Q3 2020 Goodrich Petroleum Corp Earnings Call
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Good morning, and welcome Goodrich Petroleum third quarter earnings call.
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After todays presentation, there will be an opportunity to ask questions.
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Like to turn the conference over to Mr. Gill, Good words, chairman and CEO.
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It doesn't feel good.
Yes go ahead, Sir your liability I'm sorry, good morning, good morning, everyone.
Welcome to the third quarter, good destroying earnings conference call.
Joining me on the call. This morning is our president Rob term.
The third quarter was fairly quiet quarter for us as we push all of our Frac operations and completions to late in the quarter, which resulted in a sequential decline in <unk>.
Auction.
In net production volumes. However, the late quarter completions resulted in a significant bump and net production as we enter the fourth quarter with an entry rate in excess of 150 million cubic feet of gas equivalents per day, and we are now receiving a materially better natural gas price than we are.
Averaged in the third quarter.
Additionally, as the 2021 natural gas futures strip price has improved dramatically to a current calendar year average in excess of $3 per Mcf.
Our outlook earnings and cash flow potential for next year has also increased significantly.
This morning, we are announcing preliminary 2021 capital plans and guidance approved by our board and we will share those plans with you shortly.
As the.
As the as of the ended the quarter, we had total net debt of $109 million with approximately $96 million outstanding under our senior credit facility.
In addition, our bank group recently reaffirmed the borrowing base under our senior credit facility of $120 million.
As.
And we have again prepared for you our slide presentation, and we invite you to follow along with our slide deck. During our prepared remarks, you can access the slide presentation on the Goodrich Petroleum website entitled Threeq, You 2020 earnings presentation.
I will now turn to the slide presentation for those of you would like to follow along and our standard disclaimer on forward looking statements and risk factors are highlighted for you on slide two.
In addition, we believe it is important to share with you specific data regarding our environmental social and governance statistics, which we do on slide three.
Please review this information at your leisure and we will update this slide as conditions and best practices all over time.
On slide four we provide an overview of the company in a number of key highlights.
Rob will color cover all of the third quarter results with you in just a minute.
So I will just point you to a few important highlights.
First our recent bolt on lease acquisition efforts have added approximately 2000 net acres in the core of the Haynesville shale, which brings our current total net position to approximately 24000 net acres.
The very high quality of the rock in the core of the Hazel has been generating strong rates of return at a variety of natural gas prices.
And are expected to be very robust in the current $3 plus natural gas price environment.
Finally, our already strong balance sheet is expected to improve even further in 2021 in the current gas price environment, and we expect to exit 2021 per our guidance with a net debt to EBITDA multiple of less than one.
While we also expect to enhance balance sheet liquidity as we generate significant free cash flow to pay down the revolver debt and expand the borrowing base under our senior credit facility through growth in PDP reserves production and cash flow.
Moving to slide five we show the year end 2019 FCC proved reserves.
517 Bcf equivalent.
Which as a present value of just under $300 million using FCC mandated pricing and discounted at 10%.
The charts on the right illustrate the split of the year end reserves back commodity area and prusik producing versus undeveloped.
On slide six we have updated our average daily production chart to include the preliminary guidance for 2021, where we are projecting average daily production next year with a midpoint of approximately 170 million cubic feet of gas and equivalents per day.
As I mentioned, we released preliminary guidance for next year, and we highlight our 2021 plans on slide seven.
With the improving gas price fundamentals and a solid hedge position for next year. We believe the right plan for our shareholders is free cash flow generation, which our guidance for next year indicates should be in a range of $15 million to $30 million.
Based on Nymex natural gas prices in a range of $2.50 to $3 per Mcf.
Plus growth in production in a range of 20% to 25% versus 2020 as.
As well as the associated growth in EBITDA and PDP reserves.
Using nymex range of $2.50 to $3 per Mcf, we are projecting 2021, EBITDA in a range of $100 million to $115 million, which at the midpoint.
Has our stock currently trading at only 1.2 times and 1.25 times projected EBITDA per share.
Currently enterprise current enterprise values projecting.
To projected EBITDA EBITDA excuse me at the midpoint of the guidance has us trading currently at approximately 2.25 times.
Our board has approved a preliminary capital expenditure budget of $75 million to $85 million.
Which will allow us to drill 17, gross and nine net wells in 2021, all of which will be targeting the haynesville shale. This.
This plan will again lard be largely operated activity in heavily focused on the core acreage in the Bethany long feet Street field, Encanto and Desoto parish is of northwest Louisiana.
We expect this Capex plan will result in annual production growth of 20% to 25% as I said versus 2020 at the midpoint.
As I mentioned.
And approximately 170 million cubic feet of gas equivalent per day.
On slide eight we also provide the expected cadence of completions on a quarterly basis as well as the anticipated range of certain key per unit cash expenses.
Moving on to slide eight we provide our hedge hedging summary.
Which shows the volumes type and prices of our current natural gas and crude oil hedge positions.
During the third quarter and as future natural gas prices improve significantly we added to our hedge position for 2021 and into 2022.
In a trade we like quite a bit we added hedges covering 30 million cubic feet of gas per day for the period, beginning April 2021, and running through March of 2022, and a costless collars with a floor of $2.50 and a ceiling of three days.
Sales and 50 cents per Mcf.
This brings our total hedge position for the period April through March of 22 to approximately $100 million.
Cubic feet per day.
And which is just under 60% of the midpoint of our production guidance for 2021.
I will now turn the call over to Rob Turner, our president Thanks Gil.
Revenues for the quarter adjusted for cash settled derivatives totaled 23.1 million comprised of 21, and a half million of oil and natural gas revenues and $1.6 million of cash settled derivatives.
Average realized price, including cash settled derivatives was $2 per mcf equivalent for the quarter versus 221 in the previous quarter.
Average realized price without our hedges was $1.86 per mcf fee in the quarter.
Our per unit cash operating expense, which is defined as operating expenses, excluding DDNA impairment and noncash DNA declined by 8% to 93 cents per Mcf fee generating a cash operating margin of 54% or one dollar in seven per mcf fee for the quarter.
Okay.
When you add in our cash interest expense, our total unit cash cost was one dollar in two cents down seven cents or 6.5% from the previous quarter.
We are expecting this total cash unit cost, including interest to continue to decline in 2021 with the midpoint of guidance down an additional 10% less than a dollar per mcf fee.
Combined with much higher gas prices, we anticipate robust cash margin expansion, which will drive our free cash flow for the year.
Capital expenditures for the quarter totaled $16.9 million of which nearly all was spent on drilling completion and facility costs associated with Haynesville wells.
We completed eight gross three net wells at the end of the quarter, which caused our production to rise to over 150 million cubic feet equivalent per day as we entered the.
Interest expense totaled $1.7 million in the quarter, which included cash interest of a million incurred on the company's revolver and noncash interest of 700000 included primarily on the company's convertible notes.
We will report third quarter DNA impairment adjusted EBITDA discretionary cash flow and net income with the filing of our 10-Q, which we expect to file on or before November 13th.
Just this delay was caused by the need to amend our second quarter 10-Q, due to an increase in noncash impairment of $7.3 million for that second quarter.
Which was a result of Capex on two pud locations inadvertently dropping out of our mid year Reserve report and thus the full cost pool due to a change in spud timing.
All of our activities remain in the core of the Haynesville beginning on slide nine and 10.
As Gill says we currently have approximately 24000 net acres in the play and continue to seek and review bolt on opportunities to expand our footprint footprint through acquisitions and drill to earn farm outs, whereby we commit to drilling wells weeks, which creates more value to sellers than the market is paying currently for undeveloped.
Acreage and allows the company to capture the opportunity and lengthen our inventory without levering our balance sheet.
Our acreage in North Louisiana is currently approximately 75% undeveloped and 77% operated.
We have expanded our inventories are over 18 years at current pace.
We also maintain approximately 3000 net acres held by production in the Angeleno River trend of the Shelby trough.
The Haynesville and Bossier formations are both perspective on our Shelby trough Angelenos Rivertrace acreage.
The activity map on slide 11 shows how consistent the play is in our area when drilling and completing wells in similar fashion.
Our acreage is fully de risked and ring fenced with very good wells.
500 foot or where are we now show a composite of 225 industry wells with average profit loading the approximately 3000 pounds per foot, which for the most part fits our two and a half bcf per thousand foot type curve initially.
But when the old wells fall off as the as the under stimulated wells fall below the curve.
Like the short laterals are more recent operated 7500 foot wells are outperforming materially to a composite estimate of approximately 2.8 Bcf per thousand feet again due to a higher profit concentration and tighter cluster in fracking oval spacing.
Slide 15, which now shows a composite result from 225 10000 foot laterals with an average of 3000 pounds per foot of profit are for the most part tracking or two and a half bcf for a thousand but type curve until the older wells again with lower profit concentration kick in a little over two years out.
Our ninewells, which average approximately 9600 feet of lateral in 3500 pounds per foot of profit are for the most part tracking or two and a half DCF per thousand foot curve, but we have not recently frack 10000 foot wells with tighter interval spacing.
As we believed these results will improve once implemented.
As I've stated before we believe our well performance speak speaks for itself and is driven by a number of factors.
Quality of our acreage an optimum completion design, where profit concentration fluid levels cluster, an interval spacing and pump rates provide a material difference in results.
And flew back technique that Minimises daily drawdown flattens decline curves provides high recoveries of gas in place and most importantly maximizes returns.
Our economics is shown on slide 16 to 18, which reflect our well results in the recent 15% to 20% reduction in service costs that we have seen in the second half of the year are as good as we have seen them in the base and when baking in our hedge book and strip pricing.
The outperformance of our curves on the 4600 7500 foot laterals and service costs deflation across all wells has created a unique situation.
As you can see at $2.50 gas price, we can generate approximately 100% or greater I R. R. As a long laterals due to the outperformance of our wells relative to our curves and the reduction in service calls.
As a reminder of the Haynesville economics are driven by high volumes attractive netback relative to hit rehab as compared to other gas basins low lifting cost and severance tax abatement until the earlier of two years will pay out of the well.
Moving to slide 19, we show cash cost per unit for us and our natural gas peers.
What is really important is to show how the superior well economics flow through the cash flow statement on a full cycle basis.
And as you can see we compare very favorably with our natural gas peers.
We will be updating our peers for the third quarter, but as you can see we have the second lowest cash cost structure at one dollar and two per Mcf equivalent with another 10% reduction anticipated in 2021 at the midpoint of our guidance.
Even more important in our mind is cash margin is shown on slide 20, which also bakes in net realized prices.
Or 54% margin or $1 seven per Mcf equivalent ranks first when compared to our peers second quarter numbers.
In summary, our team is executing well our balance sheet is in very good shape with low that metrics or cash margin at 54% is a pure leading return and competes with any base in either oil or gas and we have a nice hedge position that is minimizing or commodity price risk yet leaves.
Plenty of room to enjoy the better prices, we're seeing in 2021 and the dog.
With that I will turn it back to the operator for Q&A.
No I'll begin to question and answer session, that's what Gwen.
Star them, one on your Touchtone phone.
Using a speaker phone please pick up your handset before pressing the keys.
Draw. Your question. Please press Star then too.
This time, a pause momentarily to assemble the rash.
First question comes from Neil Digman Druids Securities. Please go ahead.
Just a few questions.
Like a little bit just gone Huns differential is going.
It sure does.
Because that's a pretty good contract just any color in the play would be helpful. And then just my second is not a surprise me look the type colors those.
10000, Atlanta, certainly look for being among the best did you talk about what you look at that slide dwell how many potential types of these locations you all think about before you know.
Prior to guarantee said another bolt done thank you.
Hey, Neil this is Rob and thanks for those questions, Yes, I'll start with the average lateral linked in our inventory is approximately 7000 feet. If you. Therefore look at the economics associated with the 7500 foot laterals I think that's probably the best way to.
To come up with an average.
But it does vary by area and based on our unit configuration as you know we grid the acreage in an attempt to try to capture all of the resource potential and lean towards longer laterals is better than in the past, we've swapped some acreage and potentially that could happen.
Instead of drilling short laterals, however, our results on short laterals.
Have really been exceptional.
And I think I heard you in describing basis.
We've guided 215 to 25 cents off of Henry hub for.
For 2021, frankly, it fluctuates a lot we've seen it tighter than than 15 cents.
Before and we've seen it blown out to 35 40 cents.
But it's really supply demand and with LNG demand pool growing on the Gulf coast in our proximity in the Haynesville to that demand center, we feel like in our advisers feel like the 20th.
Mid point of that guidance as good as any to use if you look at Ford basis, right now it's really off.
It really varies by shoulder months and then.
And then obviously tightens up in the higher demand forecasted months, we hope the worst is behind US certainly October realized prices basis was a little bit higher, but we've already seen a tightening of that for.
For November and forward looking.
Our hedges, we love is Gil said, we loved that 250 by 350 hedges.
We hope or writing checks because prices clothes north of 350, but you can see at 250 and current service costs, we generate significant rates of return and it's and it's blowing through our cash flow statement. So we loved those hedges and potentially as we get closer to 2022, you could see us.
Make an additional hedges.
The strip for 2022 has moved up a bit I think I saw 277 before before walking in here for the call. We think that continues to move forward, because we really don't see <unk>.
Oil prices moving north of a range bound scenario or gas companies really stepping on the accelerator to an extent that would that would increase supply dramatically.
Okay cool.
Thanks Neil.
Your next question from Duncan Macintosh Johnson writes. Please go ahead.
Winning gone Rob actually off that down for you.
Hi, all Doom.
Just wanted to go ahead.
I just Wanna say congrats of completing those bolts on acquisition I know Rob placed on a bit in his remarks, but are there any more opportunities.
Similar size or Jonathan Goodbye.
Larger deal.
He had done this guild good morning, we.
We are looking at a few things currently.
Unfortunately, I think most people know the vast majority of the Haynesville is held by production by other operators. So generally the types of things that we're looking at or a reasonably small so.
But what we've seen and we've done over the last two years now is even 500000 acre type transactions, whereas Rob describe we're we're providing the capital which gets down Ah carried interest typically.
In the well it gets them some cash flow from that that was that's better than what they could do just trying to sell that acreage out right in the market.
And is Rob also said it works well for us because we're not we're not stressing our balance sheet or levering our balance sheet too to make the acquisition. So I guess, we can say, yes, we're continuing to look yes. We see continued opportunities we expect to continue to to be able to add some modest sized bolt ons.
And we're fairly aggressive on that front, but obviously can't say anything specifically, it's going to happen until it actually happens.
Alright, Thank you for that calling and my follow up is.
What have you all seen recently on Kato do you expect blue as well to be on par with what you believe in drilling Bethany long Street.
Yeah. So so yeah.
Central part of Caddo parish, which we call Greenwood Waske them, we've got some acreage up there.
We like it quite a quite a bit we have said historically and will continue to say today that is probably.
I don't know, 85% to 90% is good so there is a little bit more clay in the rock up there, but not a tremendous amount. We are very encouraged by what we've seen over the last year or so and offset activity.
Specifically around.
Ridge Comstock in particular is drilled a number of wells Trinity operating is grilling some wells, even further north than us.
Some recently with very good results. So we're very comfortable with the acreage we think it's going to be quite good.
If you didn't want to put it in a.
2528 Bcf per thousand ranked that would be fine, but we certainly think it's 225 to 2.5 Bcf per thousand in terms of results, which is quite good in in these kind of gas prices, it's excellent rates of return.
Alright, Thank you very much.
Thanks to Honeystone.
Thank you. The next question comes from Jeff Grandma's normal. Please go ahead.
When you guys.
Jeff Jeff.
Curious on the on the 21 guide here what are you guys thinking in terms of the sustainability well con seems like we're kind of I guess, most you or maybe add drop service brightening level. You think that you tend to 21 have you made any any inflation or you're really not to do that on the horizon, just given industry activity levels.
Sure, Jeff we think it's prudent to Bacon. This is Rob we think it's prudent to bake in 15% service costs escalation, which we've done into the Capex estimates, we're not seeing any evidence of it but but if we're in a three dollar strip environment, which is certainly what it looks.
<unk> currently we just think overtime service costs are bound to creep up a bit.
But a lot of it is going to be dependent on the Permian and oil prices.
It.
If we're starting to see oil move north of 60 or 50 to $60. We could see increased activity in some of that equipment sucked back into the Permian.
And under that scenario, you could see some marginal increase in service costs.
Which is why we've kind of baked that into our guidance.
Okay. Thanks for that then.
Kind of related not on the balance sheet and was curious to get you guys opinion on first thing I was wondering you know when the strengthening of gas prices.
Pursuing a divestiture of the remaining Angelina River trend acreage makes sense for you guys and I'm looking at.
Second liens out and obviously in a relatively higher cost of capital and maiden on your free castle the guidance.
Take that out with 21 free cash flow alone wondering.
Is that a potential for your guidance as we move into next year related to the second lien.
Any thoughts on but sometimes would be great.
Sure Jeff This is Gil.
First of all in the Angelina River there is a good bit of activity down there now and some recent activity actually just south of our.
Akridge position. So we're we're very pleased to see that activity I think we're very comfortable with just being patient and seeing how that plays out what we know as the rock is very good quality down there and as we've said many many times it's.
The issue there is the depth is a good bit deeper and therefore, the wells are more expensive.
But as we start to get into a better gas price environment and.
And we see activity there that we believe will.
Further confirm and prove up the play then certainly it's something that we could consider divesting or ultimately.
Develop ourselves, but that's that's further down the road and certainly not of 2021 event unless someone comes in an office or something that would make sense to to divest it.
Secondly, after the second lien notes absolutely.
As I said in my comments.
Under the current gas price environment, we expect to both pay down the absolute amount under the revolver in 2021 through free cash flow generation.
And we would expect that the borrowing base X.
Expands through growth and PDP reserves and the enhanced cash flow that we expect from higher production and better pricing.
And we expect that wedge to grow sufficiently such that sometime during 2021 will have great optionality around taking out the secondly notes through through that expanded borrowing base.
Alright, great to hear and looking forward to it thank god.
Thanks, Jeff.
The next question is from all parts of Corker Palmer. Please go ahead.
Good morning.
Good morning, no good.
I just got a couple of questions.
2021 guidance I noticed.
What might be.
The unit cost guidance for transportation in process thing.
Emptying down just a bit a little bit lower Prince here range at the bottom and.
<unk>.
I'm just wondering if there isn't any particular driver behind that.
Sure No and this is Rob again, a lot of the rate depends on where we're drilling.
And whether the landowner pays his share of post production costs.
The when you bake in specific locations for our 2021 program. It's a combination of both of those things lower absolute transportation costs and a little less.
Have a participation on our part of having to carry landowners on those postproduction call. So.
It is a bit of a combination of those two we've also.
Negotiated a better rate structure with one of our carriers, which is dependent on on.
On volume throughput.
And that's going to again add to that decrease in the rates. So bake all of that and we're very.
Comfortable and confident in driving those rates down for those reasons.
Oh, great and actually with that.
That better rate with a carrier based on volume longterm.
Long term.
Seems to be agreement or is that just for that.
Certain amount of time.
Yeah. It's.
Every time, we do one of these amendments it's typically call at 10 years.
And it's a graduated scale matrix based on volumes and so there's incentive.
For the for the pipeline company to get higher volumes and there is incentive for us to locate our locations. We have with our acreage predominantly held by production, we have great flexibility own picking locations, which creates some nice leverage for us.
Which is why we have been able to renegotiate some of these transactions these transportation costs.
Oh great.
And.
You know it with good good.
Are you guys talk about big again, some service cost inflation in your.
In your model.
<unk>.
As opposed to the the idea that.
There'll be low forever.
I'm just wondering.
Do you I'm I'm, assuming that you don't have.
Any reflection on the horizon occur materials stand or or chemicals right.
Yeah can you repeat that I was having a hard time hearing that last bit.
Oh I just correct.
It is.
The potential for concentration I'm, assuming that would not apply to materials like flannery chemicals.
Yeah.
No we don't see any current trend towards higher cost, we just blanketed across the board put a 15% buffer in there just to make sure that we're not under capturing the expected capex call. So too early to kind of break it out by you know.
Hotline item by line item, but we feel like that as a whole gets is covered.
Biggest cost component of any drilling program is your completion.
Program on your frocks.
And we've got excess capacity in the base in which is which is creating record low bids and so the question is just how.
How active our operators and the Haynesville and do any of those spreads get pulled back into the Permian because oil prices.
We're just not seeing any of those trends currently so we just took a blanketed 15% across the board.
Great to me.
Well. Thank you. Thank you know.
Okay, and if you have a question please press star one.
Next question comes from David Snow Energy Equities. Please go ahead.
Good morning, I was just.
Oh.
The additional.
Right.
Serves interesting.
The DNA.
Strange.
Yeah, David this Rob and great to hear from you it's been awhile.
Yeah, we couldn't quantify it because it was kind of a last minute item that came up clearly if you take off more cost Outta. Your at your full costs bucket, then you have less to amortize.
Through production, so all things being equal DD&A right will will trend lower just on that one adjustment, but we just can't quantify that yes, we will by the time, we fall or.
R. R 10-Q before number for November 13th So yeah, we just ask for your patience and it's coming and obviously seven $3 million does not have a big material number it was just enough to.
To keep us from being able to report those numbers with with our press release.
Okay. Thank you very much.
Thank you David.
That concludes our question and answer session.
Now like to turn the conference back over to Mister chemical drugs from closing remarks.
Thank you everyone. Thanks for participating and we look forward to sharing with you our year end financials early in 2021. Thank you.
Conference now concluded. Thank you for attending today's presentation you may now disconnect.