Goodrich Petroleum Corporation
Q4 2020 Earnings Call Transcript

Published: 11 Mar 2021

[Operator:]

Good day, and welcome to the Goodrich Petroleum Fourth Quarter and Year-End 2020 Earnings Call. All participants will be in listen-only mode. After today’s presentation, there will be an opportunity to ask questions. Please note, this event is being recorded. I would now like to turn the conference over to Gil Goodrich, Chairman and CEO. Please go ahead.

[Gil Goodrich:]

Good morning, everyone, and thank you for participating in our year-end 2020 and fourth quarter earnings call this morning. Joining me this morning is our President, Rob Turnham. Also, joining us is Mike Killelea, our Executive Vice President and Chief – and – excuse me, and General Counsel; and Kristen McWatters, Senior Vice President and Chief Financial Officer.

[Rob Turnham:]

Thanks, Gil. Revenues adjusted for cash settled derivatives totaled $29.2 million comprised of $28.9 million of oil and natural gas revenues and $300,000 of cash settled derivatives. Average realized price including cash settled derivatives was $2.35 per Mcfe for the quarter. Our per unit cash operating expense, which is defined as operating expenses, excluding DD&A impairment and non-cash G&A was $0.97 per Mcf equivalent. And cash interest expense was $0.07 per Mcfe or a total of $1.04 per Mcf equivalent. Cash margin including interest expense was $1.31 per Mcfe or 56% of realized price including settled derivatives. As you will see in our slide deck and discuss later in my prepared remarks, based on fourth quarter results, we had the highest cash margin of any of our natural gas peer companies. We are expecting this total cash unit cost including interest to continue to decline in 2021, with the midpoint of guidance less than $1 per Mcfe. Combined with much higher gas prices, we anticipate robust cash margin expansion, which will drive our projected free cash flow for the year. Capital expenditures for the quarter totaled $11 million of which nearly all was spent on drilling, completion and facility costs associated with Haynesville wells. For the year, we spent approximately $56.5 million. Interest expense totaled $1.6 million in the quarter, which included cash interest of $900,000 incurred on the company's revolver and non-cash interest of $700,000 incurred on the company's convertible notes.

[Operator:]

We will now begin the question-and-answer session. Our first question will come from Neal Dingmann with Truist. Please go ahead.

[Neal Dingmann:]

Good morning, guys. Just two quick ones. Can you hear me all right, Rob?

[Rob Turnham:]

Yes, we do. Thanks. Yes.

[Neal Dingmann:]

Okay. Two things. One, could you tell me it seems like you've had a little change in the non-op activity. Could you tell me what's the, sort of, max? I mean could -- again maybe give us a little bit more color on what's ramped there how much more could potential ramp, or is it just, obviously, price dictated right now what's driving that? Talk about the non-op side if you could a little bit.

[Rob Turnham:]

Sure. Neal, this is Rob. And it's really -- as you know because you've seen our acreage position, Chesapeake is the predominant operator on joint acreage. Obviously, we operate 80% of our position. So it's a minority position. And with them emerging from their restructuring, we have definitely seen a few more well proposals. I think we have maybe five gross wells. Our interest in those wells is approximately 20% -- 25%, I would say on average. So it's a manageable amount if you consider that that in essence is a little over one net well. We do our best to ensure that the timing is accurately portrayed. Our land department talks to their land department extensively. And so we feel like we have a good handle on that. It's -- the magnitude of that is even if they ran two to three rigs on our acreage exclusively, we think the gross acres left to be developed in our joint venture is about 9,000 net acres out of their 225,000. So doesn't seem likely to us that they would put all two to three rigs on that acreage because it's a small subset of the total. But that being said, we're prepared to shift our operated budget down if we see multiple well proposals, and for that reason we don't enter into long-term drilling contracts. So we have total flexibility of doing that. The other acreage that we participated in quite a few wells was Sabine over on the Texas-Louisiana border. What caused the deferral of completions from the fourth quarter of 2020 to the first quarter of 2021 was just they decided to drill two additional wells off of the same pads, and therefore defer all of those wells to the first quarter. So it was the right thing to do to fully develop the acreage, but it was unexpected and that's what caused our fourth quarter volumes to be lower than expected.

[Neal Dingmann:]

Sure. No, it's good -- nice to see all the activity. Then really just one other one. We're obviously seeing a lot of activity, not just -- I would call it M&A and others. Just obviously we've talked -- we've seen about potential IPO in the Haynesville maybe the one coming or there could be two others behind that. So Rob, could you or Gil just talk on M&A and what this is doing to the play? Have you seen prices go up? I saw you did a little bolt-on which was nice to see. But I'm just wondering now it seems like there's going to be a -- much more sort of interest and continued interest in the play with these IPOs et cetera which is a good and bad thing, I think looking at yours versus them still looks incredibly cheap. But I'm just wondering more on the M&A side and asset side, what you think this will do to the play? Thank you.

[Gil Goodrich:]

Sure. Neal, this is Gil. Good morning. I would say that probably due to COVID as much as anything else and I guess low natural gas prices during 2020, it was pretty dead market probably everywhere. But certainly that was true in the Haynesville. As you probably know, the Haynesville position is not huge from a geographic standpoint and it really is dominated by call it 10 large players. Yes, we -- there is an IPO coming fairly soon. We think that's a good thing for the play. We expect as you do they're probably getting one or two more behind that. We also think that will be a good thing for the play as well. Whether or not, there's a whole lot of combinations between in-basin players that kind of remains to be seen. What Chesapeake does post-emergence is also a question, but they certainly now have a very good balance sheet and it looks to us like a very good strategy. And we position them to be more acquisitive should they so decide to do that. Very hard to handicap exactly what's going to happen. Getting back to our strategy, there are some smaller players and some smaller positions out there which is what we've really been targeting with our bolt-ons. I think as Rob said, most of what we've done in the last year with the 4,000 acres we added was kind of drill to earn, where you've got someone who's looking to get it developed may or may not have the capital or the desire to spend the capital, whereas we do and we can make a deal that actually gets a well drilled that delivers some overriding interest to them whereas it otherwise is just sitting there. So we do expect the gas prices going up. That acreage values will creep up during 2021. I can't say if that's really happened yet, but we do expect that to happen. But we're going to continue to be opportunistic and try to cut deals that fit us and fit the seller as well.

[Rob Turnham:]

And Neal, I'll add one thing. Also we look forward to those road shows and IPOs because it will bring a lot of attention to how our well results are as compared to others. And I think it's just going to broaden the exposure for our company and emphasize how good the acreage is and the well results have been to date.

[Neal Dingmann:]

Yeah. I agree with you Rob. Thanks guys. Absolutely great. Thanks.

[Rob Turnham:]

Thanks, Neal.

[Operator:]

Our next question will come from Dun McIntosh with Johnson Rice. Please go ahead.

[Dun McIntosh:]

Good morning, Gil, good morning, Rob.

[Gil Goodrich:]

Good morning.

[Dun McIntosh:]

I was wondering if you could give us a little more color around the impacts from the storm, specifically thinking about kind of LOE and workovers that you might have to do after that. And I appreciate giving the guide on the first quarter. So, anything you're seeing there? And I assume everything is back up and running? If not where you might have some trouble to get the things going again?

[Rob Turnham:]

Yes. This is Rob. Yes, everything is back up and running. Ironically, it didn't take very long once we were able to get back in the field to bring those wells back on. The problem is we couldn't get to the field. The roads were iced over and trucks were idled. So, we had significant production volumes. It wasn't below our hedged volumes, which we lock in at 1st of month. But, certainly -- and we sold some gas on gas daily, which is going to be an attractive price. But, for the most part, it just took some time, and we adjusted our guide for the first quarter down to really take into effect that. One other thing that also impacted the first quarter was shut-in of an offset well, while we were fracking these two new 10,000-foot wells. And so, when you factor that in plus the downtime, that's what's driving a little bit lower first quarter volumes than what we were expecting. You also look at the non-op activity, which -- I would say, good news is the operators on our non-op activity know what they're doing and they're making good wells. The problem is we have less control over the timing of those completions. And therefore, we've built in a little more conservatism on that guide in the first quarter. And frankly, the guide for the year, we feel more comfortable with that by deferring some of our operated activity, pushing, as Gil said, the sequencing on the cadence further into the year, caused a modest decrease of call it 3% on production. But, we're still on pace to what we think generate similar EBITDA and DCF, and similar free cash flow as we've guided before.

[Gil Goodrich:]

And Dun, this is Gil. I might just add this to your LOE question. We expect negligible impact to LOE from the storm. It really was just a shut-in and put the wells back on.

[Dun McIntosh:]

Okay. Thank you. And then, for my follow-up, I mean, Rob, you touched on it a little bit. How should we think about that production cadence with -- given the impacts in the first quarter and the reshuffling of some of that non-op activity? I know we were kind of looking for coming out of the first quarter with pretty steady growth. Is that still a pretty fair assumption?

[Rob Turnham:]

Yes. And that's why we gave the 160 million a day number in the press release, because obviously, you're seeing some wells come online, that's going to take us to another level on production. We also have a well that's going to get fracked the 1st of April. First week of April is where we currently expect it. It's an operated well. It's another 10,000-foot lateral that we have a high working interest in. So, I think we had to kind of work our way through the completion deferrals on the non-op side and the freeze, but it just feels like -- and now you could see some momentum gathered, which is why -- gathering, in particular, in the second quarter, and then throughout the rest of the year, which is why we were comfortable with revising the guidance, but keeping the number pretty high.

[Dun McIntosh:]

All right. Thank you.

[Rob Turnham:]

Thanks Dun.

[Operator:]

Our next question will come from Phillips Johnston with Capital One. Please go ahead.

[Phillips Johnston:]

Hey, guys. Thank you. Obviously, some timing factors and weather has impacted a lot over the last few months. But when we look at your well performance in terms of productivity, the state data really does confirm Rob's comments that your wells are significantly outperforming the type curve. It sounds like that's mostly a function of the new completion design. But is there anything from a location standpoint that's also driving the outperformance? It seems like most of the wells have kind of been located in the southern part of your footprint. I guess what I'm trying to ask is would you expect similar outperformance as you sort of eventually move towards the north?

[Gil Goodrich:]

Yes. Hi, Phillips. This is Gil. Good morning. Great question. Yes. So obviously, it's rocks that's driving that in addition to the things that Rob outlined, which is the completion design, which has been a bit of an evolution over the last few years both ourselves and working with our peer partners in the play to get down to what we think is best practices in terms of finding the best IRR sweet spot if you will. So clearly Bethany-Longstreet is core of the core delivering fantastic results. As you go north and we've said this for a while, the quality of Haynesville diminishes ever so slightly. And we believe and have said this for several years now that our Greenwood-Waskom acreage where we do plan to drill some wells sometime later this year going into early 2022 is maybe 10% -- 5% to 10% below what we see at Bethany-Longstreet and we're coming up with that based on a number of things, Phillips. One is the old historical wells that we drilled back in the 2009, 2010 range and we can compare those wells results with the old wells we drilled at Bethany-Longstreet. But I think more importantly, Comstock a private company called Pine Wave, Trinity Operating and others have been drilling all around our Greenwood-Waskom acreage over the last couple of years and seeing really, really good results. So I think where we would be today is, we would guide towards whereas Bethany-Longstreet might be 2.5 Bcf per 1000. We think 2.3 Bcf per 1000 feet is probably the best read on that area based on the results that we've seen over the last couple of years from wells drilled around us that are longer, lateral, tighter spacing and higher proppant wells.

[Phillips Johnston:]

Okay. That's perfect. I appreciate all those details. And then I guess the company that's about to go public has posted some very impressive results in the middle Bossier formation. Obviously that hasn't been a focus for you guys. But can you remind us of what you've said about that zone as it relates to your acreage footprint?

[Rob Turnham:]

Yes. Phillips, this is Rob. And thanks for your questions and support. We really don't think we have great middle Bossier. The further south you go in the play the better the Bossier is and correspondingly the worst the Haynesville is. So where we are, we're just not counting on any potential in the middle of Bossier. We may ultimately find that it can work in certain areas, but we would rather everyone just focus on the Haynesville across our block.

[Phillips Johnston:]

Sounds good, guys. Thank you.

[Rob Turnham:]

Thanks, Phillips.

[Operator:]

Our next question will come from Noel Parks with Tuohy Brothers. Please go ahead.

[Noel Parks:]

Good morning.

[Gil Goodrich:]

Good morning, Noel.

[Noel Parks:]

I just had a couple of questions. Just one quick one. On the acquisitions this drill to earn that you put together. Is -- just curious kind of what vintage or when roughly were the -- was that original leasing done? I was just curious about what the royalty was like on that? How it compares to your sort of the Haynesville average?

[Rob Turnham:]

Hi, Noel. This is Rob. Yeah. Interesting and good question, it varies really. If you look at the 4,000 net acres that we've acquired throughout 2020, some of that acreage was held by production in particular from shallow wells. And as Gil mentioned, the companies that owned it, couldn't afford really to -- or chose not to raise the capital to develop the property. And so, if you don't think you can, or you don't want to develop your Haynesville, you're really faced with two things sell the property. And even though, people are allocating pretty good high prices per acre, it may not be what you want to sell it. And we're able to as Gil said, drag the rigs and drill, and in many cases multiple wells. And the revenue generated from their overriding royalty interest, generates a good bit more money to them, than what they would get by just selling the undeveloped acres. So, I think it's a win-win for the seller. It's a win-win for us. We're getting similar net revenue interest to what we have on the rest of our acreage. And all we have to do is shuffle the drilling schedule around such that, we can incorporate those obligation wells, if you will to capture the acreage. So, so far it's worked extremely well for us. And it's worked extremely well for the seller. And we welcome other opportunities. And in fact continue to evaluate additional drill to earn opportunities.

[Noel Parks:]

Great. Thanks. And I think you went over this, but just to make sure I understand, I did notice especially in the 7,500-foot type curve. The addition, I think you had, now is the average of 12 Goodrich wells in there. So as you go further to the right and it sort of looks like, the wells get closer to the type curve that is mostly just an artefact of, the production being dominated by the older wells, right? Because...

[Rob Turnham:]

Yeah. That's a great point. I probably should have -- we probably should have put that in our remarks. We've always talked about the more recent wells being better stimulated. And overtime pulling up that curve, which is, if you look back at some old presentations, that's exactly what has happened.

[Noel Parks:]

Right.

[Rob Turnham:]

And it's fewer wells that were under-stimulated. And so, it's a combination. When you combine the 12-well average on page 16, it's not 12 wells, 32 months out. That's -- those are the first few wells that we drilled. And at the tail end of it it's, probably one well. And then overtime, as the completion recipes have evolved, and we've drilled more recent time wells. That's why you see the -- for a month one through 28, that's why you see that those wells outperforming the curve by a dramatic amount.

[Noel Parks:]

Great. Thanks. That's all I had.

[Rob Turnham:]

Thanks, Noel.

[Operator:]

This concludes our question-and-answer session. I would like to hand the conference back over to Gil Goodrich, for any closing remarks.

[Gil Goodrich:]

Thank you everybody. We really appreciate you participating in the call this morning. And we very much look forward to reporting our first quarter results in early May. Thank you.

[Operator:]

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.