Q4 2020 Goodrich Petroleum Corp Earnings Call
Ladies and gentlemen, thank you for standing by the conference will begin shortly please continue to hold and thank you for your patience.
[music].
Good day and welcome to the Goodrich Petroleum fourth quarter and year end 2020 earnings call. All participants will be in a listen only mode should you need assistance. Please signal a conference specialist by pressing Star then zero. After today's presentation, there will be an opportunity to ask questions to ask a question you May Press Star then one on the touch.
<unk> Town center to withdraw your question. Please press Star then two.
Note. This event is being recorded I would now like to turn the conference over to Gil Goodrich Chairman and CEO. Please go ahead.
Good morning, everyone and thank you for participating in our year end 2020, and fourth quarter earnings call. This morning are.
Joining me this morning is our president Rob turn them.
Also joining us is Mike Kelly, our executive Vice President and Chief on it and excuse me in General Counsel and Chris meant waters.
Senior Vice President and Chief Financial Officer.
We've again prepared a slide presentation for you and we invite you to follow along the slide deck. During our prepared remarks, you can access the slide presentation on the Goodrich petroleum website entitled fourth quarter and year end 2020 earnings call.
I'll begin my remarks, this morning by using the presentation slide deck and at the outset, you will see our standard disclaimer forward looking statements and risk factors, which are highlighted for you on slide two.
We've again updated our environmental social and governance statistics on slide three please review this information and we will continue to update this slide as conditions and best practices evolve over time.
As you will see we flare negligible percentage of our production and have very low emissions, we continue to work diligently.
To meet or exceed these standards.
On slide four we provide an overview of the company and our key highlights which had been updated as of the end of last year.
The key highlights is the 4000 net acres, we added to our position in inventory in the core of the Haynesville during 2020, including approximately 2000 net acres added during the fourth quarter.
These additions increase our acreage in the Haynesville to approximately 26000 net acres.
The acquisitions also helped boost our natural gas resource potential within the core of the Haynesville to over 1.8 Tcf.
During the fourth quarter, we experienced a slight delay in completion timing of several non operated Haynesville wells moved from the fourth quarter into the first quarter, which resulted in a slightly lower than previously expected quarterly production, which came in at 135 million cubic feet of natural gas and equivalents.
Per day.
Core behavioral Haynesville continues to generate outstanding results in 2020, we invested $56 $2 million in drilling and completion capital expenditures, which resulted in an all in organic finding cost of just 31 cents per M. C. F E, but more importantly, a proved.
Developed finding and development cost of 91 cents per M. C. F E, which is reflected in our DD&A rate going forward of approximately 88 cents per M. C. F E.
Moving to slide five we show our year end 2020 S. E. C proved reserves, which grew to 543 B C F E.
Using a range of natural gas prices from $2.50 to $3 per Mcf the present value discounted at 10 per cent of the year end proved reserves would range between 338 and $485 million.
At year end, our proved reserves were approximately 30% developed and almost exclusively associated with natural gas reserves and the Haynesville shale.
On slide six we've updated our capital position table for year end 2020, and pro forma for the additional $15 million of second lien notes, which we added subsequent to the end of the late of last year.
We used the proceeds from the additional two well notes to pay down the senior credit facility, which increases our liquidity and provides additional flexibility to accommodate any potential additions to both operated or non operated activities should natural gas prices and market conditions dictate.
The current borrowing base under the senior credit facility is $120 million, which provides pro forma liquidity as of the end of the year of approximately $39 million.
With an improved natural gas outlook, we are estimating a significant increase in EBITDA in 2021 compared to the $62 million reported for 2020, and we continue to project that our net debt to EBITDA at the end of this year will be approximately one times.
For trailing 12 months EBITDA equal to total debt.
We are currently conducting our spring borrowing base Redetermination and we expect to finalize that Redetermination next month.
On slide seven we show the significant growth in production, we've experienced since 2016 and the modest production growth. We had in 2020 over 2019 on materially less capex.
While net production grew by only 2.3 per cent year over year.
The modest growth was achieved on approximately $42 million of less drilling and completion capital expenditures.
Looking forward, we're expecting significant growth and have adjusted our full year 2021 production guidance to a range of 160 to 170 million cubic feet of gas equivalents per day, a reduction of approximately 3% from our prior guidance to accommodate for some additional non on.
Activity with later completion dates in the year as well as to adjust for the shut in and the impact of the recent snow and ice storms that impacted northwest Louisiana.
Since the end of the year, we have recently added nine gross or 3.2 net haynesville wells to production, which has resulted in any current net production of approximately 160 million cubic feet of gas and equivalents per day.
Moving to slide eight we provide our hedging summary, which shows the volume type and prices of our current natural gas and crude oil hedge positions.
Our current hedge position covers all of 2021 and through the first quarter of 2022.
Our hedges are a combination of swaps and collars with all of our callers beginning next month, having a floor of $2.50 and a ceiling of $3.50.
We continue to watch the markets closely and look for opportunities to prudently add to both the amount and tenure of our hedge position.
We've updated our full year guidance for you on slide nine.
We continue to plan to drill approximately 17 gross haynesville wells in 2021.
With a slight increase in the net well count to approximately 9.4 net wells.
However, we have made a slight shift in the cadence of completions towards the middle and back half of the year as I mentioned, a minute ago, which we've incorporated into our updated guidance, where we now predict a midpoint of 165 million cubic feet of gas and equivalents per day for 2021 on capital expenditures of approximately 80.
Million dollars at the midpoint.
In addition, we provided the expected range of operating cost per unit of production for 2021 as.
As we have stated previously the 2021 plan will be focused on our core acreage in the Haynesville of northwest Louisiana.
We continue to expect this Capex plan will result in annual production growth of 20 to 25 per cent over 2020, and generate meaningful free cash flow and with that I'll turn it over to Rob Turnham, Thanks ago Red.
Revenues adjusted for cash settled derivatives totaled 29.2 million comprised of $28 $9 million of oil and natural gas revenues and $300000 of cash settled derivatives.
The average realized price, including cash settled derivatives was $2 35 per mcf fee for the quarter on.
Per unit cash operating expense, which is defined as operating expenses, excluding DD&A impairment and noncash G&A was 97 cents per mcf equivalent.
And cash interest expense was seven cents per M cfe or a total of the dollar and four cents per Mcf equivalent.
Cash margin, including interest expense was $1 31 per Mcf P or 56% of realized price including settled derivatives.
As you will see in our slide deck and discuss later in my prepared remarks.
Just on fourth quarter results, we had the highest cash margin on any of our natural gas peer companies.
We are expecting this total cash unit costs, including interest to continue to decline in 2020 one.
With the midpoint of guidance less than a dollar per M. C F E.
Combined with much higher gas prices, we anticipate robust cash margin expansion, which will drive our projected free cash flow for the year.
Capital expenditures for the quarter totaled 11 million of which nearly all was spent on drilling completion and facility costs associated with Haynesville wells.
For the year, we spent approximately 56 and a half a million.
Interest expense totaled $1 6 million in the quarter, which included cash interest of $900000 incurred on the company's revolver and non cash interest of 700000 incurred on the company's convertible notes.
Turning back to our slide deck all of our activities remain in the core of the Haynesville as Gil stated beginning on slides 10 and 11.
Also as Gil stated, we announced an acquisition of an incremental 2000 net acres in the fourth quarter on a drill to earn basis, bringing our total to 26000 net acres in the core of the play.
We continue to seek and review bolt on opportunities to expand our footprint through acquisitions and drilled are on farm outs and we believe you could see additional expansion of our footprint with this strategy.
Our acreage is currently approximately 75 per cent undeveloped and 80 per cent operated.
On slide 12, we show our inventory in North, Louisiana, which totals approximately 1.85 Tcf of reserve exposure, including 559 Bcf a day and proved reserves at year end at $2 50 syngas.
We have not quantified or inventory at Angelina River or the Tms since all of our activity is planned for north Louisiana.
Our PV 10 for year end proved reserves at 250 to $3 flat pricing of $338 million to $485 million is significantly over our current enterprise value.
The activity map on slide 13 shows how consistent the play is in our area when drilling and completing wells in similar fashion.
Our acreage is fully derisk and ring fenced with very good wells.
We are in development mode drilling predictable wells in proven areas and connecting wells into existing pipes with excess capacity.
We continue to outperform our type curves and on slide 14, we track our short laterals versus 298 industry wells drilled nearby in the core.
Industry pumped on average of 2600 pounds per foot and as you can see our 10 wells are significantly outperforming the industry wells and our type curves.
Our 10 wells shown in Green were stimulated with approximately 4000 pounds per foot of profit with tighter cluster and cluster and interval spacing and as we have said before regression analysis shows a very good correlation between proppant loading and cluster and interval spacing to EUR and we expect our more recent wells to pull.
Up the composite curve over time from this optimization.
Slide 15 is a cumulative production curve and shows over time, how we are outperforming our type curves.
Slide 16.
<unk> reflects our 7500 foot curve, where we now show a composite of 207 industry wells with an average proppant loading of approximately 2500 pounds per foot, which for the most part fits our two and a half bcf per thousand foot type curve. Initially, but then falls off as the older wells that are under stimulated.
Fall below the curve.
Like the shorter laterals, our more recent operated 7500 foot wells are materially outperforming our type curves.
Slide 17 again just shows how we are outperforming our type curves on accumulative basis.
On slide 18, we track our 910000 foot laterals against the 187 industry wells drilled and completed in our areas as you will see we've for the most part are tracking our type curve and industry, mainly because we've only recently completed wells with the newer completion design.
We are very optimistic with early time flow back from our two recent wells just completed that we will be able to flatten the curve with a potential to outperform versus our type curve.
Again, slide 19, Trikes cumulative production relative to our type curve.
As we have stated before we believe our well performance speaks for itself and is driven by a number of factors.
Quality of our acreage in the core of the play an optimum completion design, where proppant concentration fluid levels cluster and interval spacing and pump rates provide a material difference in results and flowback technique that minimizes daily drawdown flattens the decline curves.
By its high recoveries of gas in place and most importantly maximizes returns.
Our economics as shown on slides 20 through 22, which reflect our well results on the reduction in service costs that we have seen are as good as we've seen them in the basin.
The outperformance of our curves on the 40, 670, 500 foot laterals and service cost deflation across all wells has created a unique situation, where a minimum of $2 50 gas price, we can generate approximately 100 per cent or greater I are ours.
As a reminder, the Haynesville economics are driven by high volumes attractive net backs relative to Henry hub as compared to the other gas basins.
Low lifting costs and severance tax abatement until the earlier of two years or payout of the well.
Moving to slides 23, and 24, our cash cost per unit of a dollar for has US ranked second among our gas peers and our cash margin of $1 31, or 56% of our realized price ranks first among our peers.
Our return on invested capital as shown on slide 25 remains extremely attractive at 38 per cent, which has us the number one ranked company out of our gas peers and if you will flip to slide 26, you will see we rank second on this return metric in the much larger 34 company peer group, which includes.
The predominant oil companies.
For 2021 when you bake in on expected lower per unit costs and the forward gas curve, we anticipate our cash margin and return on invested capital to move even higher.
In summary, our turret our team is expects acute well our balance sheet is in good shape with low debt metrics. We are generating superior returns both in the field and at the corporate level and we continue to add to our inventory depth with very accretive bolt on acquisitions.
With this favorable backdrop for 2020, one we look forward to sharing with you our results throughout the year.
And with that I'll turn it back to the operator for Q&A.
We will now begin the question and answer session to ask a question you May Press Star then one on your Touchtone phone on if you're using a speakerphone. Please pick up your handset before pressing the keys if at any time. Your question. That's been addressed and you would like to withdraw. Your question. Please press Star then two at this time, we will pause momentarily to assemble our raw.
Sure.
Our first question will come from Neal Dingmann with Truest. Please go ahead.
Good morning, guys. Just two quick ones can you hear me I'll do you hear me all right Rob.
Yeah, Yeah. Thanks, yeah, Okay.
One could you tell me it seems like you've had a little change in the non op activity could you tell me what what's the sort of Max I mean, again, maybe give us a little bit more color on whats ramp there how much more potential ramp or is it just obviously price right now what's driving that slide talking about the non op side, you've got a little bit.
Sure Neal this is Rob and it's really as you as you know because you've seen our acreage position Chesapeake is the predominant operator on a on join acreage are obviously, we are we operate 80 per cent of our position. So it's it's a minority position.
And with them emerging from from their restructuring, we've definitely seen a few more well proposals.
I think we have maybe five gross wells or interest in those wells is approximately 2025 per cent I would say on average so.
It's it's a manageable amount if you consider you know that that in essence is a little over one net well we do our best to ensure that the timing is accurately portrayed our land department talks to their land Department.
Extensively and so we feel like we have a good handle on that it's the magnitude of that is even if they ran two to three rigs on our acreage exclusively we think you know the gross acres left to be developed in our joint venture is about 9000 net acres out of their 225000 and so.
Doesn't seem likely to us that that you know they would put all two to three rigs on that acreage because it's a small subset of the total.
But that being said we're prepared to shift our operated budget down if we see multiple well proposals and for that reason, we don't enter into a long term drilling contracts. So we have total flexibility of doing that the other acreage that we participated in the on quite a few wells.
Was was Sabine over on the Texas, Louisiana border what caused the deferral of completions from the fourth quarter of 'twenty into the first quarter of 'twenty. One was just they they decided to drill two additional wells off of the same pads and therefore defer all of those wells to the.
Our first quarter so.
It was the right thing to do to fully develop the acreage, but it was unexpected and that's what caused our fourth quarter volumes, you know to be to be lower than expected.
Sure.
The other activity than really just one other one we're obviously seeing a lot of activity.
Just I would call on M&A and others. Just obviously, we thought we've seen about a potential IPO on the Haynesville, maybe the one I mean, we're just gonna be two others behind that so Rob could you just talk on M&A and what what this has joined to the play have you seen prices go up but you know I thought you did a little bolt on book was nice to see.
But I'm just wondering now it seems like theres going to be.
So much much more interest and continued interest on the play with these ipos et cetera, which is the good and bad thing I think you know looking at us versus them Bill looks incredibly cheap, but I'm just wondering more on the M&A side and asset side, what what do you think this will do for the flight. Thank you sure.
Sure Neal this is Gil and good morning, I would say that probably due to COVID-19 as much as anything else and I guess low natural gas prices. During 2020, it was pretty dead market, probably everywhere, but certainly that was true in the haynesville as you probably know the haynesville.
Position is not a huge from a geographic standpoint, and it really is dominated by call. It 10 10 large players.
Yes, we there is an IPO coming fairly soon we think that's a good thing for the play we we expect as you do that they're probably getting one or two more behind that we also think that will be a good thing for the play as well.
Whether or not there's a whole lot of combinations between our in basin players that are kind of remains to be seen.
What Chesapeake does post emergence is also a question, but they certainly now have a very good balance sheet and it looks to us like a very good strategy.
And we position them to be more acquisitive should they decide to do that very hard to handicap exactly what's going to happen getting back to our strategy. There are some smaller players and some smaller positions out there which is what we've really been targeting with our bolt ons I think as Rob said most of what we've done in the last year.
With the 4000 acres, we added was kind of a drill to earn where you've got someone who's.
Looking to get it developed may or may not have the capital or desire to spend the capital, whereas we do and we can make a deal that actually gets a well drilled that deliver some overriding interest to them.
Whereas it otherwise it's just sitting there. So we do expect with gas prices going up that acreage values will creep up during 2021 can't say, that's really happened yet, but we do expect that to happen, but we're going to continue to be opportunistic and try to cut deals that fit us and fit the stellar as well.
And Neal I'll add one one thing also we look forward to those road shows and and our Ipos because it'll bring a lot of attention to how our well results are as compared to others and I think it's just going to broaden the exposure for our company and emphasize you know how how good the acreage is in the <unk>.
All results had been to date.
I agree with you Rob. Thanks, Thanks, guys absolutely. Thanks Neal.
Our next question will come from Dun Mcintosh with Johnson Rice. Please go ahead.
Good morning, Joe moving up.
Good morning gun.
Oh, the wonder if you could give us a little more color around the impacts from the storms I'm, specifically thinking about you know kind of L. O <unk> and Workovers that you might have to do after that I appreciate getting the guide on the on the first quarter.
Yeah.
You're seeing there and.
I assume everything is back up and running and are now you know where I had some trouble with good things going on again.
Yeah. This is Rob, but yes, everything is back up and running you know ironically it didn't take very long once we were able to get back in the field to bring those wells back on the problem is we couldn't get to the field are the roads were iced over in trucks, where were idled. So we had significant production volume.
It wasn't below our hedged volumes, which we which we lock in at first of month, but but certainly and we sold some gas on gas daily, which you know which is gonna be on an attractive price, but but for the most part it just took some time and we adjusted our guide.
For the first quarter down to really take into effect that one other thing that that are also impacted the first quarter was a shut in of on offset well, while we were fracking. These two new 10000 foot wells and so when you factor that in plus the downtime.
That's what's driving you know a little bit lower first quarter volumes the than what we were expecting you also look at the non op activity, which I would say you know good news is the the the operators on our non op activity and know what they're doing and they're making good wells. The problem is we have less control over the timing of those <unk>.
<unk> and therefore, we built out a little more conservatism on that guide in the in the first quarter and frankly the guide for the year, we feel we feel more comfortable with that by deferring some of our operated activity pushing as Gil said the sequencing on the cadence.
Further into the year caused a modest decrease of you know call it 3% on production, but we're still on pace to what we think generate similar EBITDA and DCF and similar our free cash flow as we've guided before.
And Dun Dun. This is Gil I might just add is to your low your question, we expect a negligible impact on low from the storm. It really was just the shut in and put the wells back on.
Okay. Thank you and then for my follow up on Robert touched on it a little bit how should we think about the production cadence.
Given the impacts on the first quarter and.
The reshuffling of some of that activity.
We're kind of looking for coming out of the first quarter pretty steady growth, that's still a pretty fair assumption.
Yeah, and that's why we that's why we gave the 160 million a day a number in the press release, because obviously you know that you're seeing some wells come on on line, that's going to take US two to to another level on production. We also have a well that's going on going to get Fracked.
The first of April.
First week of April where we currently expect it it's an operated well it's another 10000 foot lateral that we have a high working interest and so I think you know and we had to kind of work our way through the day the completion deferrals on the non upside in the freeze, but it just feels like and now you could see some momentum are GAAP.
Which is why gathering and particularly on the second quarter and then throughout the rest of the year, which is why we were comfortable with revising the guidance, but but keeping.
Keeping the number pretty high.
Alright, thank you.
Thanks Dawn.
Our next question will come from Phillips Johnston with capital one. Please go ahead.
Hey, guys. Thank you, obviously, some timing factors and other.
And thank you book.
When we look at your well performance in terms of productivity.
Hey data really does.
But your wells.
Right.
It sounds like that's mostly a function of.
I appreciate that but is there anything per mile location standpoint, it's also.
Driving the outperform it seems like most of the wells located in the southern corner.
I guess I guess, what I'm trying to ask is did you expect somewhere else.
Sort of.
Towards the north.
Yeah, Hey, Philips this Gail good morning.
Great question, Yeah. So obviously, it's rocks that's driving.
That in addition to the things that Rob outlined which is the completion design, which has been a bit of an evolution over the last few years, both ourselves and working with our peer partners in the play.
To get down to what we think is best practices in terms of finding the best are our sweet spot. If you will so clearly Bethany Longstreet is core of the core delivering fantastic results.
You go North and we've said this for a while the quality of hungry diminishes ever so slightly and we believe and I've said this for several years now that our Greenwood Wascom acreage, where we do plan to drill some wells.
Sometime later this year going into early 2022.
Is maybe.
10%, 5% to 10% below what we see at Bethany Longstreet, and we're coming up with that based on a number of things billets.
One is the old historical wells that we drilled back in the 2009 2010 range and we can compare those wells results with the old wells, we drilled at Bethany Longstreet, but I think more importantly, Comstock a private company called Pine wave.
Trinity operating and others have been drilling all around our Greenwood wash them acreage over the last couple of years and seeing really really good results. So I think where we would be today as we would guide towards whereas Bethany longstreet might be two and a half Bcf per thousand we think two three bcf per thousand feet is probably the.
Best the best read on that area based on the results.
The we've seen over the last couple of years from wells drilled around us that are longer lateral tighter spacing and higher profit wells.
Okay. That's perfect I appreciate all those details.
And then I guess the company that's about to go public it's growth.
Very impressive results.
Closure.
Obviously that hasn't been a focus for you guys, but can you remind us what you've said about that zone as it relates to your paper.
Yeah.
Philip This is robin and thanks for your questions and support.
We really don't think we have great middle Bossier are the further south you go in the play the more the better the the Bossier is and correspondingly the worst the Haynesville is so where where we are we're just not counting on any any potential in the middle of.
Moshe we may ultimately find that it can work in certain areas, but we would rather everyone. Just focus on the Haynesville you know across our block.
Okay guys. Thank you.
Phil.
Again, if you have a question. Please press Star then one our next question will come from Noel Parks with Tuohy Brothers. Please go ahead.
Good morning good.
Morning Noelle.
Just on a couple of questions just one quick one on the.
Acquisition.
On this drill to build the one that you.
Ah well put together.
Together.
So just curious kind of what what vintage or when when roughly where the was that original leasing done I was just curious about what the royalty like that on that you know how it compares to net.
You are sort of our Haynesville average.
No. This is Rob yeah interesting and good question it varies really if.
If you look at the 4000 net acres that we've acquired throughout 2020. Some of that acreage was was a held by production.
In particular from shallow wells and as Gil mentioned the companies that owned it couldn't afford really two two or chose not to raise the capital to develop on the property.
And it and so if you don't think you can or you don't want to develop your haynesville, you're really faced with two things sell the property and and even though people are allocating pretty good hide prices per acre. It may not be what you want to sell it and we're able to as Gil said dragged the rig.
Zen drill and in many cases multiple wells and the revenue generated from their overriding royalty interest.
Generates a good bit more money to them than what they would get by just selling be undeveloped acres. So I think it's a win win for the seller. It's a win win for US we're getting similar net revenue interest of what we have on the rest of our acreage and all we have to do a shuffle, but really the drilling schedule around such that we can.
Incorporate those those obligation wells, if you will to capture the acreage. So so far it's worked extremely well for us and it's worked extremely well for the seller and we welcome you know other opportunities in the and in fact continue to evaluate you know additional drill to earn opportunities.
Great. Thanks, and then I think you.
Went over this but just to make sure I understand I am I I did notice, especially on the 7500 foot type curve.
The addition, I think you had a net one average of 12.
A good rich wells in there.
So as as you as you go further to the right and it it sort of looks like the.
On the wells.
Get closer to the type curve that that is mostly just an artifact of the.
Section being dominated by the older wells right because.
It's.
Okay, Great. That's a great point I, probably should've, we probably should have put that in our remarks, we've always talked about the more recent wells being better stimulated and overtime pulling up that curve, which is if you. If you look back at some old presentations, that's exactly what has happened right and it's fewer well.
Wells that were under stimulated and so it's a combination when you when you combine the the 12 well average on the low on page 16.
It's not 12 wells you know 32 months out that's those are the first few wells that we drilled in and at the tail end of it it's probably one well.
And then over time as the completion recipes have evolved and we've drilled more recent time wells. That's why you see the you know from month one through 28, that's why you see that those wells.
And outperforming on.
The current by a dramatic amount.
Great. Thanks, that's all I had.
Thanks Noel.
This concludes our question and answer session I'd like to hand on the conference back over to Gil Goodrich for any closing remarks.
Thank you everybody. We really appreciate you participating in the call. This morning.
And we very much look forward to returning reporting our first quarter results in early may Thank you.
The conference has now concluded. Thank you for attending today's presentation you may now disconnect.