Edited Transcript of GDP.A earnings conference call or presentation 11-Aug-20 3:00pm GMT

Moving to Slide 5. We show our year-end 2019 SEC proved reserves of 517 Bcfe, which has a present value of just under $300 million using the SEC mandated pricing and discounted at 10%. The pie charts on the right illustrate the split of the year-end reserves by commodity, area and producing versus undeveloped reserves.

On Slide 6, we have again updated our cap table as of the end of the second quarter. At the end of the second quarter, we had total net debt of $107.7 million with approximately $95 million outstanding under our senior credit facility. At the end of the quarter, net debt-to-EBITDA on a trailing 12-month basis remains less than 1.5x.

On Slide 7, we show our annual growth and net production volumes over the past several years, including the midpoint of our guidance for 2020 of approximately 140 million cubic feet per day. As I said, our current strategy is to remain in maintenance mode with roughly flat production levels during 2020 with a significantly reduced CapEx program.

Moving to Slide 8. We have updated our hedging summary, which shows the volumes, type and prices of our current natural gas and crude oil hedges. With the recent strength in the future strip prices for natural gas, we recently layered in additional natural gas hedges for a portion of 2021 and the first quarter of 2022, which raises our total hedge position to 70 million cubic feet per day for all of 2021 and the first quarter of 2022, with a blended average price of approximately $2.55 per Mcf. We view this as prudent risk mitigation, while retaining meaningful upside to an improving natural gas market and represents approximately 50% of the current production rate hedged through March of 2022.

Finally, we provide details of our current 2020 guidance on Slide 9, where we expect to have drilled 12 gross and 5 net Haynesville wells by the end of the year. While the lateral length may vary from well to well, we estimate the blended average lateral length for 2021 will be approximately 8,500 feet. While we have not updated our full-year guidance, we have elected to participate in 4 nonoperated wells with a blended average working interest of approximately 17%, which are currently expected to be turned in line or turned to sales in the first quarter of next year. We have adjusted our full-year budget to accommodate for the participation in these wells. However, our Board reviews and approves our CapEx budget quarterly with the ability to speed up or reduce the pace of development.

And with that, I will turn the call over to Rob Turnham, our President.

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Robert C. Turnham, Goodrich Petroleum Corporation – President, COO & Director [3]

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Thanks, Gil. Revenues for the quarter adjusted for cash settled derivatives totaled $27.8 million, comprised of $20.5 million of oil and natural gas revenues and $7.3 million of cash settled derivatives. Average realized price, including cash settled derivatives, was $2.21 per Mcf equivalent for the quarter versus $2.32 in the previous quarter. Our per unit cash operating expense, which is defined as operating expenses, excluding DD&A and noncash G&A was $1.01 per Mcfe, generating a cash margin of 56% for the quarter. Very importantly, if you bake in our cash interest expense of $1 million, our total cash expense was $1.09 per Mcfe, which compares very favorably to our peers.

In fact, we will incorporate 2Q financials and work this slide into our future presentations.

Capital expenditures for the quarter totaled $10.2 million, of which nearly all was spent on drilling and completion costs associated with Haynesville wells. We conducted drilling operations on 6 gross, 2.2 net wells and netted 1 gross, 0.8 net wells in the quarter. We exited the quarter with 13 gross, 4.7 net wells in drilling or completion phase, with 6 gross, 2.8 net wells completing at the end of the third quarter, which, as Gil said, will allow for a surge in production as we head into the fourth quarter where we see much higher natural gas prices. Interest expense totaled $1.7 million in the quarter, which included cash interest of $1 million incurred on the company’s revolver and noncash interest of $700,000 incurred on the company’s convertible notes and amortization of issuance cost on the revolver. As everyone likely knows by now, all of our current activities are centered in the core of the Haynesville, beginning on Slides 10 and 11.

With the announcement of incremental acreage in today’s press release, we are currently — have approximately 24,000 net acres in the core of the play, which meaningfully adds to our inventory. Our acreage in North Louisiana is over 75% undeveloped and 75% operated. We estimate over 1 Tcf of reserve exposure at 2.5 Bcf per 1,000 feet of lateral and 880 spacing feet spacing in North Louisiana alone versus our booked reserves of about 1/2 of a Tcf. We also maintain approximately 3,000 net acres held by production in the Angelina River Trend of the Shelby Trough. The Haynesville and Bossier formations are book perspective on our Shelby Trough Angelina River Trend acreage.

The evolution of the completion design in the Haynesville as shown on Slide 12 has transformed the play into one of two premier gas basins in the country. Our results, as shown on Slide 13, are very consistent. All of our acreage has now been derisked and we are in development mode, drilling predictable wells in proven areas and connecting wells into existing pipes with excess capacity. We continue to outperform our type curves.

And on Slide 14, we track our wells versus 309, 4,600 foot lateral industry wells drilled in the core. Industry pumped an average of 3,100 pounds per foot. But as you can see, the older wells are underperforming the newer wells, as average proppant is lower on these older wells. Our 6 wells shown in green were stimulated with approximately 4,100 pounds of proppant per foot. And tighter clustering and — cluster and interval spacing are exceeding the industry average composite results and our 2.5 Bcf per 1,000 foot type curve to an estimate of approximately 2.7 Bcf per thousand feet. Linear regression of completions to EUR shows a clear correlation between proppant loading and cluster and interval spacing and we expect our more recent well to pull up the composite curve over time from this optimization.

Slide 15 reflects our 7,500-foot curve, where we now show a composite of 225 industry wells with average proppant concentration of approximately 3,000 pounds per foot, which, for the most part, fits our 2.5 Bcf per 1,000 foot type curve. However, the older wells fall off as they are understimulated like the 4,600 foot laterals and fall below the curve. Our more recent operated 7,500-foot wells are outperforming materially to a composite estimate of approximately 2.8 Bcf per thousand feet due to higher proppant concentration and tighter cluster and fracked able spacing.

Slide 16, which now shows a composite result from 225, 10,000-foot laterals with an average of 3,000 pounds per foot of proppant are for the most part, tracking our 2.5 Bcf per 1,000 foot type curve. Our 9 wells, which average approximately 9,600 feet of lateral and 3,500 pounds per foot of proppant are for the most part, tracking, again, our 2.5 Bcf per 1,000 foot curve. However, we have not recently fracked 10,000-foot wells with tighter interval spacing. So we believe these results will improve once implemented. As we have stated before, we believe our well performance speaks for itself and is driven by a number of factors: one, quality of our acreage; two, an optimum completion design where proppant concentration, cluster and interval spacing and pump rates provide a material difference in results; and finally, flowback technique, that minimizes daily drawdown, flattens the decline curves, provides high recoveries of gas in place and most importantly, maximizes returns.

Our economics, as shown on Slide 17 through 19, which reflect the recent 15% to 20% reduction in service costs are as good as we have seen them in the basin when baking in our hedge book and strip pricing. The outperformance of our curves on the 4,600 and 7,500-foot laterals and service cost deflation across all wells has created a unique situation. As you can see at $2.50 gas price, we can generate approximately 100% or greater IRRs on long laterals due to the outperformance of curves and recent reduction in costs. As a reminder, the Haynesville economics are driven by high volumes, attractive netbacks relative to Henry Hub as compared to the other basins. Low lifting costs and severance tax abatement until the earlier of 2 years will payout of the well.

In summary, our team is executing well. Our balance sheet is in good shape with low debt metrics. Our margin at 56% competes with any basin, and we have a nice hedge position that is minimizing our commodity price risk yet leaves plenty of room to enjoy better pricings as we — that we see in 2021 and beyond.

With that, I’ll turn it back to Jason for Q&A.

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Questions and Answers

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Operator [1]

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(Operator Instructions)

The first question comes from Duncan McIntosh from Johnson Rice.

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Austin Joseph Aucoin, Johnson Rice & Company, L.L.C., Research Division – Assistant [2]

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This is Austin on for John. I was wondering if you all could provide some additional color around the acquisition. Specifically, how many new locations does this bring net to Goodrich? When would you all like to pick up a rig to start working there? And do you all see any additional opportunities under a similar filter earn structure?

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Robert T. Barker, Goodrich Petroleum Corporation – Senior VP, Controller, CAO & CFO [3]

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Yes, Don (sic) [Austin] this is Rob. It’s really comprised of 2 sections in the Bethany-Longstreet area, and it is set up for really shorter laterals, but 16 locations, within those 2 sections at 880 feet apart. So quite a bit of running room. Obviously, 912 acres divided by 1,280, which would be the sections would give you our average working interest in those 2 wells. And we’ll be the operator on those sections. As far as other deal flows. As you can see, that’s just a portion of what we’ve added for the year since we’ve gone from 22,000 to 24,000. So we continue to kind of chip away at some bolt-on opportunities. And there are packages in the market, currently, that we are in evaluation phase 1. So I think the deal flow is certainly higher than it has been, and we’ll see if we can continue to add to our position. But one thing we’re not going to do is lever up for undeveloped locations. Balance sheet is the key here. And obviously, we have over 16 years of inventory as it is. So I think we just need to be conservative. If we can pick things up, where we have no upfront costs like what we’ve done here in 2020, that really fits in well for us because we can work that into our CapEx budget and capture the opportunity without upfront cash.

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Austin Joseph Aucoin, Johnson Rice & Company, L.L.C., Research Division – Assistant [4]

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I appreciate the color. And for my follow-up, I was wondering, you all have stated 3Q with a high point for a turnaround activity this year. And you all active on the drilling front in 2Q in preparation for that. Could you provide some color around your production trajectory for the second half of the year and maybe your early thoughts on the 2021 program, especially the current strip holds even or it gets better?

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Walter G. Goodrich, Goodrich Petroleum Corporation – Chairman & CEO [5]

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Yes. So Don (sic) [Austin] , this is Gil. I guess the short answer would be, we’re not really ready to give any change to the overall plan at this point in time. We certainly do like where natural gas is setting up. We’ll be reviewing second half activity as well as a preliminary look at 2021 with our Board here coming up in a few weeks. But I think for right now, as Rob just said, balance sheet is the number one issue, and we’re continuing to take a more cautious mode and just staying in maintenance. We did allude to a little bit of perhaps reduced volumes coming up in the third quarter by delay in activity, but we’re expecting a very robust fourth quarter in production volumes, and we’ll see where that leaves us going into next year.

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Operator [6]

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Next question comes from Jeff Grampp from Northland Capital Markets.

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Jeffrey Scott Grampp, Northland Capital Markets, Research Division – MD & Senior Research Analyst [7]

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Maybe if I can go at the ’21 commentary, maybe a little different way and certainly not going to pin you guys down, too firm on anything. But maybe directionally, how you guys are viewing maintenance CapEx levels trending into next year versus this 40 to 50 level that were this year? I guess, I’m more kind of thing internally, you have some cost efficiencies, you have an inventory of wells in process that I imagine provides a bit of a capital efficiency tailwind for you. So does that suggest that maintenance CapEx could trend down next year? Or are there to be some other factors at play where maybe that’s a little too ambitious of an expectation?

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Robert T. Barker, Goodrich Petroleum Corporation – Senior VP, Controller, CAO & CFO [8]

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Yes. Jeff, this is Rob. You’re right on as to your analysis. We think we could hold volumes flat with less capital than what we spent this year. The question is whether that’s all we do in a $2.75 gas environment. I think it’s unlikely that all we’re going to do is just target holding volumes flat. We can even spend a little bit more money perhaps than holding volumes flat and grow to some degree. You won’t see us likely grow dramatically, but certainly getting to a 10% growth, generating substantial free cash flow and spending less money is really an option that the Board will consider as we set our budget in December.

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Jeffrey Scott Grampp, Northland Capital Markets, Research Division – MD & Senior Research Analyst [9]

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Got it. Really helpful. And can you guys just touch on your comfort level with your current liquidity position? I understand leverage is very healthy, especially relative to a lot of peers out there. But just your overall comfort level with liquidity. And if you have any expectations at least directionally on the borrowing base redetermination in the fall?

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Walter G. Goodrich, Goodrich Petroleum Corporation – Chairman & CEO [10]

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Sure, yes. This is Gil. So obviously, the liquidity is what it is. We’ve given the borrowing based number and the outstanding under the revolver. So we have a $25 million of liquidity currently. We will be going through a review next month with our bank group, and we will not prejudge them or what they decide the borrowing base should be. However, the strip price that we’ve talked about here on this call has improved dramatically. So as you compare by looking back to May, when we put the last revolver borrowing base in place, the strip price is obviously considerably higher today. So we think that bodes well for the new borrowing base. And then the hedges that we just recently layered on and get out all the way through the first quarter of 2022 also will be positively impactful when you compare that with what’s likely to be the bank’s price deck.

So would we like to have some more liquidity? Sure. I think everybody probably would. Are we comfortable? Yes, we are. And we’re operating in a mode that we think is very careful with the balance sheet is the #1 priority.

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Operator [11]

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Next question comes from Phillips Johnston from Capital One.

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John Phillips Little Johnston, Capital One Securities, Inc., Research Division – Analyst [12]

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First question is on CapEx. I guess through the first 6 months, you spent about $29 million, which is about 63% of the budget at the midpoint. I know the net well pops for the second half of the year, pretty close to what came online in the first half. So can you talk about what factors you — caused your spend rate to sort of creep a little bit lower in the back half of the year?

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Robert T. Barker, Goodrich Petroleum Corporation – Senior VP, Controller, CAO & CFO [13]

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Sure, Phillips. And we basically built a DUC backlog, as you’ve seen currently planning to complete 6 gross, 2.8 net wells for the remainder of the year. But we basically drilled 13 gross, 4.7 net wells that have yet to be completed. So even though you tie CapEx to turn in line, we’ve incurred a good bit of drilling cost that we won’t have in the back half of the year or heading into 2021.

So as Gil said, we watch it quarterly. You’ll see us, based on where commodity prices are either defer or accelerate, capital based on what the Board wants to do relative to a budget. But a lot of the costs that we’ve incurred to date have been drilling wells to put in our DUC inventory. And so just on paper, that means less total well cost for wells that are being turned in line in the future.

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John Phillips Little Johnston, Capital One Securities, Inc., Research Division – Analyst [14]

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Okay. That makes sense. And then, I know it’s early on ’21, but Rob, I just wanted to clarify your comments that you could possibly look to grow 10% next year was in free cash flow. Obviously, your exit rate this year is going to be pretty considerably higher than sort of the full-year average. So would that 10% growth be directionally versus the exit rate or the full-year average?

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Robert T. Barker, Goodrich Petroleum Corporation – Senior VP, Controller, CAO & CFO [15]

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Yes. Yes, Phil, it’s a good question. I think it’s going to be — the number I quoted was really year-over-year. However, we still should be growth over the exit rate all. So it just won’t be double digit. And of course, that double — the 10%, for example, is predicated on spending a certain amount of money. We just won’t get out ahead of our Board, but it’s awfully appealing when you bake in less capital and grow 10% year-over-year and still generate substantial free cash flow, which is what our modeling suggests. But again, December will be the date that we kind of put the 2021 budget together, and we won’t jump ahead of our Board as to kind of where we want to go with that.

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John Phillips Little Johnston, Capital One Securities, Inc., Research Division – Analyst [16]

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Yes. That makes sense. I mean it’s a pretty impressive combination either way.

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Operator [17]

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(Operator Instructions)

There are no more questions in the queue. This concludes our question-and-answer session. I would like to turn the conference back over to Gil Goodrich for any closing remarks.

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Walter G. Goodrich, Goodrich Petroleum Corporation – Chairman & CEO [18]

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Thanks, everybody. We appreciate you participating this morning, and we look forward to reporting third quarter to you in early November. Thank you.

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Operator [19]

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The conference is now concluded. Thank you for attending today’s presentation. You may now disconnect.