Goodrich Petroleum Corp. (GDP) CEO Gil Goodrich on Q3 2018 Results - Earnings Call Transcript

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About: Goodrich Petroleum Corp. (GDP)
by: SA Transcripts

Goodrich Petroleum Corp. (NYSEMKT:GDP) Q3 2018 Earnings Conference Call November 8, 2018 11:00 AM ET

Executives

Gil Goodrich - Chairman and Chief Executive Officer

Rob Turnham - Chief Operating Officer

Analysts

Neal Dingmann - SunTrust

Phillips Johnston - Capital One

John White - Roth Capital

Eli Kantor - IFS Securities

Operator

Good day and welcome to the Goodrich Petroleum Third Quarter 2018 Earnings Call. All participants will be in listen-only mode. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Mr. Gil Goodrich, Chairman and CEO. Please go ahead.

Gil Goodrich

Thank you and good morning everyone. Thank you for participating with us this morning in our third quarter call. We are pleased to have the opportunity to share our third quarter results with you as well as to discuss our ongoing activity and plans. In conjunction with the call, we have again prepared a slide presentation and we would invite you to follow the slide deck during the prepared remarks. You can access the slide presentation on our website at goodrichpetroleum.com and it is entitled Earnings Call Slides Third Quarter 2018. Our standard disclaimer, forward-looking statements and risk factors are highlighted for you on Slide 2 of the presentation.

We are very pleased with the third quarter results which met or exceeded our internal estimates in almost every reported category. In addition, the continued momentum achieved during the third quarter has positioned us well to deliver additional growth in the fourth quarter.

On Slide 3, you will see our company overview, which includes the third quarter production results which grew 40% sequentially over the second quarter to just under 85 million cubic feet of gas equivalent per day. Quarterly volume growth continues and we are providing production guidance for the fourth quarter in which we project will range from an average of 95 million to 105 million cubic feet of gas equivalent per day. In addition, we reiterate our preliminary 2019 production guidance of 100% year-over-year growth or an average for the year at the midpoint of 140 million cubic feet of gas equivalents per day. Due to a large percentage of our operating expenses remaining relatively flat on an absolute basis and the very low incremental lease operating expenses or LOE associated with new well additions, we are experiencing significant margin expansion with rapid production growth. The margin expansion and associated EBITDA should allow us to execute our 2019 plans and capital budget with very manageable outspend while maintaining net debt to EBITDA in the range of 1.0x to 1.5x.

To further protect EBITDA for 2019, we recently added to our 2019 natural gas hedge position which you will find in the appendix section of our earnings slide presentation. The updated hedge position provides us with just over 70 million cubic feet of gas hedged for calendar year 2019 or approximately 70% of the midpoint of our fourth quarter of 2018 estimate at a blended average price of $2.88 per Mcf. And adding in our existing clinical hedges for next year, the blended average hedge price for 2019 is approximately $3.12 per Mcf equivalent.

On Slide 4, we highlighted our reported third quarter capital expenditures of $38.3 million and provide capital expenditure guidance for the fourth quarter in a range of $8 million to $10 million. As I mentioned, we are experiencing meaningful production growth and declining associated operating expenses where our per unit cash operating expenses decreased sequentially by 20% with lease operating expenses declining 27% sequentially to $0.33 per Mcfe and per unit cash G&A expenses declining 34% sequentially to $0.40 per Mcfe. Declining per well unit growth is expanding cash flow with EBITDA growing to $14.3 million in the quarter, Bcf to $13.8 million in the quarter and we expect this trend to continue as we continue to rapidly grow our production volumes.

Slide 5 illustrates the robust production volume growth I mentioned a minute ago which we achieved during the third quarter, the projected production guidance for the fourth quarter of this year as well as our preliminary guidance for 2019. On Slide 6, we present our updated capitalization table. We ended the quarter with $1.9 million of cash and $15 million drawn under the senior credit facility. When combined with our existing second lien notes, it yields net debt at the end of the third quarter of $65 million. In addition, our bank group recently increased the borrowing base under the senior credit facility to $75 million.

Slide 7 shows the location of our core assets and on Slide 8 you will again see the chart showing our SEC proved reserves and growth over the last couple of years with year end 2017 proved reserves of 428 Bcf equivalent. In summary, we are very pleased with the operational performance in the most recent quarter. We like where we are positioned and believe we are set up well to deliver exceptional growth in the coming quarters.

I will now turn the call over to Rob Turnham.

Rob Turnham

Thanks Gil. For the quarter our revenues increased by 37% sequentially to $24.3 million with an average realized price of $3.12 per Mcfe comprised with $2.75 gas and $72.29 per barrel of oil. Our per unit cash operating expenses dropped by 20% from the previous quarter resulting in a significant expansion of our cash margin. We expect to see a continuing drop in total per unit cash operating expenses as the Haynesville wells are added as they carried very low LOE, no severance taxes until the earlier payout in 2 years and more attractive gathering agreements than our legacy contracts. The two main drivers of lower per unit cash operating expenses, as Gil pointed out our cash G&A expense which was down by $300,000 from the previous quarter and on a per unit basis from $0.61 to $0.40 per Mcf equivalent, which for unit costs for the quarter puts us in the lower quartile of our peer group.

And second, our LOE, which dropped from $0.60 per Mcfe to $0.33 per Mcfe driven by significantly higher volumes and very low per unit LOE on the incremental production. We expect both of these per unit cost categories to continue to fall. We had operating income for the quarter of $5 million, EBITDA of $14.3 million and net income of $1.7 million or $0.14 per basic share. Interest expense totaled $3.1 million in the quarter which includes cash interest of $300,000 incurred on the company’s revolver and non-cash interest of $2.8 million incurred on the company’s convertible notes. Non-cash interest expense was comprised of $1.7 million of paid in-kind interest and $1.1 million of amortization of debt discount.

Moving back to our slide deck, we have included several slides beginning with Slide 9 that showed how we trade well to an approximate 50 company peer group. Review of Slides 9 through 12 will show you that even though the stock has outperformed year-to-date, at October 30, the company was still trading at the third lowest multiple of our 50 company peer group at a little over 2x enterprise value to consensus 2019 EBITDA. Add the fact that we expect to maintain our debt to EBITDA through ‘19 at 1 turns and 1.5 turns allows for a compelling argument as to why the company is undervalued. What is driving our significant growth in volumes and cash flow is our capital efficiency which is shown on Slide 11 provides the ability to grow production with the least amount of capital that anyone in our peer group regardless of basin. This was also supported by public data as reported by multiple sales side and third-party analytical firms where we rank at the top of the list on productivity per thousand feet of lateral in the Haynesville and the Haynesville ranks high in productivity among all basins.

On Slide 12, we currently have 22,400 net acres in the core of the Haynesville with 19,100 net acres in the North Louisiana core and 3,300 net acres in the Angelina River Trend in East Texas. Our North Louisiana acreage is approximately 80% undeveloped and 73% operated which by the way is an increase in our operated percentage by virtue of recent acreage swaps. Still have over 200 gross and 97 net locations, which again is up 7 net locations once we have added some additional bolt-on acreage. We have gridded our acreage with a plan to maximize long laterals and expect to continue to swap acreage or drill joint wells and offset operators to further increase our long lateral inventory and operator percentage. We estimated over a Tcf of reserve exposure at 2.5 Bcf per 1,000 feet of lateral in North Louisiana alone.

Moving to Slide 13, activity remains high with about 50 rigs running in the play. All of our acreage has now been de-risked and we are 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 to Bethany Longstreet and the other 30% to the Thorn Lake area, where we are drilling our Cason-Dickson and Harris wells. We currently expect a higher allocation to Bethany Longstreet and a higher operating percentage in 2019. We have been given preliminary CapEx guidance for 2019 of a range of $125 million to $150 million and we will put out a more detailed cadence schedule for 2019 after our board meeting in December.

We continue to show an abundance of well results on our decline curve slides beginning on Slide 14. On Slides 14 and 15, we are tracking 59 4,600-foot laterals with average profit of approximately 3,400 pounds per foot and in many cases with wells more than 2 years of production on a handful of those wells. The composite production curve is generally following our 2.5 Bcf per 1,000-foot type curve is shown in red and our 4 operated well averages running well above the curve with higher profit loading and tighter interval spacing.

Slides 16 and 17 reflect our 7,500 foot curves where we continue to show a composite of 87 wells with average profit concentration of 3,100 pounds per foot, which again fits nicely with our 2.5 Bcf per 1,000 foot type curve. The older wells included in the composite curve are a handful of under-stimulated wells and we expect the composite tale results to pull up as the newer wells with higher proppant concentrations flowing through over time. Our operated wells again are running on or above the high case curve.

Slides 18 and 19 which show composite results from 35, approximate 10,000-foot laterals with an average of 3,200 pounds per foot of proppant are also tracking our 2.5 Bcf per 1,000-foot type curves. Our 6 wells, which averaged approximately 9,500 feet of lateral and 3,700 pounds per foot of proppant are on or above the 2.5 Bcf per 1,000 foot curve. In general, longer laterals and higher proppant loading typically make better wells so that we are focused on IRR not EUR as returns matter more than ultimate recovery of reserves. Our economics as shown on Slide 20 through 22 show how exceptional this play is at current gas prices. At $2.75 to $3 gas, we can generate 36% to 53% IRRs for 4,600-foot laterals, 43% to 60% internal rates of return for 7,500-foot laterals and 55% to 76% IRRs for 10,000-foot laterals. In many cases, our returns are better where our gathering fees and basis are lower than the $0.60 per Mcfe used in the analysis or where we are outperforming the type curves. In fact, in that we are looking at flatter initial production profiles, we believe the IRRs could improve once we adjust our curves at year end.

In summary, we are executing on all cylinders, volumes are actively growing and cash operating costs are falling as expected, which will continue to drive margin expansion and superior growth in EBITDA.

With that, I will turn it back over to the operator for Q&A.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Neal Dingmann with SunTrust. Please go ahead.

Neal Dingmann

Gil or Rob, just my question. Now after you have done a lot of this activity, could you talk a bit about lateral size I mean is bigger always going to be better and if so on what percent of your acreage now can you do some of those longer laterals? Thanks.

Gil Goodrich

Yes. So Neal, it’s Gil, good morning, very good question. Look, we think that every foot of laterals you can get is you can better amortize surface cost, vertical hole cost is better. We will say that there could be a point out there which the longer you go, you are taking on some incremental list of further out you get with you lateral, perhaps having the megabit tripped way out on that lateral that could take you a couple or 3 days, which have some incremental cost. So we are getting pretty comfortable that 7,500s and the 10,000, so a little bit better on the 10,000 if everything goes perfect, but we have got a fair number 7,500 planned for next year. I think this year Rob will correct me, I think we are about 8,000 feet blended average this year and pretty similar to that for next year. As Rob mentioned in his remarks depending on exactly how we either swap out additional acreage or participate with others and some longer laterals is a lot of flexibility around whether or not we fully loaded up to 10,000, so we drilled more 7,500. I think we got lot of flexibility around that Rob might have another comment or two.

Rob Turnham

I think that is why the goal is to have a blended average at 7,000 to 8,000 foot lateral when you bake in the longer laterals with the handful of 4,600s.Well, one interesting analysis that we are ongoing also is just if you look at how prolific even our 4,600 foots and are certainly you drill them faster, you get them hooked up faster on a programmatic basis it would be in an interesting analysis to compare more wells, there are slightly shorter laterals that get online quicker than the incremental lateral length wells. So I agree with Gil, I mean rates have returned certainly better on the longer laterals, but from a program standpoint, not all bad to add wells quicker.

Neal Dingmann

Okay. And then just one follow-up, looking at the Bethany-Longstreet area, Rob or Gil how do you think I have noticed you hadn’t been – some of that Northwest area still hasn’t been as active in that area, your thoughts about doing in that area or if you could just talk about where you are sort of focused in that entire area for ‘19? Thank you?

Gil Goodrich

Yes. Okay. Well, so first of all the Northwest area there what we call Greenwood-Waskom, Metcalf, Neal is first of all it’s all held by production we drilled a handful of wells back in 2009, 2010 framework. So we have no fresh ones anything up there, really all of Northwest again is up by production. We really like what we see our friends at Comstock have drilled a handful of wells up there continue to be very active up in that area and just slightly south of that making wells that are in the 25 million to 30 million a day range on initial production rate. So we are very high in the area, good news is we got plenty on our plate here through ‘19. I don’t think we currently had anything planned up there, but certainly could add a well in anytime we wanted to.

Rob Turnham

And the only thing I will add Neal is just our North Louisiana acreage footprint is growing fast. We have wells surrounding us in all sides and it’s really one of the few plays if not the only play that we have been in over a 23-year period where if you drill it and you complete it the same way, you basically have the same well results. And so we are truly in development mode and now we are just trying to maximize or minimize cost and get these wells hooked up as quickly as possible and pretty much have high confidence on what those results are going to look like.

Neal Dingmann

Great. Thanks for the color guys.

Gil Goodrich

Thanks Neal.

Rob Turnham

Thanks Neal.

Operator

Our next question comes from Ron Mills with Johnson Rice. Please go ahead.

Unidentified Analyst

Good morning guys. This is Doug on for Ron, high level wondering about M&A in the Haynesville, any opportunity to be yes to or just kind of where you see in general that the gross scale, more specifically with Chesapeake you saw on ground make the WildHorse acquisition and the Haynesville seems to be less and less part of their plans going forward. Just kind of your thoughts around that would be great?

Gil Goodrich

Yes. It’s a great question. The geographic area in the North Louisiana core is fairly small when compared to other basins. It’s dominated or controlled by probably 15 operators, many of whom are large scale operators. We certainly have a great relationship with Chesapeake. We’ve been partners in the play since 2008, and it is something of interest to us in particular on our joint acreage. And I think you – we certainly expect to continue to have dialog with Chesapeake. As you know we’ve swapped acreage with them. We’re both trying to maximize the value of our positions and we’re open ears and expect to continue to try to bolt-on opportunities for the company. We’ve added a little bit of acreage I would say over the last 3 to 6 months, which has increased our inventory a little bit. So we’re focused like a laser on trying to do it in a way that creates a deeper inventory, but doesn’t over-lever the balance sheet because that’s our main concern. And even though we only have 22,000 net acres with it being 80% undeveloped. We still have over 1 Tcf of reserve exposure there. For a company of our size that’s just huge compared to where we sit now.

Unidentified Analyst

Okay, great. Thanks. And then also kind of on the activity front, in the Angelina River Trend area, you’ve seen some majors kind of moving over there. Just kind of general commentary on what the industry’s kind of development base over there and what you’re seeing?

Gil Goodrich

Yes, BP has – if you look at our kind of activity slide I think we still show 4 rigs in the Angelina River Trend area, and will be very complementary of BP that made really good wells over there. For us it is deeper and therefore little more expensive to get those wells drilled when compared to North Louisiana. So we’re – that acreage is held by production for us. We’re just going to let it sit there for a while, it’s only going to get more developed while we focus all our efforts in North Louisiana with plenty of running room.

Unidentified Analyst

Alright, great. That’s it from me.

Rob Turnham

Thanks.

Gil Goodrich

Thanks.

Operator

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

Phillips Johnston

Hey, guys. Thanks. Just one question for me. You guys spent more than 250% of your cash flow in the quarter, and if you annualize your third quarter EBITDA, the leverage ratio is still slightly below that max 1.5 times target. So everything still seems very comfortable and it seems like you can stay under that max target even while outspending cash flow next year and obviously it makes sense to grow given your size. But my question is, what do you think is realistic in terms of timing of when the company can spend within cash flow or even generate free cash flow on a sustainable basis and still show some healthy production growth at the same time?

Gil Goodrich

Phillips, that’s a – this is Gil. That’s a – good morning, and that’s a great question. And the answer is, today we would just slow down a little bit. Rob and I were looking this past week at just kind of what a December 31 run-off looks like in our internal modeling and projections. And our estimate is something less than 2 net wells next year would keep production flat. So we could – when you could keep production flat with very, very little call it $20 million to $25 million of net capital. So the lever on the growth been – is just purely a question of how fast you want to grow. So we could grow within – we could grow and build within cash flow in 2019, I think very comfortable without any question. We’re really looking as Rob alluded to earlier, what’s our trailing EBITDA metrics, where are we comfortable, where is our board comfortable from a debt perspective. And given the relatively low leverage on the balance sheet today and the tremendous growth opportunities we think the right answer is to outspend a little bit and we’re very comfortable if the borrowing base will actually be expanding faster than any incremental borrowings then liquidity actually improves during the course of next year.

Rob Turnham

And Phillips only one other thing to add would be if you looked at minimum CapEx in the fourth quarter and you bake in a midpoint of our production guidance of $100 million a day, you will see obviously that’s a free cash flow generating quarter. But to your point, we think there’s a certain critical mass that is beneficial to have and certainly consensus EBITDA of $100 million next year for us gets us up to a size that, that makes some sense and should be a real value creator for the company and for our shareholders. But as you get later in the year, you’re obviously not outspending by much, if any, based on the cadence that we’ll lay out after our December board meeting. So, we’re getting closer but we’re creating a tremendous amount of value for our shareholders, while we’re keeping our debt metrics very low.

Phillips Johnston

Okay. That’s a great answer. Thanks, guys.

Gil Goodrich

Thanks, Phillips.

Operator

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

John White

Good morning. Thanks for taking my question.

Gil Goodrich

Hi, John.

Rob Turnham

Good morning, John.

John White

Hi. Yes, hi, guys. Want to make sure I heard this right, you’re going to overweight 2019 CapEx back to the Bethany-Longstreet area?

Gil Goodrich

That’s right. It’s just the factor of it. So we’ve been over in Thorn Lake, I think we estimated about 30% of our activity in Thorn Lake, where we’re drilling these Cason-Dickson and Harris wells, and they are really tremendous wells. I mean, we’re – in fact, if you – if you look at the fact that, we haven’t talked about yet, which is we deferred the completion of basically 1 net well that was scheduled in the fourth quarter to the first quarter of ‘19 and yet we’re maintaining at the midpoint kind of our $100 million a day guidance. That’s basically telling you our wells are doing extremely well relative to our curves. But we’ve made a concerted effort to fully develop a certain lease or couple of sections over there in the Thorn Lake area and we’re well on our way to finishing that up by probably mid to third quarter of ‘19. So other than that, we would expect to just supplement that towards back to Bethany-Longstreet. So, we think probably going to be – certainly going to be in excess of the 17% that we’re spending at Bethany-Longstreet in ‘18. And again, once we have this board meeting in December, we’ll put out ‘19 guidance.

John White

Okay. Thank you. And any update on the Cason-Dickson 3 and 4, when you think they might get fracked?

Gil Goodrich

Sure, John. This is Gil. We are – that’s a 2 well pad. The fourth down in case, the 3 is almost at total debt and we’ll be running casing on that here shortly. We plan to drill an additional Loftus well. We drilled and cased our first Loftus well. We’ve got a second Loftus well, that we’d be drilling here fairly soon late this year, very early in ‘19. And then those 4 wells, 2 well pads will be fracked in sequence in beginning in early January. So that’s why we had a little bit of a delay just to take advantage of the synergies and cost savings from 2 well pads back to back.

John White

Okay. So, Loftus No. 1, is that [indiscernible]?

Gil Goodrich

Loftus No. 1 is sitting ready to go today and we’ve put a little bit of a delay on the completion of that well just to take advantage of the synergies with the Loftus No. 2.

John White

Got it. Well, thanks, again, and keep growing these good wells.

Gil Goodrich

Thank you, John.

Rob Turnham

Thank you, John.

Operator

Our next question comes from Eli Kantor with IFS Securities. Please go ahead.

Eli Kantor

Hey, good morning, guys.

Gil Goodrich

Good morning, Eli.

Eli Kantor

Can you talk about what you’re seeing in the bond market as you look to refinance your second-lien notes and how big of a liquidity boost may come with that?

Gil Goodrich

Yes, Eli, so really kind of not quite big enough to really go float high-yield bonds or notes. We’ll likely to replace the existing second-lien with something more like a term loan or – whether it’s second-lien or unsecured will depend on the terms that are being pitched to us. So I – and I think – and we think it’s not going to be convertible, but a little less capability for us just due to size, but not having the high-yield market open. So we’ll stick to what we think which is likely either unsecured or second lien term loan, yet to replace it. And there is quite a bit of interest we have been still forming firms until first quarter of next year because we just think it’s beneficial to refinance in the first quarter. But it is likely that we do refinance it before the end of the quarter, because our senior credit facility matures at December 31, ‘19 and we don’t want those notes or the revolver to go current. So we will adjust that probably late December or early January and then likely refinance in the first quarter. Now, what’s interesting is that since we are likely to not do a convertible note or bond there is 1.875 million shares currently associated with the conversion of the 40 million existing second lien notes that will come out of a fully diluted share count. So a big positive there and we think we can improve on the cost in those of the new financing versus what we are currently accruing for which is the 13.5% coupon. So should be a real positive event to replace what we have with lower cost to capital and take 1.875 million shares out of the fully diluted count.

Eli Kantor

That’s great color. In the Eagle Ford and TMS, is there anything you are seeing from an offset peer development standpoint that might want reallocation activity or a divestment of that asset?

Gil Goodrich

Yes. This is Gil. There is some activity going on around, there are some people who probably are aware that a private equity backed fund, but not out of San Antonio bought the Cabot position just east of us in the Eagle Ford. So we are thrilled with that and we wish them well and activity continues around us on the East side there. So we are very contented at this point to just see that play out we think as oil prices continue to improve over time the value there just increases for us. So no activity planned there are currently more at least at this point in 2019. Shifting over to the TMS our friends from Australis who purchased all of the Encana TMS position have been studying the play since the acquisitions well a year ago and they have recently moved the rig in or going to a new TMS well. So if you need the first TMS well to be in the place as we shutdown in mid to late 2014. So we are wishing them well. We are watching that closely and obviously I hope they provide some really strong results that might give people a new look at that, but again for us too high of internal rates of return being generated in the Haynesville for us to think about allocating anywhere else at this point in time.

Eli Kantor

It makes sense. Last one for me, can you talk about how you are situated on the service cost front with regards to your drilling rig contracts and frackers and if there any potential changes that might impact that 125 to 150 2019 CapEx guidance?

Gil Goodrich

Yes. So it’s Gill, also not really we are seeing slight changes in the rig market, obviously the Haynesville being a fairly deep normally pressured reservoir we need to get up. We like to get around 2,000 horsepower rigs, but those are running between 18,000 and 20,000 a day, so not much change there. On the pressure pumping front, actually some good news I think Rob has talked about this number of occasions. During the course of 2018 we have actually seen spread weights come down, mainly driven by increased capacity into Haynesville, so the rig count has ticked up to 50 rigs running in the play the pressure pumping community has added capacity in the play and that actually helped us. So as we look at 2019, we don’t see anything on the horizon today that looks like there is whole lot of inflation. We have seen obviously some increase in pipe prices with the steel tariffs. But although we now have – look like a fairly stable environment if anything it would be kind of in the 5% to 10% range and we do include some cost sensitivities in our economics in our presentation.

Eli Kantor

Great. Thanks for the color and congrats on the quarter.

Gil Goodrich

Thanks.

Operator

This now concludes the question-and-answer session. I would now like to turn the call back over to Gil Goodrich for any closing remarks.

Gil Goodrich

Thank you all. We greatly appreciate everyone’s participation and interest in the company. As I said earlier, we feel really good about where we are and very excited about reporting our fourth quarter numbers to you in a few months. Thank you.

Operator

The conference has now concluded. Thank you for attending today’s presentation and you may now disconnect.