Goodrich Petroleum Corporation
Q1 2017 Earnings Call Transcript

Published: 13 May 2017

[Operator:]

Good day, and welcome to the Goodrich Petroleum Corporation First Quarter 2017 Earnings Conference Call. All participants will be in listen-only-mode [Operator Instructions]. After today's presentation, there will be an opportunity to ask questions [Operator Instructions]. And please note this event is being recorded. And now I would like to turn the conference over to Gil Goodrich, Chairman and CEO. Please go ahead.

[Walter Goodrich:]

Thank you. Good morning, everyone. We are pleased to have the opportunity to share our first quarter results and current activities with you this morning. As a reminder, our current operations and capital expenditures are focused on the reemerging Haynesville Shale play, where longer laterals and high proppant wells are delivering outstanding results. As most of you are aware, the Haynesville is undergoing a significant transformation with longer laterals of as much as 10,000 feet being drilled and coupled with changes in completion design and material increases in proppant volumes. We initiated our renewed Haynesville activity in the fourth quarter of last year with the participation in 2 non-operated 10,000-foot high proppant wells, which have exceeded expectations and are on track to deliver rapid payback and outstanding rates of return. Additional recent activity around our acquisition has further delineated the value and potential of our acreage, which is well positioned within the core of the play. I would like to direct your attention to the earnings slide, which can be found on our website if you have not already accessed the slide deck. I would like to point everyone to the disclaimer information on Slide 2. And then we'll ask you to turn to Slide 3, which provides several key points in the company overview section. Included in this are the opportunities we have with our enhanced balance sheet, leveraged to the reemerging Haynesville Shale and therefore, ability to rapidly grow production volumes, reserves and EBITDA. Based on our current rate of development in 2017, the inventory of Haynesville development locations is approximately 20 years. Also during the first quarter, we initiated another important step in our evolution with the process of listing with the New York Stock Exchange. We completed the process early in the second quarter. And the company's stock is now listed on the NYSE market under the symbol GDP. In December, our board approved a 2017 capital expenditure budget focused on Haynesville Shale development of $40 million to $50 million, which includes approximately 9 to 12 gross Haynesville wells and 4 to 5 net Haynesville wells being drilled in 2017. We believe this level of development will dramatically transform the company. And we are projecting these wells will lead to greater than 200% production growth and rapidly growing EBITDA from the high-volume Haynesville wells. On Slide 4, we highlight several important points from the first quarter. During the quarter, we began our initial operated development activity and incurred capital expenditures of approximately $6.2 million related to drilling, completion, workover and facilities. While we only initiated our operated activity during the first quarter, production has started to materialize from the non-operated activity late last year and several workovers in the Haynesville. For the quarter, production grew sequentially over the fourth quarter by 20% to approximately 26 million cubic feet of gas and equivalents per day and was led by natural gas volumes, which grew by 36% sequentially as oil volumes remained relatively flat over the period. With the pending completion of 2 operated wells with high working and revenue interest, we are anticipating a significant further production ramp in the next 30 days or so. The balance sheet remains in good shape with approximately $38 million of cash and net debt of just $21 million at the end of the first quarter. Operationally, we have drilled and completed our Wurtsbaugh 26H-1, which we have a 74% working interest. And we expect to begin flowback within the next week. We have drilled, cased and begun completion operations on the Wurtsbaugh 25 and 24H-1 in which we have a 69% working interest. And we expect to begin flowback by the end of this month. As I've mentioned a moment ago, we are projecting addition of these 2 wells to our production mix will result in a significant increase in our net daily production. If you will turn to Slide 5, you'll see our growth in proved reserves at year-end 2016, where we were able to add over 200 Bcf of proved reserves from the Haynesville Shale. On Slide 6, you will see our updated production profile with the average daily rate during the first quarter of approximately 26 million cubic feet of gas equivalents per day and our current rate of approximately 29 million cubic feet equivalent per day, which is 80% natural gas volumes. And you will see our year-end guidance of approximately 50 million cubic feet of gas equivalent per day. Turning to Slide 7. We present our current hedge position for future natural gas production volumes. We believe hedging is an important risk mitigation tool. And we have begun to layer in hedges to protect cash flow in 2017 and 2018. While we will clearly have more work to do as additional volumes come online, we currently have 18 million cubic feet per day or 78% of current natural gas production hedged at prices between $3 and $3.60 for 2017 as we have recently also added hedges for 2018 covering 12 million cubic feet per day or approximately 52% of current natural gas production at just over $3 per Mcf. With that, I will turn the call over to Rob Turnham to review the Haynesville Shale as well as updated activity and performance from our wells and key industry wells. Rob?

[Robert Turnham:]

Thanks, Gil. Our revenues for the quarter were generated from an average realized price of $4.05 per Mcf equivalent, comprised of $2.89 per Mcf and $50.12 per barrel. Our operating expenses included many non-recurring and non-cash items for the quarter. LOE was $4.3 million for the quarter, which included $2.1 million of workover expense. LOE excluding workovers was $2.2 million or $0.94 per Mcf equivalent. Per unit LOE will continue to fall as we add significant volumes from the Haynesville, which carry an initial estimated per unit LOE cost of approximately $0.05 per Mcf. Production and other taxes as well as G&A will also trend lower on a unit production basis because the Haynesville has severance tax abatement until the earlier of payout or 2 years. And we expect G&A to remain relatively flat during the year while we post significant production volume growth. Of our total G&A for the quarter of $4.5 million, $1.9 million was non-cash, stock-based compensation and rent amortization and $2.6 million was cash, which included certain year-end costs. Interest expense totaled 2.2 million for the quarter, which included cash interest expense of $300,000 and $1.9 million of non-cash interest and amortization of debt discount expense associated with our second lien notes. Moving back to our slide deck. Slide 8 shows our core properties, where we retain approximately 48,000 gross, 23,000 net acres in the Haynesville with 35,000 gross, 16,000 net acres in the North Louisiana core. In addition, we have 176,000 gross, 128,000 net acres in the TMS and 32,000 gross, 14,000 net acres in the Eagle Ford. Slide 9 breaks out our approximate acreage position for the Haynesville, where the vast majority of our capital plans this year will be spent in the North Louisiana core position, where we are focusing all of our activities. As shown on Slide 10, we have 85 old vintage short lateral Haynesville wells drilled on our North Louisiana acreage and 235 gross, 96 net remaining locations with at least half of those being 10,000-foot laterals. We have gridded our acreage with a plan to maximize long laterals and expect to be in a position to swap acreage or drill joint wells with offset operators in an effort to further increase our long lateral inventory. We are also targeting additional bolt-on acreage acquisition opportunities in the core to add to our inventory. On Slide 11, we show a cross-section of the Haynesville from our Angelina River Trend acreage in East Texas through our Caddo Parish acreage in North Louisiana. The quality of the section over our acreage is very consistent. And in the Angelina River Trend acreage, we have very good Bossier Shale play developed as well. When analyzing the logs and mapping the thickness of the Haynesville that has a minimum of 12% porosity by log, you will see that both of our East Texas and North Louisiana acreage positions are situated in the core with very good thickness, which is supported by recent well results. Slides 12 and 13 show the evolution of drilling and completion techniques designed to get more footage drilled at lower cost per foot and better near-wellbore stimulation through innovative completion designs. This new completion design is allowing for higher recovery factors at the gas in place, which is yielding higher EURs per 1,000 feet and most importantly generating very high rates of return. We haven't had many well results to post on our industry activity map on Slide 14 of late. But that will be changing soon with our well results and those of offset operators. For those that are looking for the first time

[Walter Goodrich:]

Thanks, Rob. The next few months and quarters are going to be a very exciting time for the company and its shareholders as we truly begin to see the results of our Haynesville-focused development strategy and the efforts we have made to implement the strategy. And we look forward to sharing those results with you as they come in. That concludes our prepared remarks. And I will turn it back over to the operator for questions.

[Operator:]

Ladies and gentlemen, we will now begin the question-and-answer session. [Operator Instructions]. The first question today comes from Neal Dingmann with SunTrust. Please go ahead.

[Raymond Leong:]

This is actually Ray on for Neal. Just looking on the completion side, we've seen you guys and others kind of push the limits on the sand. And I guess, just as you -- are you guys kind of seeing diminishing returns as you move up to 5,000 pound per foot? And what do you kind of envision the basin settling down at?

[Walter Goodrich:]

Yes, great question. This is Gil. The quick answer would be, no, we've not seen any diminishing returns up to 5,000 feet, in fact -- 5,000 pounds. In fact, the industry-leading wells have been up around 5,000 pounds per foot and obviously the longer laterals. Where we go from here, I think, will be interesting to see. Could we go to 6,000 or 7,000 pound per foot? Perhaps. But we start running across some cost issues, number one, and design issues in terms of how much proppant we can pump over a given interval stage link. So I think what you're going to see from us is 4,000 to 5,000 pounds per foot, probably in that range, makes the most sense. We can tell you we just completed the Wurtsbaugh 26H-1. That was right at 5,000 pounds per foot. So for the time being, we're pretty comfortable. Perhaps, you'll see us a little below 4,000 pounds. But in that 4,000 to 5,000 feels like the sweet spot right now.

[Raymond Leong:]

Okay, sounds good. And with the next 3 wells that you guys plan to drill, those 10,000-foot lateral wells, are you guys going to be kind of doing anything different in terms of like targeting or completions or something else?

[Walter Goodrich:]

No, we don't plan on doing anything different. All 3 of those wells planned for the second half this year are currently planned to be 10,000-foot laterals and again within the proppant range that I just described.

[Operator:]

Our next question comes from John White with Roth Capital. Please go ahead.

[John White:]

Good morning guys, thanks for taking my call.

[Walter Goodrich:]

Good morning ,John.

[John White:]

Good morning. First, a comment. The cross-section in your slides is just a thing of beauty. I wish more companies would include subsurface detail like that. On the hedges, you've got a pretty good amount of 2017 hedges in place. But with the production, I think, most people are modeling, there's room to add more. Do you want to tell us a little bit about your thoughts on hedging for 2017 volumes?

[Walter Goodrich:]

'17 or '18, John?

[John White:]

Well, I'd like to hear your thoughts on both. You've got a lot of hedges on '17, but there could be room to add a little bit more, I would think.

[Walter Goodrich:]

Yes. So it's really kind of 2 different thought processes between the 2 years. For '17, you're right, we've got a pretty good position. Currently, I think what we'd like to see is these 2 wells come online. As we mentioned, we expect by the end of this month, both wells will be online. So we'll see what kind of volumes, what kind of projection of volumes that provides us throughout the balance of this year. And yes, I think you will see us probably add in some additional protection in the balance of 2017 once those wells are on. In terms of 2018, I think again we'd like to see these new wells come on and see where we think those wells will project out for 2018 in terms of the volume. We're a little bit challenged with just straight swaps in 2018. $3 obviously works today. But we are mindful of the fact that as proppant costs are going up, other inflation could take place in the second half this year. And we want to be very careful that we don't lock ourselves into somewhere where our margins are getting squeezed from the bottom. So we have a very active hedging committee. We're looking at it almost daily and can say with confidence that as we get into the second half of this year and these 2 wells run, you will see us adding volumes probably in both years but certainly in 2018.

[John White:]

Okay. That's well-thought-out. And is there a well planned or are you planning on participating in a well in Greenwood-Waskom in 2017? Or are they all in Bethany Longstreet?

[Robert Turnham:]

John, this is Rob. No plans currently for Greenwood-Waskom in 2017. We do have plans early '18. I might note, our friends at Comstock, I guess, have announced that they have a multi-well plan up in Greenwood-Waskom on their joint venture acreage, which we're confident will make very good wells as well. So just for now, we're focusing in the Bethany Longstreet area, in addition to some non-operated activity, just small interest over on what we call Swan Lake/Thorn Lake area.

[John White:]

It's an active play and you're right in the middle of it. So good luck, and congratulations.

[Walter Goodrich:]

Thanks, John.

[Robert Turnham:]

Thanks, John.

[Operator:]

The next question today comes from John David with Heikkinen Energy. Please go ahead.

[David Heikkinen:]

Well, it's actually David Heikkinen. That's a new one. I wasn't expecting to be called John today. Just one question on how you've seen your operated and non-operated well costs compared to, really you're all in the 10,000-foot laterals, that $10 million target?

[Walter Goodrich:]

Yes. So David, this is Gil. I would say the biggest difference, David, so far has been on interval spacing and therefore how many stages are getting pumped. We've seen some variability. I think if you look at the slides, I can't remember, the 11 and 12 or 12 and 13 in the presentation, you'll see from as tight as under 100 feet of interval spacing per stage to as much as 215, 225. We're not sure where the sweet spot is there. We've seen some excellent results from wells that are just over 200 feet per stage. Our bias is to come down a little tighter done that, maybe 150 to 200 in that range. And obviously, the number of stages that you add causes cost to go up. In terms of the drilling, we haven't seen a whole lot of variability. These wells are drilling pretty darn quick and easy, the Haynesville drills very well. So I don't -- and that's a relatively small percentage of the overall completed well cost. It really is in completion design. And the biggest variable there is interval link, number of stages and a little bit of the proppant per stage.

[David Heikkinen:]

So your wells will be 150-foot stage lengths and these first couple of wells, 5,000 pounds per foot and see how they perform?

[Walter Goodrich:]

Yes. And I would say we have made a caveat that a little bit, 150 to 200.

[David Heikkinen:]

To 200.

[Walter Goodrich:]

Yes, exactly.

[Robert Turnham:]

And 4,000 to 5,000 pounds per foot.

[David Heikkinen:]

I thought you said the first well was a bit closer to 5,000, but...

[Robert Turnham:]

Yes, for our first well, it is. Yes, this is Rob, David. First well was 5,000 pounds per foot, second well, 4,000 pounds per foot.

[David Heikkinen:]

Okay. And then just how do you plan to update the market on the well results for the first well? I mean, how long do you want them to produce? Like what are you thinking about as far as the -- it's clearly important and there's urgency, and then there's also duration of cumulative volumes. So how are you thinking about that?

[Robert Turnham:]

Yes, this is Rob again. We have such leverage to the play, the volumes are certainly meaningful to the company. The information is important to our investors. So I think once we have a well that is online and producing and has established kind of a peak rate for a period of time, I think we'll go ahead and announce that, which means -- which likely means our shorter lateral with 5,000 pounds per foot could get announced ahead of the longer laterals just due to timing factors. So I think until we get a number of these wells under our belt and the volumes obviously are going to grow significantly, it's important to us to go ahead and announce those results. And then we'll continue to do, like we've done on the ROTC wells, update the production both on our decline curves as well as cumulative production, like we did in the press release.

[Operator:]

Our next question comes from David Beard with Coker & Palmer.

[David Beard:]

Thank you gentlemen and good morning.

[Walter Goodrich:]

Good morning David.

[David Beard:]

A small question, I noticed the longer well is 9,000 feet. I know you'd also talked 10,000 feet. Just what are some of the factors that may vary the horizontal length in that well or a well?

[Walter Goodrich:]

Yes, David. You've seen this from others as well. But the main differentiating factor is when you get out beyond 9,000 feet, if your mud motor goes out on you or your bit is worn out and you've got to make a trip, you've got a decision to make, "Do I make a long trip back, pick up a new bit and go back in to finish up another a little bit of footage? Or do I just take what I have?" And in the case of our 25 and 24 Wurtsbaugh well, that was really where we were. We had a decision to make, "Do we pick up a new bit and go back in?" We felt like our MWD issues, "Do we pick up a new bit or not?" And we felt like it made sense to save those incremental dollars and just take what we had.

[Operator:]

[Operator Instructions]. And currently showing no further questions, I would like to turn the conference back over to Gil Goodrich for any closing remarks.

[Walter Goodrich:]

Okay, thank you. David, you dropped off on us there, I expected a follow-up. But at any rate, hopefully we answered your question. We thank you all for your participation. We do intend to file our 10-Q later today with the SEC. And as Rob said, we look forward to sharing results with you as these wells come on and reach a sustained rate. Thank you, everyone.

[Operator:]

Ladies and gentlemen, the conference has now concluded. Thank you for attending today's presentation. You may now disconnect.