Goodrich Petroleum's (GDP) CEO Gil Goodrich on Q2 2018 Results - Earnings Call Transcript

Goodrich Petroleum Corp. (NYSE:GDP) Q2 2018 Earnings Conference Call August 7, 2018 11:00 AM ET

Executives

Gil Goodrich – Chief Executive Officer

Rob Turnham – Chief Operating Officer

Analysts

Neal Dingmann – SunTrust

Joe Allman – Baird

John White – Roth Capital

David Snow – Energy Equities

Operator

Good day and welcome to the Goodrich Petroleum Second Quarter 2018 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today's presentation, there'll be an opportunity to ask questions. [Operator Instructions] Please note this event is being recorded.

I would now like to turn the conference over to Mr. Gil Goodrich, CEO. Sir, please go ahead.

Gil Goodrich

Good morning, everyone. Thank you for joining us this morning, and we are pleased to have a chance to share with you our second quarter results and also provide you an update on recent activity. We’ve again prepared a slide presentation in conjunction with the call this morning. And we invite you to follow the slide deck during our prepared remarks.

You can access the slide presentation on the Goodrich Petroleum website entitled Earnings Call Slides Second Quarter 2018. Our standard disclaimer, forward-looking statements and risk factors are highlighted for you on Slide 2.

During the second quarter, we achieved excellent acceleration of both production and cash flow, which has continued into the third quarter and positioned us well to achieve our stated goals and guidance for 2018. I'll begin with a few highlights from the second quarter and an update on recent activity, which you will find on Slide 3.

We continued a robust development pace in the Haynesville with second quarter capital expenditures of approximately $31 million, and we remain on track for full year capital expenditures within the previously given guidance range of $85 million to $95 million, all of which will be invested in the Haynesville and on our core acreage in Northwest Louisiana.

In addition, and as a reminder, we have also provided preliminary guidance for 2019, where our board has established a preliminary CapEx budget of $125 million to $150 million, which will further accelerate development of our core Haynesville position and is projected to more than double both production and cash flow, again, next year. In the second quarter, net production volumes grew 66% sequentially over the first quarter to just under 61 million cubic feet of gas equivalents per day.

As I said, this acceleration has continued into the third quarter, with net production thus far in 3Q averaging 75.5 million cubic feet equivalents per day. In addition we have two more operated high working interest Haynesville wells set to come online in the next 30 days, with initial production from our Demmon 34H-1 to begin flowback and production later this week. This ongoing ramp in production and cash flow has positioned us extremely well for a very robust second half of 2018.

With very low LOE increases and severance tax abatement on each new Haynesville well as well as relatively flat cash G&A expenses, we were able to deliver a substantial sequential decrease and per unit operating expenses with these three categories down 37% to 42% versus the first quarter.

As a result, ramping production and declining per unit cost led to solid increases in EBITDA and Bcf of $8.9 million and $9.2 million respectively. In addition, we expect this trend to continue as our production continues to grow going forward.

Moving to Slide 4, we again provide you an overview of the company, including our assets, and in particular, the Haynesville Shale, where we have a 10 to 15 year inventory of development locations and approximately 1.2 Tcf of reserve potential. For those of you who may be new to the company, our common stock is traded under the symbol GDP on the NYSE American, where we continue to work towards providing current and future shareholders a stock with increasing float and liquidity.

The Haynesville provides us a unique opportunity at current gas prices to grow rapidly, and as I have said, our plans and catalyst for 2018 call for rapidly growing production and EBITDA while also keeping our debt metrics at very conservative levels. Following on the second quarter production of just under 61 million cubic feet per day, we are projecting an additional 65% increase in the second half of the year to achieve our Exit Rate guidance of 100 million cubic feet of gas per day equivalent prior to the end of the year.

With two more wells set to come online in the next 30 days, we will soon move further to that goal. On Slide 5, you will find a map showing the location of our primary assets, including the Haynesville, Eagle Ford and TMS as well as a breakout of the SEC-proved reserves by area and our acreage position in each place.

Turning to Slide 6, you will, again, see the chart showing our year-end 2017 SEC-proved reserves and the reserve growth over the past couple of years. Proved reserves grew last year by over 40compared to year-end 2016 to 428 Bcfe. Consistent with our focus and development activities, all of our reserve growth was associated with our core Haynesville Shale assets.

On Slide 7, we present our updated capitalization table. Subsequent to the end of the second quarter, our bank group increased the borrowing base under our senior credit facility to $60 million. We recently began to utilize the senior credit facility and ended the second quarter with $6 million outstanding under the RBL, which added to our second-lien PIK notes, results in total debt of approximately $56 million or $54.5 million of net debt. We remain committed to rapidly growing our production and cash flow while also preserving low debt metrics.

Slide 8 illustrates the robust production growth I mentioned a minute ago with the anticipated further ramp to our Exit Rate forecast of approximately 100 million cubic feet per day and continuing into 2019, where the midpoint of the production guidance we have provided equates to 140 million cubic feet per day as an average rate for next year.

I'll now turn the call over to Rob Turnham.

Rob Turnham

Thanks, Gil. For the quarter, our revenues were $17.8 million from an average realized price of approximately $3.23 per Mcf equivalent, comprised of $2.67 per Mcf and $69.39 per barrel of oil. Our per unit cash operating expenses, as Gil has highlighted earlier, dropped by $0.86 per Mcfe or 32% of our realized natural gas price in the quarter, resulting in a significant expansion of our cash margin.

Cash unit costs were down across the board in all of our operating categories. We expect to see a continuing drop in per unit cash operating expenses as the Haynesville wells are added as they carry very low LOE, no severance taxes until the earlier payout in two payout in two years and attractive gathering amendments.

General, administrative experience was $4.8 million in the quarter, which is $400,000 less than the first quarter. But most importantly, our cash G&A was $3.4 million in the quarter, down a $100,000 from the previous quarter and $0.61 per Mcf equivalent.

As we have stated before, we feel confident we can control our cash G&A, while our volumes grow rapidly, which will continue to lower our unit results and put our G&A metrics in the lower quadrant of our peers. We had operating income for the quarter of $2.1 million and a net loss of $2.7 million of which $2 million was an unrealized loss on commodity derivatives, representing the fair value of our commodity derivative contracts.

Interest expense totaled $2.7 million in the quarter, which includes cash interest of $75,000 incurred on the company's revolver and non-cash interest of $2.6 million incurred on the Company's convertible notes, which includes $1.6 million paid in-kind interest and $1 million of amortization of debt discount.

Moving back to our slide deck, we've included several slides beginning with Slide 9 that show how we trade relative to an approximate 50-company peer group. Review of Slides 9 through 12 will show you that the company is trading at a very low multiple relative to our peers, whether it is enterprise value to consensus EBITDA, net debt to consensus EBITDA or capital efficiency.

In particular Slides 10 and 12, show us as the cheapest stock in the 50-company universe, currently trading at 1.7 times enterprise value to consensus 2019 EBITDA, and with the lowest CapEx to production adds of the 50-company peer group. Our CapEx plans will provide margin expansion, substantial growth in EBITDA relative to the size of our enterprise, and the stock price should follow as we post the numbers on the scoreboard.

Moving on to the Haynesville, beginning on Slide 13, we currently have a 22,000 net acre position with approximately 19,000 in the core of North Louisiana. Our acreage is approximately 80% undeveloped and 55% operated, with approximately 200 locations of blended lateral links with an average of 7,000-foot laterals.

We have gridded our acreage with a plan to maximize long laterals and expect to continue to swap acreage or drill joint wells with offset operators to further increase our long lateral inventory. As Gil said, we estimate over a Tcf of reserve exposure at 2.5 Bcf per 1,000 feet of lateral in North Louisiana alone.

Moving to Slide 14. Activity remains high in the Haynesville, with about 50-rigs running in play. All of our acreage has now been derisked and we're in development mode, drilling wells in proven areas and connecting those wells into existing pipes with excess capacity. We have allocated approximately 70% of our 2018 capital budget to Bethany Longstreet and the other 30% to the Thorn Lake area, where are drilling our Cason-Dickson and Harris wells.

We are very optimistic also about the Greenwood-Waskom area. And as you can see, there are numerous wells permitted in that area. In addition, we still own 3,000 net acres in the Angelina River Trend where BP has been making very good wells. We continue to show an abundance of well results on our decline curve analysis as shown on Slides 15 to 20.

On Slides 15 and 16, we are tracking 59 4,600-foot with an average profit of approximately 3,700 pounds per foot with more than two years of production on a handful of wells. The composite production curve is generally following our 2.5 Bcf per 1,000 foot tight curve as shown in red and our three operative well averages running well above the curve with higher profit loading and tighter interval spacing.

Slides 17 and 18 reflect our two 7,500-foot curves, where we continue to show 87 wells with an average profit concentration of 3,000 pounds per foot in our composite production curve, which again fits nicely with our 2.5 Bcf per 1,000 feet type curve. The older wells included in the composite curve are a handful of under-stimulated wells, and we expect the composite tail results to pull up as the newer wells with higher profit concentrations flow through over time.

Our operated wells here are running on or above the high-case curve. Slides 19 and 20, which show composite results from 35 approximate 10,000 foot laterals with an average of 3,300 pounds per foot of proppant are also tracking our 2.5 Bcf per 1,000 foot curves. Our well, which has a 9,200 feet of lateral and surrounded by wells is running on the 2 Bcf per 1,000-foot type curve.

In general, longer laterals and higher profit loading typically make better wells. Although we are focused on IRR, not EUR, as returns matter more than ultimate recovery of reserves. Our economics as shown on Slides 21 to 23, show how exceptional this play is at current gas prices. At $2.75 to $3 gas, we can generate a minimum of 36% IRR for a 4,600-foot lateral at $2.75 to as much as 76% at $3 gas for 10,000-foot laterals, all with a blended average gathering rate and basis $0.60.

With the recent amendment to our gathering rate on a significant portion of our acreage and the higher operated percentage of our activity over the next couple of years, we expect to see further reduction in transportation charges over time and higher rates of return as our operated gathering fees average $0.23 to $0.37 per Mcf, depending on the area.

The superior economics are driven by very productive rock as evidenced by the curves, high realized prices being $0.12 to $0.15 off of Henry Hub, low LOE, which averages about $0.05 per Mcf equivalent and even lower in the initial months, and as I said earlier, no severance tax until the earlier two years of payout. In summary, we are maintaining our production, CapEx and operating cost guidance as shown on A-3 of our appendix and have slightly tweaked our completion cadence based on real-time scheduling.

This quarter was an inflection point for the company, where production and EBITDA growth took a positive step change. When you take the third quarter production to date as disclosed and baked in our completion cadence, we feel very good with our guidance, which we believe could be conservative. The significant volume and cash flow growth in the future will create substantial value for our stakeholders and should be a positive catalyst for our stock price.

And with that, I will turn it back to the operator for Q&A.

Question-and-Answer Session

Operator

Thank you. We will now begin the question-and-answer session. [Operator Instructions] And our first question comes from Neal Dingmann with SunTrust. Please go ahead.

Neal Dingmann

Good morning, guys. Could you talk – just two questions, one about trading for higher working interest, and then secondly, Rob, for you or Gil, just thoughts about selling the Eagle Ford.

Rob Turnham

Sure. We have executed a number of swaps, which not only adds to our long lateral inventory, but increases our working interest in fewer wells. So again, better finding cost, better rates of return from the same EURs per foot. And in addition to that, as you know, and what was in our prepared remarks, our operated gathering fees are lower than when we participate many times in non-operated wells. So it's a win-win for us and also allows us to help control the timing of our budget. And I think you could continue to see us introduce swaps and/or drilling joint wells instead of an inventory of shorter laterals.

Neal Dingmann

Great. And then on Eagle Ford?

Gil Goodrich

Yes, good morning, Neal. It’s Gil. We've always said for quite a while now that it was a place we were unlikely at the current oil and gas price relationship to go spend much capital given on what's going on in the Haynesville, and therefore, if something that at the right price, we would consider divesting ourselves of. As oil prices have improved over the last six months, the volume of incoming inquiries has increased pretty significant. And so we would just say that today it remains something that we would consider divesting at the right price.

Neal Dingmann

Thanks guys.

Gil Goodrich

Thanks Neal.

Operator

Our next question comes from Joe Allman with Baird. Please go ahead.

Joe Allman

Thank you. Good morning everybody.

Gil Goodrich

Good morning, Joe.

Joe Allman

In terms of the well count, I see that you accelerated the – some completions from fourth quarter to the third quarter, and I think you're expecting six total completions. So based on my list, we've got the Demmon, the Harris, number one; the Loftus, the Cason-Dickson, the number three and four. So confirm that those five are part of the third quarter completion list? And what will be the sixth completion?

Rob Turnham

We have some non-operated activity also that is flowing through that. So we are participating for small interest in four wells, the cutting part is drilling offsetting our acreage. I think the average is about 7.5% working interest. So those completions are kind of staggered. But offline, I can give you a more detailed timing estimate. We try to just group these by quarter, but I can certainly lay out the wells a little bit more accurately if you'd like.

Joe Allman

Yes, that'd be great, Rob. I appreciate that. And then…

Rob Turnham

Sure.

Joe Allman

Second question, in terms of just financial plans, can you just walk us through the financial plans going forward?

Gil Goodrich

Yes, sure, Joe. It’s Gil. That's pretty straightforward. Obviously, we announced a material increase in the borrowing base this morning. We expect that to continue. Obviously, it certainly is EBITDA driven in nature. And so as we continue to add the EBITDA, we would expect as we get to year-end and we hand the year-end reserve for – to our bank group that giving us stagnant gas price forecast, you would expect to see another meaningful increase in the borrowing base and therefore, increased liquidity.

So as we look out to 2019, look at the guidance that we've given, the combination of cash flow plus increased borrowing base we feel very comfortable is adequate, sufficient and keeps us very conservative under 1.5 times total debt to EBITDA.

Secondly, we do have the second-lien notes that are out there. I think you'll remember, we've got a step down in the make-whole provision coming in October. So part of our plan is to take a look at those second-lien notes later this year to refinance those and provide perhaps a little bit of incremental capital with that part of that refi. So where we sit today, we're very comfortable with the plans at least through 2019.

Joe Allman

All right. Great, very helpful. Thanks guys.

Gil Goodrich

Thanks Joe.

Operator

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

John White

Good morning, gentlemen.

Gil Goodrich

Good morning, John.

Rob Turnham

Good morning, John.

John White

You talked about some new transportation and gathering agreements. You mentioned a range of $0.22 to $0.37. How does that compare with your guidance page that shows $0.30 to $0.40? The lower numbers, are those on operated wells?

Rob Turnham

Yes, it’s Rob. I'll take a crack at that. We're still comfortable with the unit cost guidance as shown on A-3. It's a blend of, obviously, operated and non-operated activity. We had previously budgeted 80-something percent, 84% operated anyway, which had the lower gathering fees. So really the amendment to the gathering fees that we announced previously is really going to be more of a 2019 positive effect than a 2018 effect and that it will start working through the inventory under the other acreage. Actually, we start there late this year, but the drill results will flow through the income and cash flow statement in 2019.

John White

Okay, thank you. And you mentioned your guidance for 2018 of 65 to 75 million cubic feet a day might be conservative. I certainly agree with that. Are you kind of hinting around there?

Rob Turnham

Well, I think as I said, I think hitting the Exit Rate, if you just start doing the math, you see where we are currently, look at net revenue interest of 65% or so blended average on the next couple of wells, and you start to add to that in plus the completion cadence that we show on this exhibit, if all works as planned and obviously, it's subject to service company scheduling and timing them showing up when expected.

But you could say that we potentially could certainly hit that Exit Rate sooner rather than later, and if we do that and we continue on the plan, then potentially you could produce more than the midpoint of that range. But not ready to change the guidance. We just – we'd rather try to be conservative and maybe beat it and then move from there.

John White

Yes. And I noticed you've got some longer – some of the significantly longer laterals scheduled for the third quarter at 7,000 and 7,500 and couple of 10,000-foot lateral. So that will just be more additives to your volumes?

Rob Turnham

Exactly right.

John White

Thanks again and congratulations.

Rob Turnham

Thank you, John.

Gil Goodrich

Thanks John.

Operator

Our next question comes from David Snow with Energy Equities. Please go ahead.

David Snow

Hi, good morning. I'm going back to an earlier statement that you would be looking forward to increasing stock and liquidity. Is that referring to PIKs? Or what was the reference?

Gil Goodrich

Well, David, it’s Gil. So if you've noticed, we've seen a fair amount of increasing liquidity and flow over the last six months or so. We came out from our restructuring with a very consolidated shareholder base. We remain that way today but a little bit of liquidity feeds on itself over time, and you're continuing to see that, and we would like to be where we can to try to help that accelerated that. To get ourselves in a stock where it's attractive to a broader range of potential investors, I think that's the essence of what we're saying.

Rob Turnham

And David, it’s Rob. I'll add. We're set to present in a number of conferences. We're getting more incoming costs as far as operations. And so the story will get told quite a bit over the next three months or so. And as, again, we put the numbers on the scoreboard. At some point, you can't trade at 1.7 times 2019 EBITDA. Some thing's got to change and it's our job to continue to tell the story and build that support and increase our shareholder group.

David Snow

Is it possible that some of the consolidated holders will also be able to free up some of that stock? Or is that part of your?

Rob Turnham

Well, certainly, it's – I think, the reason you're not seeing more shares trade is, they see where we're going. It's pretty obvious that when you're growing cash flow as much as we are, and if the stock trades rationally, the stock got to be worth more, and therefore, it ought to trade better. So I can't blame anyone for not wanting to sell shares to provide illiquidity because our path forward is very obvious.

David Snow

Okay, fine. Thank you.

Rob Turnham

Thanks.

Operator

[Operator Instructions] Showing no further questions, this concludes our question-and-answer session. I'd like to turn the conference back over to Gil Goodrich for any closing remarks.

Gil Goodrich

Thanks, Steven. Thank you everyone. We appreciate your participation this morning. As Rob said, 2Q was a pretty good inflection point for us, rolling very strongly into 3Q. We certainly look forward to presenting those results to you in early November. Thank you.

Operator

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