Goodrich Petroleum Corporation (NYSE:GDP) Q4 2019 Earnings Conference Call March 5, 2020 11:00 AM ET
Gil Goodrich - Chairman and CEO
Rob Turnham - President and COO
Conference Call Participants
Dun McIntosh - Johnson Rice
Wells Fitzpatrick - SunTrust
Phillips Johnston - Capital One
Noel Parks - Coker & Palmer
Good day and welcome to Goodrich Petroleum Fourth Quarter and Year End 2019 Financial Results Earnings Call. All participants will be in listen-only mode. [Operator Instructions] After today’s presentation there will be an opportunity to ask questions. Please note the event is being recorded.
And I’d like to turn the conference over to Mr. Gil Goodrich, Chairman and CEO. Please go ahead.
Good morning, everyone. Thanks for participating in our fourth quarter and full year 2019 earnings call this morning. The current natural gas market presents challenges for all natural gas producers and we are no exception. However, we are blessed with a strong balance sheet which currently represents a net-to-EBITDA of approximately 1.25 times when annualizing our most recent quarterly EBITDA.
This relatively low level of debt, the very high quality of our Haynesville assets and inventory and our very good hedge position provides us great flexibility to execute and deliver positive results during this period of low natural gas prices, as well as to prepare us to resume higher levels of growth when the market has recovered and provides more compelling returns on our capital. We are watching the markets closely and routinely discussing strategic options with our Board to ensure we execute the right plan and strategy for our shareholders during this period of reduced commodity prices.
Our hedging position continues to provide us with excellent protection from the current low prices and delivered almost $10 million in realized derivative gains in 2019. Our current forward hedge position through 2020 covers approximately 50% of current production at a minimum blended floor price of approximately $2.60 per Mcf. While our realized field level natural gas prices averaged just $2.14 per Mcf in the fourth quarter, when factoring in the benefit of our realized hedge gains on our natural gas derivatives, net realized prices were $2.53 per Mcf.
In addition, the quality of our Haynesville asset is demonstrated by the continued improvement in well performance reserves and returns on capital investments, all of which we will review with you this morning. While we currently are maintaining a 1 rig drilling program in the Haynesville, we retain the flexibility to pick up or slow down the pace of development as well as the cadence of completions. Any changes to our capital plans will be made after a careful review and deliberation with our Board of Directors and done on a quarterly basis. We’ll be meeting with our Board next week for our March meeting.
We anticipate generating free cash flow in 2020 and any potential changes in capital planning, will be done with an eye toward further strengthening the company, its balance sheet and achieving the optimum amount of free cash flow during this period of depressed natural gas prices. 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. You can access the slide presentation on our Goodrich Petroleum website in the tab entitled 4Q 2019 Earnings Presentation.
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 2. On Slide 3, we are now providing all of our stakeholders, information regarding our environmental, social and governance statistics. We hope this information is helpful, and we will continue to strive to provide the most current and transparent information we can as it pertains to ESG.
On Slide 4, we have again included an overview of the company and our assets with highlights our core Haynesville Shale position in Northwest Louisiana, where our inventory life has grown to approximately 16 years of net inventory, as we have slowed our pace of development in response to current lower natural gas prices. This inventory contains over 1 Tcf of natural gas reserve potential and a clear runway of well delineated de-risked development for years to come.
The company’s total net production hit an average of 145,000 million cubic feet of natural gas and equivalents per day in the fourth quarter. And for the full year, net production grew year-over-year by 85%. Our reserves at year end averaged approximately 2.5 Bcf per 1,000 feet of lateral for all of our higher profit, tighter frac interval space wells that we have drilled over the last three years.
Performance from our refined completion designs, lower cost of goods and services, very low LOE and our hedge position are collectively delivering very solid returns. For full year 2019, our return on capital employed or ROCE was approximately 12%. I will show you how that compares with our peers in just a moment.
Solid production performance, cost containment in approximately $3.4 million of realized hedge benefit delivered EBITDA in the fourth quarter of approximately $21 million. For the full year, we achieved $79 million in EBITDA. We again delivered top tier capital efficiency while maintaining low leverage on our balance sheet.
On Slide 5, we present our year end 2019 SEC proved reserve which grew to 517 Bcf with a present value of just under $300 million using SEC mandated pricing and discounted at 10%. As you’ll see from the pie charts, our proved reserves are almost exclusively natural gas and associated with the core Haynesville Shale assets.
On Slide 6, we provide an updated cap table as of the end of the year. At year end, total net debt was $104 million with approximately $93 million outstanding under our senior credit facility, which currently has a borrowing base of $125 million.
Turning to Slide 7, we provide our quarterly production chart which shows the continued growth we have achieved, and as I mentioned, averaged 145,000 million cubic feet of gas per day in the fourth quarter. In addition, we provide the midpoint of our current plan and guidance for 2020.
On Slide 8, we provide detailed volume and price information our current natural gas and crude oil positions. As you can see, we are very well hedged to all of this year, with a combined 70 million cubic feet of natural gas hedged at a blended average floor price of $2.60 per Mcf, which provide solid protection against the currently depressed natural gas market. We continue to watch the natural gas markets closely for additional opportunities to add to our hedge position to both support and protect our capital planning.
Finally, we provide our current 2020 guidance on Slide 8, which provides for more modest year-over-year growth with a projected midpoint of production equal to an average of 149,000 million cubic feet of natural gas and equivalents per day, on a CapEx program with a midpoint of $60 million.
We’ve also updated our guidance for the expected basis differential in the Haynesville as well as estimates of our 2020 per unit cash cost on a per Mcfe basis. And in addition, we did provide the anticipated well count and completion cadence for you on a quarterly basis.
I’ll now turn the call over to Rob.
Thanks, Gil. As stated earlier, production averaged approximately 145 million cubic feet equivalent per day in the fourth quarter, which was at the high end of our previous guidance range of 140 million to 145 million cubic feet equivalent per day, primarily driven by the participation in a non-operated well in the quarter that was unexpected at the time of our previous guidance.
Revenues adjusted for cash settled derivatives total $33.6 million for the quarter comprised of $30.2 million of oil and natural gas revenues and $3.4 million of cash settled derivatives. Our per unit cash operating expense, which is defined as per unit operating expenses excluding DD&A and non-cash GMA dropped to $0.97 per Mcfe in the quarter, generating a cash margin of 62%.
Capital expenditures for the quarter totaled $18.5 million, of which, 99% was spent on drilling and completion of costs associated with Haynesville wells. The fourth quarter capital expenditures were higher than our previous guidance, again, due to the participation in one previously unanticipated non-op Haynesville well in the quarter. Capital expenditures for the year totaled $98.4 million, a 99% was spent on drilling and completion costs in the Haynesville.
We conducted drilling or completion operations on 16 gross wells in 2019, and added 3 gross, 1.85 net and 9 gross 7.2 net wells during the quarter and year respectively. We previously gave guidance for 2020 in December, but as Gil said, it is subject to quarterly review by the company’s Board of Directors, with the primary goal of being cash flow generation from modest growth and volumes hedge realizations and a continuing reduction in cash operating expenses.
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-in-kind interest, and $400,000 of amortization of debt discount and debt issuance cost primarily associated with the company’s second lien notes.
Moving back to our slide deck, as we have highlighted before, we’ve included several slides beginning with Slide 10 that show how we compared to our peers. As stated earlier, and as you will see on Slide 9, our return on capital employed for the year was 12.4%, despite very low commodity prices, which ranks 4th out of the 39 companies in our peer group that have reported fourth quarter financials as of Tuesday.
In addition to returns, it is critical to maintain low leverage in these challenging times for commodity prices. And we are focused on maintaining a debt to EBITDA ratio of 1.5 times or less and we’re below this market currently and expect to remain there in the foreseeable future.
Even though our capital efficiency and return on capital employed are near the top of the peer group and our debt to EBITDA is conservative, we only trade at approximately 2 times enterprise value to EBITDA as shown on Slide 12, which needless to say is an extremely low multiple versus our peer company average of over 4 times.
As everyone likely knows by now, all of our current activities are centered in the core of the Haynesville beginning of Slides 13 and 14. We entered 2020 with 22,000 net acres in the core of the play and 208 gross, 91 net locations on spacing of 880 feet between well bores for a net inventory life of approximately 16 years at current pace as Gil stated earlier.
These 208 gross, 91 net locations are all in the core of North Louisiana. Our acreage in North Louisiana is over 70% undeveloped and 73% operated. We have granted our acreage and expect to continue to swap acreage or drill joint wells with offset operators to maximize our returns.
We estimate over 1 Tcf of reserve exposure at 2.5 Bcf per 1,000 feet of lateral and 800 foot spacing in North Louisiana alone versus year end ‘19 book reserves in North Louisiana and those are proved reserves of approximately 510 Bcf equivalent. We also maintain approximately 3,000 net acres held by production in the Angelina River Trend of the Shelby Trough for future development. The Haynesville and Bossier formations are both perspective on our Angelina River Trend acreage.
As shown on Slide 15, all of our acreage has now been de-risked and we’re in development mode, drilling predictable wells in proven areas and connecting these wells into existing pipes with excess capacity. We’ve allocated approximately 90% of our 2020 preliminary capital expenditure budget to Bethany-Longstreet and the other 10% to the Thorn LAKE area.
We continue to outperform our type curves, and on Slide 16, we’re tracking our wells versus 309, 4,600 foot lateral industry wells drilled in the core. The industry pumped an average of 3,100 pounds per foot on these 309 wells. But as you can see, the older wells are underperforming the newer wells as average proppant is lower on those older wells.
Our 6 wells shown in green were stimulated with approximately 4,100 pounds of proppant per foot, and tighter clusters spacing and interval spacing and not only are they quite a bit better than the industry average composite kind of curve, but our composite curve exceeds our 2.5 Bcf per 1,000 foot curve to an estimate of approximately 2.7 Bcf per thousand. There is a clear correlation between proppant loading and cluster and interval spacing and we expect our more recent wells to pull up the composite curve over time as we reached completion optimization over the last 18 months.
Slide 17 reflects our 7,500 foot curve, where we now show a composite of 225 industry wells with average proppant and concentration of approximately 3,000 pounds per foot, which for the most part fits our 2.5 Bcf per thousand foot type curve. The older wells included in the industry composite curve that are underperforming the curve in the later years are a handful of under-stimulated wells with proppant loading of approximately 2,300 pounds per foot.
Like the 4,600 foot laterals, our more recent operated 7,500 foot wells are outperforming materially the composite estimate of approximately 2.8 Bcf per 1,000 feet due to higher proppant concentration and again, tighter cluster and frac interval spacing.
Slide 18, which now shows a composite result from 225, 10,000 foot laterals with an average of 3,000 pounds per foot of proppant are for the most part tracking or 2.5 Bcf per thousand foot type curve. The older wells here with low proppant concentration kick in a little over 2 years out and are falling below the curve, once again, tight correlation with proppant loading and EUR. Our 9 wells, which averaged approximately 9,600 feet of lateral and 3,500 pounds per foot of proppant are for the most part tracking our 2.5 Bcf per thousand curves.
We believe our well performance speaks for itself and is driven by a number of factors, quality of our acreage and no question, we’re in some of the best rock in the play, an optimum completion methodology where proppant concentration, cluster and interval spacing and pump rates, provide a material difference in results and flow back technique that minimizes daily draw down, flatness of the decline curves, provides high recoveries of gas in plays and most importantly, maximizes returns.
We’ve updated our economics and shown – as shown on Slides 19 through 21, to reflect our outperformance and to also include a $2 gas price on the low end of the range. Our economics have improved on our 4,600 and 7,500 foot laterals due to outperformance. As you can see, even at $2.25 gas price, we can generate a 40% IRR on our average 7,500 foot lateral wells.
As a reminder, the Haynesville economics are driven by high volumes, attractive net backs relative to Henry Hub as compared to other gas basins, low service costs, low lifting costs and severance tax abatement until the earlier of two years or payout of the well.
In summary, although we can’t control commodity prices, our team is executing well, our balance sheet is in good shape with low debt metrics, we have a nice hedge position that is minimizing our commodity price risk and a unit cost structure that is declining, creating competitive margins.
With that, I’ll turn it back to Nick for Q&A.
We’ll now begin the question-and-answer session. [Operator Instructions] First question comes from Dun McIntosh with Johnson Rice. Please go ahead.
Good morning, Rob and Gil.
I wonder if you could provide a little more color around the optionality in your 2020 program. You know, just running 1 rig, is it – would it be, you know, if prices do remain low or would it be laying that rig down for a while and you know, maybe picking up, looking for some more non-op opportunities or kind of how do you think about that it would, obviously, free cash flow kind of being the driver in this environment?
Yeah, this is Gil. Thanks, Dun. Well lots of great flexibility. We do have some areas you know, Rob alluded to in his prepared remarks, we had a kind of an unexpected non-op proposal come up to us on really good acreage, and we didn’t want to let that opportunity get away. So we elected to participate in that well. We have several of those that could be potential opportunities in 2020 and we’re still trying to get our arms around the exact timing of that and we will backfill around with our offline activity for whatever that level of non-op participation is.
That being said, we got great flexibility and we’re running the 1 rig now. I think one of the things that we could do is, is maybe just build some DUCs, keep the rig for a period of time, build a few DUCs and complete them and on cadence, that makes sense with natural gas prices. So as I alluded to in my remarks, we’ll be reviewing a number of different scenarios with the Board next week and staying with the base case guidance we’ve provided is one of those options obviously, then we may decide that we want to slow down a little bit. I really don’t think you’ll see us pick up with the pace at this point in time.
And Dun, this is Rob, I’ll add to that. As far as swaps, we continue to do that. We think there’s a chance of perhaps picking up a little bit of incremental, you know, bolt-on type acquisitions through certain swaps, but nothing definitive to talk about now.
Okay, great. Thanks. And then maybe from a little bit higher level macro question, you know, the Haynesville rig count was surprisingly resilient through the back half of ’19 and recognizing that private operators drove a lot of that, but kind of what do you see now and how do you think about the Haynesville activity in context to kind of the broader natural gas space and what’s your thoughts on kind of looking out 12 months, 18 months with respect to price and kind of the ideology maybe at low prices or fixed low prices, just kind of any color you can give there and how –
Sure, this you know, I’ll start and then Rob can chime in. obviously our crystal balls not necessarily any better than anyone else’s. We will say that we track all Haynesville activity very closely on a weekly basis. We are hand-sculpting that to specific Haynesville-only rigs. Sometimes if you look at just kind of general area, we’ll pick up some Cotton Valley activity and non-Haynesville stuff.
Our internal numbers suggests that the Haynesville rig count hit about 60 rigs at a peak last year and the most recent week it’s at 38. My personal belief is that, that number comes inside of 30 and probably does fairly soon. And we’ll be – ultimately this year will be one of those rigs, I believe that we’ll laying down our rig and building some DUCs as I said and completing some wells later in the year.
I can’t help to believe given where natural gas prices and strip prices are, you know, while most people are fairly well hedged this year that begins to change quite dramatically in 2021. And as we move closer and closer to ‘21, either the strips going to come up or CapEx levels are going to come down in terms of natural gas activity.
And the only thing I’ll add, Dun is, we belong to a consortium, which includes most of the operators in North Louisiana. And the commentary is, it’s consistent with what Gil just described, which and it includes quite a few privates that people you know, don’t have intelligence on. So the direction is clearly, rigs coming out of the base and which we think obviously is a real positive on declines in supply, not just there, but you’ll see them continuing in the Marcellus which ultimately, you know, fixes the commodity, the strip ought to go in contango, and then you’ll have a real reason for people to kind of jump back into the space.
All right, great. Thanks and congrats on a strong ‘19 and a solid ‘20 outlook.
Thank you, Dun.
Next question comes from Wells Fitzpatrick of SunTrust. Please go ahead.
Hey, good morning.
Can we talk a little bit more about the divergent and the curves on the lateral length? I mean, more specifically, I’m a little bit surprised that the mid ranger would be better than the 10,000 footer. You know, how – I guess how clean is that data? I mean, it’s, you know, how many wells do you have in each sample set? And it’s some of that may be kind of the fact that you don’t necessarily have as many maybe 4,600s as you do 10,000 footers, et cetera?
Yeah, so this is Rob, I’ll take a shot at that. If you look at – so for example, the 4,600 foot laterals and the newer wells flow through the curve, we think that composite result is going to only get better and you can see that over the first 18 months those wells are producing far in excess of the older wells, you know, they kick in and call it 20 months. So we – all we’ve done is taken the composite of those wells that we show on that graph and model that out using standard you know, terminal declined rates as used by [indiscernible].
But we think there’s an upside to the 4,600 foot case, up and above – over and above the 2.7 Bcf per 1,000 that we’ve used in the updated economics. We’ll tell you one other thing that we see some benefit there, which is the ability to nail your capital expenditures, you know, right on your AFE, obviously, the shorter the lateral, the higher the probability of meeting or beating those cost estimates.
As to the 7,500 would make great progress there. That’s – those economics have moved a good bit. The previous economics for example, on a 7,500 foot lateral were 45% IRR at $2.50 and that’s, you know, 59% now, so really almost 15% incremental IRR. And like the 4,600 foot laterals, we started tightening up our frac interval spacing, increasing our proppant loading a bit and similar to the 4,600 foot curve, you see over the early 18 months those wells are outperforming and again, should pull up the curve over time as those wells flow through the curve. So we feel very good about that.
When you look at the 10,000 foot laterals, you know, we have similar proppant probably than what we have before the, you know, the proppant loading, again, is in a similar range, the interval spacing on average is about 125 feet per stage versus a little less than that on the 4,600s. So, again, and even the 7,500s the better wells that pull it up or even tighter than that at 100 foot intervals. So, clearly you know, when we do linear regression, very good correlation on proppant per foot and interval spacing per foot. And we think that’s shown up here.
The only problem with tightening your intervals on the 10,000 foot laterals to a 100 feet or 110 is just the cost of the well. And as we’ve talked before, anytime you extend past 7,500 feet, if you have the need to trip out a hole and replace bottom hole assembly or bit, you’re adding to your cost of the wellbore. So – and it’s a, you know, 3-day or 4-day turnaround. So we – you know, all things being equal, you could say your 7,500s or your sweet spot in that you have less risk on exceeding your AFE and you’re generating very good rates of return that are actually similar, if not, better than your 10,000 foot laterals, because the results have been better.
Okay, okay that makes sense. So it sounds like the 4,600s have probably the most room to improve versus the rest of them. But can you remind us how many of your locations are 7,000 foot or greater?
Yeah, it’s a moving target. You know, I would say, depending on how we structure that, you could probably get, you know, 40%, 50% longer laterals. And then the 4,600s, you know, would be, you know, call it 50% to 60%. That being said, with acreage swaps, we’ve been drilling longer laterals. So I think the likelihood is that, it could be as you know, be more like a third, a third, a third.
But we’ve – but if you just grid it out right now we have, you know, plenty of 4,600s to drill and that’s why you know, spending, you know, our well costs, you know, in some cases are probably slightly higher than others, but we’re outperforming those other companies because of our well design. And when you really do the math and you run the economics, yeah, you can save money by pumping less proppant, and you’re going to automatically make poorer wells and we just see the real benefit from the proppant loading in the tight interval spacing.
Okay, okay, that makes sense. And then, you know, kind of look into 2020, you talked about this a little bit, but can you talk to the non-op visibility from a CapEx standpoint? And I assume, given your prior comments that if anything that would be biased downwards?
Yeah, so this is Gil, Wells. First of all, it’s very difficult to give you a whole lot of clarity, because as were just happened in this last quarter, we had something pop up that we didn’t even know, you know, it was some activity on some acreage that the well proposal just came out of nowhere.
And so we don’t expect very much of that this year, we think that what’s coming, we do see, we’re still trying to get our arms around the exact timing of that. And as I said, we’ve got the flexibility with the rig and more importantly, the casing and completion cadence to kind of backfill around that from a capital perspective and blended out on a quarterly basis.
Okay, perfect. That’s all I have. Thank you so much.
Next question comes from Phillips Johnston, Capital One. Please go ahead.
Hey, guys. Thanks and thanks for the disclosure around PDP, PV10 at year end. I think it’s just speak to the – yeah, I think it speaks to the value here. My question is, what would that approximately $600 million of PDP value look like if you ran it at sort of a flat $2 gas price instead of the SEC deck?
Yeah, we’ve not done the sensitivity yet. We’ve been you know, kind of run around with our head cut off getting ready for the 10-K in the call. I’ll have to get back with you on that sensitivity, Phillips.
Okay, Rob. And then you guys given some good color around just the quarterly cadence of net well counts for the year. So just wanted to see what that schedule means for quarterly-wise at least from a directional standpoint, I think your guidance implies fully or average it’s around 3% above kind of that fourth quarter ‘19 exit rate. So should we expect fairly even, you know, quarterly sequential growth throughout the year versus that exit rate or is there some lumpiness in production –
Yeah, there is going to be a little lumpiness, because if you look at the Slide number 9, current guidance, you know, has us only completing 1 net well in the first quarter, and then to 2.3 net in the second, 1.8 in the third and 0.7 in the fourth. So as our budget currently sits, you know, going to be a surge kind of in the second and third quarter and we’ll try to get a little bit more guidance as Gail said, we got a Board meeting next week and we’ll see if this changes at all, but yeah, it’ll be – it certainly would be lumpy and peaking in the second and third quarter.
Okay. So for Q1, should we expect maybe down a little bit and then surging in second and third quarter and then maybe down a little bit in Q4?
Yeah, exactly, right. Directionally.
Okay, all right. Perfect. Thanks, Rob.
Next question comes from Noel Parks, Coker & Palmer. Please go ahead.
Hey. Good morning.
Good morning, Noel.
I just want to check in, sorry if you’ve touched on this already. But the non-op well, that you had in fourth quarter. What was the working interest on that?
Yeah. Likely close to 25% working interest, but we incurred all of the capital in December. So and net acreage by the way was kind of near the Louisiana border in East Texas, if – someone else called me and said, you know, it looks like you had an increase in reserves in East Texas. It was basically just our interest from that well.
Gotcha. And just sort of thinking of all the volatility we’ve had in commodity prices. And as you look ahead to the sort of longer-term, the gas landscape, you know, with oil having taken, you know, having a tough time again with the recent events, do you have any assumptions about just what the associated gas, you know, input into the system from the Permian, you know, what that would look like? And if, you know, for example, if we were headed for a considerably weaker environment for oil and, you know, we saw activity slow maybe on what we, you know, have been expecting for the next couple of years? Do you think that would have an effect either regionally on prices for you or even on the benchmark itself?
Yeah. This is Rob, I’ll take a first stab at it. You know, we’ve seen and we have hedging consultant group that advises us on some of that, I think the numbers are really moving. If you assume 1 million barrel a day growth in the Permian, which we would bias lower than that based on where prices are, where you know, how conservative the banks are, the capital markets being somewhat close. We think it’s going to be less than that.
And we’ve seen you know, 3.5 Bcf a day or thereabouts of associated gas growth, if my memory serves me, for the 1 million barrel a day, which you know, we think should be biased low. And of course, the problem is the takeaway is not there to capture all those volumes. So, we think, you know, the true output coming from the basin is going to be a good bit lower than that.
If you then look at that the Haynesville and Marcellus currently in decline. And we don’t think it’s freeze offs. And certainly not in the Haynesville, maybe there’s a little bit in the Marcellus we think it’s more cutting of CapEx budgets to live within their means, then clearly we’re declining there, and we’re going to have less associated gas, and as long as demand remains and certainly coronavirus hasn’t helped and we’re suffering through some oversupply on LNG currently, as long as that kind of gets back to where we think it should be, then the back half of this year ought to be better for gas prices and likely for oil prices as well.
And as I said, you know, Gil could chime in, but, you know, what we really need is, people that live within their means, let’s see the rollover continue on supply and then they’ll reach a point in time where we think the strip will go in contango, then the industry is more investable at that point.
Great, thanks a lot.
[Operator Instructions] This concludes our question-and-answer session. I would like to turn the conference back over to Mr. Gil Goodrich for any closing remarks. Please go ahead.
Thank you very much, everyone. We appreciate your participation this morning and we look forward to reporting our first quarter 2020 reports to you in early May. Thank you.
The conference is now concluded. Thank you for attending today’s presentation. You may now disconnect.