Goodrich Petroleum Corporation
Q3 2019 Earnings Call Transcript

Published: 8 Nov 2019

[Operator:]

Good morning. And welcome to the Goodrich Petroleum Corporation Third Quarter 2019 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] Please note, this event is being recorded.I would now like to turn the conference over to Gil Goodrich, Chairman and CEO. Please go ahead.

[Gil Goodrich:]

Thank you. And good morning, everyone. Thank you for participating on our third quarter earnings call this morning.Despite extraordinarily weak natural gas prices in the quarter, we again achieved solid EBITDA for the quarter on the strength of our hedge position and lower lease operating expenses. As has become our practice, we have again prepared a slide presentation, and we invite you to follow the slide deck during our prepared remarks this morning. You can access the slide presentation on the Goodrich Petroleum website, entitled 3Q19 Earnings Presentation.While we maintained a one rig drilling program in the Haynesville, we slowed the completion cadence during the third quarter with only one gross and 0.9 net wells completed in the quarter. We are currently fracking our Loftus 27 & 34 1H well, which is a 7,500-foot lateral in the Bethany-Longstreet field, and we expect initial production in the third week of this month. Looking forward, we are monitoring the markets closely but our current expectation is that we will build some drilled but uncompleted wells or DUCs as we enter 2020 including three drilled and currently uncompleted 10,000-foot non-operated Haynesville wells in the Bethany-Longstreet.We will review a range of CapEx and budget options for 2020 with our Board in early December. And given our current hedge position and 2020 natural gas future strip prices, we are confident in our ability to both reduce full-year CapEx compared to this year and grow production volumes more modestly, while generating an attractive free cash flow yield.Once our Board has formally approved the preliminary plan for 2020, we’ll provide you with more details on the budget and planning for next year. As I said, operationally, we continue running one rig and the core of the Haynesville in Northwest Louisiana. And this morning, we announced the completion of our Harris 2H well in the Thorn Lake field, which was recently completed as a 9,400-foot lateral in Red River Parish.I will now turn to the slide presentation for those of you who would like to follow along. And our standard disclaimer, forward-looking statements and risk factors are highlighted for you on slide two.On slide three, we have again included an overview of the Company and our assets, which highlights our core Haynesville share position in Northwest Louisiana, where we continue to maintain a 10-year net inventory of delineated development locations, which contain over 1 TCF of natural gas reserve potential. While we maintain upside exposure to crude oil through our Eagle Ford and TMS assets, all of our current activity is focused on the core, Northwest Louisiana, Haynesville.Our Haynesville position is yielding low finding cost, decreasing per unit expenses, solid rates of return on capital invested. At the end of the third quarter, our calculated return on capital employed was 17% when annualizing 3Q EBIT. As I said earlier, the strength of our hedge position and lower per unit LOE led to third quarter EBITDA of $21.3 million and an EBITDA margin of 64%.On slide fur, we again highlight our year-end 2018 SEC proved reserves of 480 Bcfe, which had a present value of 10% or $418 million.On slide five, we provide an updated cap table as of the end of the third quarter. During the third quarter, our borrowing base under our senior credit facility was re-determined, which resulted in a $10 million increase from the initial borrowing base in May to $125 million. Our third quarter annualized EBITDA equals $85.2 million, and when compared to approximately $99 million of net debt, results in a net debt to EBITDA of just over 1.1 times.Turning to slide six, we have updated our quarterly production chart to illustrate our production growth over the last few quarters and couple of years, as well as the current expectation for the fourth quarter of this year. As I said a minute ago, we continue to watch the markets and set the appropriate completion cadence designed to achieve the right rate of growth and generate free cash flow.On slide seven, we have updated the detailed volume and price information on our current natural gas and crude oil hedge positions. As you can see, we are very well hedged through the remainder of this year with 100 million cubic feet of natural gas hedged at $2.89 per Mcfe, which represents a little over 75% of the reported third quarter natural gas volumes hedged at these prices. During the third quarter, we added to our natural gas hedge position in 2020 and early 2021 with a combination of additional swaps and costless collars, which now provides us solid downside protection, equal to almost 50% of anticipated 4Q ‘19 production through that period of time.We continue to watch the natural gas markets closely and look for additional opportunities to hedge and add to our additional hedge position and support and protect our capital planning.Finally, we have updated our 2019 guidance on slide eight to adjust for the current anticipated completion cadence, and a midpoint of production guidance for the full year to approximately 130 million cubic feet of natural gas and equivalents per day.In addition, the guidance provides the anticipated ranges for per unit cash expenses of LOE, taxes, transportation and cash G&A. The quarterly completion cadence reflect the adjustment to our 2019 gross and net well counts, in particular the adjusted cadence I mentioned earlier, where we have three non-operated wells in Bethany-Longstreet, in which we have a 25% working interest that we now expect will be completed in early 2020.And with that, I’ll turn the call over to Rob.

[Robert Turnham:]

Thanks, Gil.Revenues totaling $27.2 million in the quarter with an average realized price of $2.01 per Mcf, $59.67 per barrel of oil, and $2.17 per Mcf equivalent. When adjusted for our settled hedges, revenues were $33.1 million with an average realized price of $2.65 per Mcf equivalent, down $0.05 from the previous quarter.Our per unit cash operating expense, which is defined as operating expenses excluding DD&A and non-cash G&A continued to drop in the quarter, decreasing by 23% over the prior year period and 5% sequentially to $0.98 per Mcf equivalent. The sequential drop in per unit cash costs was driven by a reduction in LOE by 13% to $0.21 per Mcf equivalent, and transportation and processing by 11% to $0.41 per Mcfe.Capital expenditures for the quarter totaled $25.5 million, of which 97% was spent on drilling and completion costs associated with Haynesville wells. We expect to spend $10 million to $15 million in the fourth quarter as we complete 2 gross, 1.7 net wells, and enter the year with 5 gross, 2.5 net Haynesville wells drilled but uncompleted.Interest expense totaled $2 million in the quarter, which included cash interest of $1.2 million incurred on the Company’s revolver and non-cash interest of $800,000 incurred on the Company’s convertible notes.The non-cash interest expense was comprised of $400,000 of paid and in-kind interest and $400,000 of amortization of debt discount and debt issuance cost associated with the Company’s second lien note issuers. Interest expense for the quarter decreased by $1.1 million from the prior year period due to refinancing a majority of all second lien notes with our revolver, which carries a much lower interest rate.Moving back to our slide deck, as we’ve highlighted before, we’ve included several slides beginning with slide nine that show how we compare to a 55-company peer group. As Gil said earlier, and as you will see on slide nine, our return on capital employed for the quarter was 17%, despite very low commodity prices, which ranks in the upper tier in the peer group as of October 30th.Moving to slide 10, if we were to show true capital efficiency, defined as CapEx to growth and volumes, we would likely be at or near the top of the rankings, due to making very high volume levels. But we believe a more compelling evaluation is a modified definition being CapEx to growth in EBITDA as everyone is focused on returns versus production growth.As you see, we ranked very high again on this modified capital efficiency analysis as our returns including our hedges are extremely competitive, even when comparing to oil basins as evidenced again by our return on capital employed. Under this modified capital efficiency analysis, there are fewer companies in the peer group due to fewer companies actually growing EBITDA year-over-year.In addition to returns, it is critical to maintain low leverage in these challenging times for commodity prices. And we’re focused on maintaining a debt to EBITDA ratio of 1.5 times or less. And as Gil stated earlier, we stood at 1.1 times annualized and 1.25 times trailing 12-month. EBITDA at the end of the quarter.Even though our capital efficiency and return on capital employed are near the top of the peer group and our debt to EBITDA is extremely conservative, we only trade at little lower level 2.5 times consensus enterprise value to ‘19 EBITDA as shown on slide 12.As everyone likely knows by now, all of our current activities are centered in the core of the Haynesville, beginning on slides 13 and 14. We entered the year with 22,600 net acres in North Louisiana, and 214 gross, 99 net locations on spacing of 880 feet between well bores.As reflected in our first quarter 10-Quarter, we sold a small portion of our Greenwood-Waskom acreage that we viewed as out of the core and leaving approximately 22,000 net acres currently. The acreage that was sold was not originally in our 214 gross, 99 net location count. Therefore, that count does not go down.As Gil alluded to earlier, we and the operator of thee non-operated wells made a decision to defer completions on four gross, 1.75 net wells due to low gas prices at the time, which have obviously rallied a good bit since the decisions were made. We expect to have 5 gross, 2.5 net drilled but uncompleted wells as we enter the year, and all five are expected to be fracked in the first quarter of 2020 with 4 of the 5 currently expected to commence fracking operations in January.As stated in the press release, this deferment affected fourth quarter volumes by 14 million cubic feet per day, but sets us up well for a surge in volumes early in 2020 at hopefully higher prices, which will provide momentum for the year from which we can deliver a very good free cash flow yield to our shareholders. Due to the deferred completions, we now expect to complete eight gross, 7.2 net locations this year, down 2.1 net wells from previous guidance.At this completion cadence, we will lengthen our inventory life from 18 gross, 10 net wells currently to approximately 25 gross, 12.5 net years from North Louisiana only as we enter 2020. The acreage in North Louisiana is over 70% undeveloped and 73% operated. We’ve 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 1 TCF reserve exposure at 2.5 Bcf or 1,000 feet of lateral and 880-foot spacing in North Louisiana alone versus year-end ‘18 book prove reserves in North Louisiana of 471 Bcf equivalent. We also maintain approximately 3,000 acres held by production in Angelina River Trend of the Shelby Trough for future development. The Haynesville and Bossier formations are both prospective on our Angelina River Trend acreage.As show on slide 15, 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’ve allocated approximately two-thirds of our 2019 capital expenditure budget to Bethany-Longstreet and the other one-third to the Thorn Lake area. We announced another well result with this release as Gil stated, which was a 9,400-foot lateral in Thorn Lake at a stable 24-hour production rate of 26 million cubic feet per day, which is similar with its closest offset. This is the six new vintage well, we’ve drilled in Thorn Lake on an approximate 1,280-acre unit. And as we stated in the press release, our previous five new vintage wells have produced an average of 7 BCF in 13 months from an average lateral length of 6,900 feet. And the wells continue to produce at high rates. We’re currently drilling our last well in the acreage with plans to frack that well in January.On slide 16, we’re tracking 299, 4,600-foot laterals with average proppant of approximately 3,100 pounds per foot. As you will see, the older wells are underperforming the newer wells as average proppant is lower on the older wells. Our six wells shown in green were stimulated with approximately 4,100 pounds per foot of proppant loading. And they’re not only a good bit better than the prop than the industry average composite curve, but they exceed our 2.5 BCF per 1,000-foot curve by a good bit. In fact, our more recent wells are pulling up the composite curve over time, which we expect to continue.Slide 17 reflects our 7,500-foot curve, where we now show a composite of 206 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. The older wells included in the composite curve are a handful of understimulated wells with approximately 2,400 pounds per foot. And the newer wells average 3,500 pounds per foot, which we expect, again will pull up the curve as the newer wells flow through over time.Our more recent operated wells which carry higher proppant concentration are running well above the 2.5 BCF per 1,000-foot curve.Slide 18, which now shows a composite result from 187 10,000-foot laterals with an average of 3,000 pounds per foot of proppant are also tracking our 2.5 BCF per 1,000-foot type curve until the older wells with lower proppant concentration kick in a little over two years out. Our nine wells which average approximately 9,600 feet of lateral and 3,500 pounds per foot of proppant are for the most tracking our 2.5 BCF per 1,000 curve.We believe this data validates the quality of our acreage and optimum completion and flow back technique and maximize cash flow generation, which is the number one driver in our corporate strategy. In general, there’s a high correlation between tighter interval spacing and higher proppant concentrations to EUR. But as we have said before, we are more focused on the returns we’re generating versus just EURs. Return on capital employed is our primary objective.Our economics, as shown on slides 19 through 21 show how exceptional this play is at reasonable gas prices. If you bake in our hedges of 100 million cubic feet per day at $2.89 at the end of the year, we should average pre differential in the $2.65 to $2.75 range, which would generate approximately 55% to 65% IRR at the midpoint for average lateral length for the year, using our 7,500-foot curve and assumptions.We capture the early timeout performance on our wells. And when you combine that with high netbacks relative to other gas basins, very low LOE, initially at less than $0.05 for per MCF, and no severance tax until the earlier of two years of payout, our returns are very competitive with any basin, as evidenced by our 17% return on capital employed for the quarter at similar pricing.In summary, we can’t control commodity prices, but we have a balance sheet that carries low debt metrics and asset that is working very well, a nice hedge position that is minimizing our commodity price risk, a unit cost structure that is declining, creating very attractive margins, and a capital efficiency and return on capital employed that competes with any basin.With that I’ll turn it back to the operator for Q&A?

[Operator:]

Thank you. [Operator instructions] Our first question comes from Wells Fitzpatrick with SunTrust. Please go ahead.

[Wells Fitzpatrick:]

Hey. Good morning. You guys talked to it in the prepared remarks, but the delayed completions due to gas pricing, to be clear, that was Henry Hub pricing, not any basis issues. Is that correct interpretation?

[Robert Turnham:]

Yes. Yes, Wells, this is Rob. Yes, we monitor NYMEX, just like everyone else. And Henry Hub can fluctuate, but ultimately gets back at the end of a contract term. But yes, it's all about gas prices. Obviously, gas prices have moved dramatically over the last 30 or 45 days. Those decisions were made at a much lower price per Mcf than what we currently see. But, we're going to stick to our guns. We think the market is balancing. We think prices, assuming weather continues to be cold as it has been in November, the prices likely should get better. And I think as you pointed out in your mourning, no, price realization, Henry less $0.20 to $0.30 frankly, it has been widely fluctuating on a daily basis. In fact, yesterday, I think, it was $0.09 -- $0.05 yesterday. So, I mean it, it's all over the place. It's a product of supply and demand. We expect the basis to tighten back as more Marcellus gas stays in the Northeast and in the shoulder months, the basis widens. So, the question is just where is it going to stabilize. We think it's a product of just overall supply versus demand and regional demand, primarily, the Marcellus sucking up that Marcellus gas.

[Wells Fitzpatrick:]

Okay. No, that makes sense. And I know we had a sidebar on it, but it's great to see the public E&P is essentially at flat, if you believe consensus year-over-year and the same year that you’re still going to get [indiscernible] LNG demand. And I'm sorry, if you hit this in your prepared remarks. But, the pipeline maintenance that hit you in 3Q, is that ongoing or has that been resolved?

[Gil Goodrich:]

No. This is Gil. That was a phenomenon that came as a surprise to us that is now behind us and all those wells are back on at full rate.

[Wells Fitzpatrick:]

Okay, perfect. And then, just one last one for me. Obviously, both the Harris 23 & 14 are great wells. On a per foot one, the 23 is a little bit below. I assume that's for the same reason it always is when you have a longer lateral, but it's just kind of choking itself off. Is that a fair interpretation?

[Gil Goodrich:]

Yes. I think that -- we probably held that one back a little bit more. And Rob mentioned in his prepared remarks, we do have several other wells in that area. And they really are fantastic wells, and we didn't feel like it was necessary to push it. So, we just kind of held the choke to try to, we think, get a little bit flatter curve over time. So, that's why that piece a little bit lower per 1,000.

[Operator:]

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

[Joe Allman:]

My question is on capital efficiency. So, I saw all the things that you put in the presentation on capital efficiency. But like my main metric for capital efficiency is PD F&D. [Ph] So, when we look at 2019, say versus 2018. Do you think that capital efficiency has improved in 2019 versus 2018? And then, even during 2019, do you think as the years progress that you've improved capital efficiency? And I know slides 16, 18, kind of help address some of it. But, what are the factors, if in fact, capital efficiency has improved, what are the factors that are helping to improve capital efficiency?

[Robert Turnham:]

Well, Joe, this is Rob. I'll tell you, first of all, it's up to Netherland Sewell who prepares the 100% of our gas reserves, as to what those EURs are. We continue to plot against 2.5 Bcf per 1,000 feet. They're a little bit less than that, mainly because they take the future off at a steeper pitch. So, their terminal decline rate, they may take a point in time in the future and just take it off steeper to be more conservative. So, that clearly factors into proved developed finding cost. I will say that we've added a number of these wells, in particular Thorn Lake and we've got 2 Loftus wells, they are just -- that have been really good, another well called our Melody Jones has been very good. So, again, we'll just have to see at the end of the year, whether those get us a lower proved developed finding and development costs.Our DD&A rate was $1.06, I think, which is certainly reflective of finding cost over time. And we'll just have to see. But, the well results, frankly, as you know, because you plot Haynesville operators by foot, show us as number one productive wells by foot. And we expect that to translate well once we deliver our reserve report at year-end.

[Joe Allman:]

So, in terms -- in the numerator that equation, so have you seen things improve kind of in the numerators in terms of cost per well in 2019 versus 2018 and even through 2019?

[Robert Turnham:]

Yes. Just as a follow-up on that. So, I think, and maybe we've discussed this with you, certainly with others before. We are really focused on increasing our well results versus cutting costs because we see real benefit, in particular because of our hedge book, in delivering the best production results that we can. And so, that's why, instead of adjusting our CapEx numbers in our economic slides down, because of lower service costs, we basically kept those costs similar, and we're tightening our frack intervals, which, even though the cost per stage is a lot lower than it used to be, we're doing more stages because we're doing tighter frac interval spacing. And we just -- we see the benefit instead of keeping the completion, the same as what we were doing back when we were pumping a stage over 150 to 200 feet, we've reduced it on average to about 125 feet. And again, even though the price per stage is a good bit lower, the costs are similar or on our assumptions. And so, I think, all things being equal, we would hope to have a similar proved, a similar DD&A right as we enter 2020. But again, it's out of our control. So, we see the Netherland Sewell report.

[Operator:]

[Operator Instructions] As there are no further questions, I'd like to turn the conference back over to Gil Goodrich, for any closing remarks.

[Gil Goodrich:]

Yes. Thank you very much. We appreciate everyone’s participation this morning. And we look forward to reporting our fourth quarter numbers to you at year-end early in 2020. Thank you.

[Operator:]

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