natural gas side, we continue to benefit from strong hedges, but this is less impactful. Just to provide some context on the financial benefit of our hedge book, as of March 31, the mark-to-market of our hedge book was approximately $93 million.

In terms of commodity pricing during the first quarter, our oil prices averaged $46.59 per barrel, which was right around 100% of NYMEX. Natural gas prices were $0.65 per Mcf or about 33% of NYMEX and natural gas liquids prices were $11.01 per barrel. This resulted in an unhedged average realized price of $31.46 per barrel of oil equivalent during the quarter.

Our hedging program significantly improved our price realizations to $52.62 per barrel for oil, $1.19 per Mcf per gas with NGL, which is not hedged, remaining at $11.01. And this resulted in an average realized price, including the hedge settlements of $38.25 per barrel of oil equivalent during the quarter.

On the expense side, we again achieved our targeted sub-$10 per barrel of LOE and cash G&A. With LOE coming in at $6.51 per BOE and cash G&A coming in at $3.09 per BOE for $9.60 per BOE in aggregate. We have targeted a 25% reduction in cash G&A on an absolute basis versus our prior guidance, which is around the low end of the updated $15.5 million to $16.5 million guidance for the year.

We aim to achieve this primarily through a reduction in executive compensation, but also through some further cost-saving initiatives that are in progress. We do really highly value our employee base and remain very focused as the management team on doing everything in our control to keep our employees fully utilized. We are making an investment in our people, and it's a team effort, and we'll continue to view our employees in that light.

We also reduced our interest expense by about 5% from the fourth quarter, and our production and ad valorem taxes were 22% lower sequentially. From an income standpoint, we reported GAAP net income in the first quarter of $36.7 million or $0.57 per diluted share, which reflected the pre-tax gain of $99.8 million on our derivative contracts.

The 2020 first quarter results also included a $60.4 million impairment expense, of which $42.8 million was related to an oil and gas property impairment, driven by low commodity prices and $17.6 million was a goodwill impairment.

Our adjusted net income, a non-GAAP measure, was $8.2 million or $0.13 per adjusted diluted share for the first quarter. We reported adjusted EBITDAX, also a non-GAAP measure, of $38.2 million in the first quarter. Please see our earnings release for explanations and reconciliations of non-GAAP measures.

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

[Robert Anderson, President and Chief Executive Officer]

Thanks, Mark. Again, I'll reiterate, we had a really good first quarter. While the severely depressed commodity prices persist, we will be even more diligent about cost control and efficient management practices while continuing to focus on health and safety of our employees and contractors as well as the protection of the environment and the communities where we work.

As I said earlier, we continue to manage and produce our properties as we wind down drilling and completion activities, experiencing no complications arising from our COVID-19 mitigation efforts. We are also focused on maintaining our strong balance sheet position throughout the year and continue to target being below 1x levered at year-end 2020. Our strategy has not changed despite the current challenging industry conditions.

We continue to focus on low-cost, efficient operations and on building scale through value-enhancing [indiscernible] be plentiful in this distressed environment. We expect to be a part of the consolidation that will occur as a result.

Before we take your questions, we would like to say thank you again to our dedicated personnel who are working smart and adapting to this new challenges we have. Our hearts go out to those being affected by this pandemic and our deepest thanks to those working tirelessly to help us persevere through it. We will continue to focus on making the best long-term decisions for our company and key stakeholders and believe our experience and resilience will make Earthstone stronger in the days and years ahead.

With that, operator, we'll turn it over to questions.

[Operator]

Thank you. We will now be conducting a question-and-answer session. [Operator Instructions] The first question comes from the line of Brad Heffern with RBC Capital Markets. Please proceed with your questions.

[Bradley Heffern, RBC Capital Markets]

Hey. Good morning, everyone. I have a couple of questions on the shut-ins. So first of all, what was the rationale behind the shut-ins? Because obviously, it's not close to the op cost. So was there some components of difficulty marketing the barrels? Or was it purely based on sort of the forward curve and the outlook for oil?

[Robert Anderson, President and Chief Executive Officer]

It's really, Brad, based on not wanting to sell our oil at $5, $6, $7, $8 is what it was appearing to look like in late April. So we made that decision. And it's a game time decision to adjust that as we move through the month.

[Bradley Heffern, RBC Capital Markets]

Okay. Fair enough. And I guess, can you talk about the confidence that you have that the wells will come back to something like the rates that they were at. And then also, does this have any implications for the lease agreements?

[Robert Anderson, President and Chief Executive Officer]

Sure. One thing is from the lease agreement standpoint, we're not shutting wells very long, and we're rotating wells throughout our different leases. So in general, wells will produce, at some point, a little bit during the month. So that satisfies that issue. We have confidence that our wells will come back to where they were based on wells that were frac hit in the past, coming back to the line, the forecast.

And again, we're not shutting wells in for a very long time. And the majority of our wells, other than a few new wells, have been on long enough that we don't think there's any detrimental effects. The other thing is we're not sitting in an old waterflood where you've got momentum built up in energy and things like that, that create issues from a reservoir dynamic standpoint. So we just felt like the reservoir risk was pretty darn low.

[Bradley Heffern, RBC Capital Markets]

Okay. Got it. And then at the end of your comments, Robert, you mentioned that you might be part of the resulting consolidation from this. I guess, how do you think about the contrast between they're likely being distressed assets out there, but also the uncertainty of the situation and probably the desire to also just hunker down? Thanks.

[Robert Anderson, President and Chief Executive Officer]

Yes. I think both of those things are true. There's going to be distressed assets and therefore, sales of properties. We'll participate in those properties that make sense. And then you're going to have the asset market shut down until there's a little bit more stability in prices. With the movement in prices here recently, that should help sellers who, for whatever reason, need to sell or want to sell, maybe again, foregoing stress in the fall, something like that. These times create opportunities and we're going to try and take advantage of gaining some more scale through this.

[Bradley Heffern, RBC Capital Markets]

Okay. I appreciate the comments. Thanks.

[Operator]

Our next question is from the line of Neal Dingmann with SunTrust. Please proceed with your questions.

[Neal Dingmann, SunTrust Robinson Humphrey, Inc.]

Good morning all. My first question just on your future activity. I'm just wondering are you able to address the prospects efficiently going forward with the one rig? Or would you occasionally again, I know that makes a lot of sense now and especially given the pristine balance sheet you all continue to keep. But I'm just wondering is there a point to either because HBP or just whatever with this acreage going forward where it would make sense from either because of that reason or just efficiency that it would make sense that if you come back, you'd have to come back with more than one rig, two or three rigs or anything like that?

[Robert Anderson, President and Chief Executive Officer]

That's sort of a mouthful, Neal. So we at some price, we're going to be comfortable to come back. And what is that exact price? I don't know what it is, but definitely a four handle gets us a little more excited about coming back with the rigs, especially if we can see reduced costs. I think we're going to have to build up the efficiency when we come back because we will you put a new team back on the field, it's going to take a little bit of time.

From an HBP status, and obligation status, we pushed everything out a year. So we've got lots of time to evaluate. And if prices remained at some low level to where the economics didn't justify, then we would go back to those same groups and ask for another annual extension, or in some cases, we may, depending on the size of the acreage position, just let those go by the wayside. It depends what the environment looks like.

But we're optimistic that oil prices are going to recover, and we're going to get back to work. And we think sometime in 2021, whether it's January or maybe it takes all year, but we think that, that's the case.

[Neal Dingmann, SunTrust Robinson Humphrey, Inc.]

And then just lastly on the non-op, any thoughts I guess I had heard I don't is there too often on just like what CrownQuest in? Any thoughts or forecast for what you're thinking there for the remainder of the year?

[Robert Anderson, President and Chief Executive Officer]

So speaking to all of our parties who operate in areas for us, they have all put our particular acreage and any new activity on hold. We had some plans in Midland County with one of our parties to drill a couple of wells. And then when prices started deteriorating, rapidly in March. We put that on hold as a group. So right now, there's no discussion of having any capital plans for the rest of this year.

[Neal Dingmann, SunTrust Robinson Humphrey, Inc.]

Very good, thanks guys. Great financial.

[Robert Anderson, President and Chief Executive Officer]

Thanks, Neil.

[Operator]

Our next question comes from the line of Dun McIntosh with Johnson Rice. Please proceed with your question.

[Duncan McIntosh, Johnson Rice & Company L.L.C]

Good morning, Robert, and Mark. Actually most of my questions were asked, but a quick question on the revolver. You all got out there early in just a 15% cut. Wondering if you get any sense from the banks as we look out to the fall redetermination and if prices do materialize that, do you think that kind of the level you're at here is you feel pretty comfortable with the $275 million? And how they're thinking about the bank's exposure to the industry?

[Robert Anderson, President and Chief Executive Officer]

Hey. Mark, you handle that one, please.

[Mark Lumpkin]

Yes. I'll pick that one, Dun. That's a great question. We obviously when prices fell pretty sharply in March, we made some pretty decisive decisions even before oil got to a worse spot. And to us, we're looking at the economic decisions, and that's true as it relates to the CapEx. It's also true as it relates to the shut in.

Our number one job is to be good stewards of our resources for our shareholders, and then secondly, for our employees. That's what we're going to do every step of the way, whether it's making decisions on, well, do we want to sell a barrel of oil for $8 or $10? Or do we want to not sell it? Realize the hedges and sell that barrel later for a higher price or the CapEx, how we spend our G&A, et cetera.

And in terms of the borrowing base, we did go early because we saw some signs, certainly not to the extent that occurred, but we saw some signs that things could get a little bit choppy and the banks could be a bit nervous and certainly, we're seeing more of that play out as more folks have gotten the processes done.

Realistically, because we set the rig down and we're not bringing on any new wells. I mean the borrowing base is just going to go down between now and the fall because you're really looking at a natural PDP decline for the most part.

Now can you get into some math about if you shut in ex-barrels for ex-period of time, does it actually push some of the PDP further out? Yes. But we're honestly not doing that. We've got enough liquidity that we feel very comfortable at the rate that we'll be paying down debt.

And kind of what the PDP roll off is that even what the decks the banks are using now, we're going to have plenty of liquidity. Now that does go into our thinking of CapEx and acquisitions and maybe to answer a little bit of Brad's question on the M&A. There are a lot of distressed situation out there. We're not going to become one of them, whether it's organically or doing some acquisition.

And as it relates to the borrowing base, we're looking at that, and we've done our forecast and feel comfortable with where things are headed, frankly, not just later this year, but even next year if we weren't drilling. And with the hedges, we could not producing barrels, still pay down pretty significant amounts of debt between now and the end of this year, especially, but also next year.

[Duncan McIntosh, Johnson Rice & Company L.L.C]

All right. Great, thanks. And then a follow-up, I was wondering if you could provide a little color on your marketing arrangements. I know that one of the things that's kind of brought to light as prices have collapsed has been the role factor in these marketing agreements. And I think it's gotten a little better as Contango is flattened out some, but kind of what are you seeing on that front? And kind of what role does that play in your decision to start opening up the chokes on some of those wells that you've cut back right now?

[Mark Lumpkin]

Maybe I'll take it, the first part of that question and then turn it over to Robert. In terms of the roles, yes, it's typically plus or minus $0.25 to $0.50 and with what happened with prices collapsing, especially in the near months, you ended up in a situation where the role is calculated on basically the month before.

So by late April, we knew the role is going to be minus $6 or $7 or $8. We also knew that we're going to get a pretty good negative differential on basis, both in Permian and Eagle Ford as Cushing over that time was trading at a premium to those two basins.

That absolutely was a critical piece of our decision on shut-ins for May. It looks a lot better looking forward to how that will apply to June. Probably by if you take the role plus the diff and it's probably about $10 better. And that's a different economic decision. And then certainly, strips risen since late April. So you do think about that different from an economic decision.

In terms of the marketing, maybe I'll kick that over to Robert to pick up what is going on there. And certainly, that's something everybody's had to be a lot more focused on given the disruption we're currently seeing with shut-ins and talking curtailment and no curtailment, et cetera.

[Robert Anderson, President and Chief Executive Officer]

Yes. I would just say that on the marketing front, we're dealing daily with our purchasers, both relative to May and what June volumes we're thinking about. And we have a multiple – multitude of purchasers that we're dealing with, and it gets complicated. We have some on truck, we have some on pipe. And so its nominations are in progress or thinking about it and all that.

So as we look to June, what June might look like, I'm getting more comfortable that we're going to turn more volume on in June. However, as shut-ins come back on, we may be our worst enemy and prices may take a turn for the other direction, and we're going to have to just play that out as we get closer to the beginning of the month.

[Duncan McIntosh, Johnson Rice & Company L.L.C]

All right, thank you all and congrats on a strong quarter and look forward to following on.

[Robert Anderson, President and Chief Executive Officer]

Thanks Dun.

[Operator]

Our next question comes from the line of Jeff Grampp with Northland Capital. Please proceed with your question.

[Jeffrey Grampp, Northland Capital Markets]

Hi guys. I thought it was interesting, it looks like you guys added, on Slide 10, kind of a future pad size expectation of four to five wells per pad. Obviously, a big step-up from where you've been historically. Should we think about that as being basically happening irrespective of the overall rig count that you guys have? And I guess where I'm headed with that is you guys seemingly are maybe more comfortable, even in a one rig scenario with the extended cycle times and that maybe the efficiencies more than offset the extension there? Am I thinking about that right?

[Robert Anderson, President and Chief Executive Officer]

There's a couple of things. You picked up on efficiency, and that's definitely true. The other thing is reservoir dynamics, Jeff. So stacked benches, making sure you develop them in the best way possible and kind of capture as much as the resource economically as possible. That seems to be another benefit. So those two combined give us the pad size. So right now, we're drilling a sixth well, finishing up on the six well pad, and – going forward or in that range, four or five on average wells per pad. So we hope that we can pick up where we are leaving off on the efficiency side and also gain that on the reservoir side.

[Jeffrey Grampp, Northland Capital Markets]

Got it. Got it. Understood. And more kind of a modeling question. I don't know if this is more for Mark. But any expectations for where we should think about oil mix kind of heading the next few quarters, understanding that there's some GOR implications with kind of going to a PDP blow down mode? Do you have a sense of when that maybe kind of stabilizes out and on what level?

[Mark Lumpkin]

I mean honestly, it doesn't look drastically different to us. We actually tick down the oil content just a little bit. That probably wouldn't be a bad thing, but it's not like we think it's 55%. We think it's still pretty close to 60%, 62%.

That being said, obviously, because we've got sort of an indefinite volume that shut-ins for an indefinite time. As the technical guys, all remind me frequently, it's not as easy as just flipping a light switch everything back on exactly like it was. But generally speaking, we're not expecting a huge degradation in the oil content.

[Jeffrey Grampp, Northland Capital Markets]

All right. I appreciate the time guys. Thank you.

[Operator]

Our next question comes from the line of John White with Roth Capital. Please proceed with your question.

[John White, ROTH Capital Partners]

Good morning. I don't have a question. I just wanted to say, Robert, with all the experience you've gained with all the crashes that you've been through is really paying off now. You got the company, in my opinion, positioned as well as you possibly could. So congratulations.

[Robert Anderson, President and Chief Executive Officer]

Hey will you send that note to Frank. Thanks, John. I appreciate it. I have a great mentor. So and a great team around us. It's not all me.

[John White, ROTH Capital Partners]

I'll get in touch with Frank. You bet.

[Robert Anderson, President and Chief Executive Officer]

Thanks.

[Operator]

Our next question is from the line of Jason Wangler with Imperial. Please proceed with your question.

[Jason Wangler, Imperial Capital Asset Management LLC]

Hey, good morning guys. It may kind of dovetail on the last question there. As you – Robert, you mentioned kind of rotating the production things. Can you talk about the operating or even capital costs that entails as you kind of shut-in wells and bring them back on and things? And then also as you think about getting it back into full production, what would that kind of cost you? And I assume that's kind of budgeted in the budget this year?

[Robert Anderson, President and Chief Executive Officer]

Sure, Jason. Good questions. And part of it is a little bit unknown, but I'll tell you that the ability to cycle from one well to the next in a unit, makes us confident that we'll bring these wells back on with very little mechanical issues, because we're putting chemicals around each wellbore and treating the rods and that kind of thing or and we did a good job before we shut in gas lift wells by enhancing the amount of chemicals we treated those wells with and gave them a big squeeze before we shut them in.

So that gives us some confidence that when we turn these wells back on, we're not going to have a whole lot of remedial capital that needs to be spent to fix them. Now that said, there's going to be some cases, I suspect, where we're going to learn something and go – ops, we would do it maybe a little bit differently in a particular area because each area is a little different, the chemical programs are a little different, definitely between the Eagle Ford and the Midland Basin. But in general, we don't think that there's going to be any material capital to bring all the wells back online.

[Jason Wangler, Imperial Capital Asset Management LLC]

And then you obviously have the DUCs kind of built up or you will here pretty shortly. As you think about, again, bringing all the wells back on and all that stuff, whenever it's appropriate, would it make sense that you'd probably complete some wells before bringing a rig back on? Or do you think that would be done kind of in tandem when appropriate?

[Robert Anderson, President and Chief Executive Officer]

I think there are two different decisions. We get to the end of the year, and oil is hovering where it is today. Maybe we go ahead and complete those wells, but we're not bringing a rig back. If oil is 40-ish at the end of the year, we're bringing a rig back and we're completing those wells. And it's a balance between liquidity, cash flow and all that.

So it is going to be sort of something we continue to watch throughout the year. We're not in a big hurry to bring those to complete those 11 wells. And it's somewhat price dependent. I don't really have a price that we're willing to do it. It's more of what the future looks like.

[Jason Wangler, Imperial Capital Asset Management LLC]

Okay. I appreciate it. Thank you.

[Robert Anderson, President and Chief Executive Officer]

Thanks, Jason.

[Operator]

Our next question is from the line of Noel Parks with Coker & Palmer. Please proceed with your question.

[Noel Parks, Coker & Palmer, Inc.]

Good morning.

[Robert Anderson, President and Chief Executive Officer]

Hi, Noel.

[Noel Parks, Coker & Palmer, Inc.]

Hey, just had a couple of questions. You mentioned earlier about having extended the lease terms on some of your acreage. And if I'm reading that right, that's not reflected in the 10-K, right, the expiration schedule there?

[Robert Anderson, President and Chief Executive Officer]

That's probably correct because in the K, by the time when we filed it, and that's as of 12/31. Our obligation drilling was set for the year. And so we did negotiate in a couple of instances where those obligatory wells were pushed out a year.

[Noel Parks, Coker & Palmer, Inc.]

Okay. Great. I was just wondering because I took a quick look at the 2019 year-end and compared it to the 2018, and numbers seemed like it had gone up, I mean, not a huge amount. So that would make sense that it was after that, so thanks.

[Robert Anderson, President and Chief Executive Officer]

Yes.

[Noel Parks, Coker & Palmer, Inc.]

And as far as the – one quick thing, kind of sort of housekeeping, can you give me a rough idea of where the effective interest rate is headed for second quarter on the credit line? I noticed a – note about some interest rate swaps are going to be taking effect this month?

[Mark Lumpkin]

Sure, Noel. It's Mark. I'll pick that one up. So what happened here in the past three or four months is LIBOR has tightened quite a bit, which really was – what caused us to looking to do with some interest rate swaps. Yes, we've effectively got our underlying LIBOR component swapped at a little under 30 basis points over a four-year period with some step downs. That's not on all of our debt, but it's probably 75% of it or something like that.

In terms of the underlying rate, right now, our kind of regular interest rate is about 3%. I think it's been a little below 3% the last few tranches. But if you use kind of a 3% number for 2Q, that's probably about right relative to where LIBOR is and what the margin above LIBOR in our credit agreement is.

[Noel Parks, Coker & Palmer, Inc.]

Great. Thanks a lot. And you talked about consolidation, and that's been a topic that's been up quite a bit over the quarters, just with the strength of your balance sheet. And I was wondering in to the degree you're hearing about or in touch with some of those properties that might be available. Are you seeing any greater appetite for accepting equity as consideration? It sure seems to me people should want to accept equity, but it doesn't mean it's necessarily happening.

[Robert Anderson, President and Chief Executive Officer]

You said the right thing. It sure seems like people should be wanting to do, but it isn't happening. I think we're just in sort of a frozen state at the moment, and until things fall out a little bit, what does demand look like, therefore, what do prices look like, then I think there'll be a little bit more appetite by sellers to look at opportunities where they can take equity and grow, whether that's a private or a public for that matter. So we are – as our track record has proven out, we're always willing to use our equity and bring in a party and grow together.

[Noel Parks, Coker & Palmer, Inc.]

Great. And just I don't know if you have any thoughts on this. It strikes me. This is clearly probably a terrible time for people to be trying to unload non-core stuff. It's probably hard enough to get a bid for the really high-quality stuff. And I just wondered, as far as what you're seeing available, have you seen any maybe just some of the lower-tier stuff dropping out. Is the overall quality of what you're seeing kind of on the increase? Or is it just as you said, pretty much everything is frozen?

[Robert Anderson, President and Chief Executive Officer]

The few things I've seen that sort of would peak our interest, are frozen and then the things that I am seeing are and that we're seeing as a team are probably areas that have assets that are – that were probably distressed coming into the beginning of the year and aren't in areas where we're really focused. We're really focused in the Eagle Ford and the Permian. We that's our main areas, and we're not going to deviate from that materially.

[Noel Parks, Coker & Palmer, Inc.]

Great, thanks a lot.

[Robert Anderson, President and Chief Executive Officer]

Thanks, Noel.

[Operator]

Thank you. At this time, we've reached the end of our question-and-answer session, and I'll hand the floor back over to Robert Anderson for closing remarks.

[Robert Anderson, President and Chief Executive Officer]

Yes. Thanks, everybody for listening in today. And as always, we're open to calls and emails and look forward to getting through the second quarter. Thanks.

[Operator]

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