Q2 2020 Goodrich Petroleum Corp Earnings Call
Pardon me. Thank you for your patience the call will begin momentarily.
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Good day and welcome to the Goodrich Petroleum second quarter 2020 earnings call.
All participants will be in listen only mode should you need assistance. Please signal conference specialist pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. Please note. This event is being recorded.
Like to turn the conference over to go Goodrich Chairman and CEO. Please go ahead.
Thank you Jason Good morning, everyone. Thank you for joining us for our second quarter 2020 earnings call. This morning.
With our core Haynesville shale position and natural gas focused development strategy, we are very well positioned.
Improving market fundamentals, including reduced drilling and completion cost and increasing future prices for natural gas in fact, if the current development costs and a calendar year strip for natural gas now at approximately $2.75 are forward looking rates of return.
Payback periods as margins are as attractive as they have ever been.
Well 2021 natural gas prices look quite good correct <unk> month remain depressed at around $2 per Mcf after bases differential and therefore, we have slightly delayed the completion of threed drilled but uncompleted wells do a little later in the third quarter than previously.
Plan, which will impact Threeq, you production, but should allow us to produce more volumes into higher prices in the fourth quarter of this year.
With roughly flat production versus the first quarter of approximately 138 million cubic feet of natural gas and equivalents per day reporting quarterly EBITDA or $15.4 million.
In addition, we reduced our right of development activities during the quarter with capital expenditures of approximately $10 million.
We have again prepared a slide presentation, we invite you to follow along with the slide deck. During our prepared remarks, you can access the slide presentation.
On the Goodrich petroleum website entitled to Q2 thousand 20 earnings presentation.
Now turning to slide presentation for those of you 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 again provide specific data regarding our environmental social and government statistics, we plan to continue to share. This information with you as well as update and we're fine as conditions and best practices evolve overtime.
On slide four we've again included an overview of the company, which highlights various aspects of our core haynesville shale position in northwest, Louisiana as well as recent performance and results of note since the beginning of the year. We've added approximately 2000 net acres in the core of the Haynesville through several small.
Bolt on transactions.
On a drill to earn basis, which increases our core position to approximately 24000 net acres and meaningfully increases our core inventory.
As I mentioned the company's total net production was up slightly versus first quarter.
This year to an average of 138 million cubic feet of gas and equivalents per day, as we try to maintain roughly flat production quarter over quarter.
We expect quarterly production may fluctuate based on the timing and completion cadence as we add wells, which typically have high working interest and very robust early time production levels.
That's where gas prices were very weak in the second quarter, where we realized where I realized prices before hedges was just $1.54 cents per mcf fee.
The low natural gas prices were partially offset by realized hedging gains and as I mentioned a minute ago resulted in quarterly EBITDA of $15.4 million.
Moving to slide five we show our year end 2019, FCC proved reserves of 517 Bcf B.
Which has a present value of just under $300 million using the FTC mandated pricing and discounted at 10%.
The pie charts on the right illustrate the split of the year end reserves by commodity.
Area and producing versus undeveloped reserves.
On slide six will again updated our cap table as of the ended the second quarter.
The end of the second quarter, we had total net debt excuse me, it's $107.7 billion.
Approximately $95 million outstanding under our senior credit facility.
At the end of the quarter net debt to EBITDA on a trailing 12 month basis remains less than 1.5 times.
On slide seven we show our annual gross and net production volumes over the past several years, including the midpoint of our guidance for 2020 of approximately 140 million cubic feet per day.
As I said, our current strategy is to remain in maintenance mode with roughly flat production levels during 2020 with a significantly reduced capex program.
Moving to slide eight we have updated our hedging summary that shows the volumes tight and prices of our current natural gas and crude oil hedges.
With the recent strength in the future strip prices for natural gas, we recently layered in additional natural gas hedges for a portion of 2021 and the first quarter of 2022, which raises our total hedge position to 70 million cubic feet per day for all the too.
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And the first quarter of 2022 with a blended average price of approximately $2.55 per Mcf.
We view this as prudent risk mitigation, while rate to retaining meaningful upside due in improving natural gas market and represents approximately 50% of the current production right hedged through March of 2022.
Finally, we provide details of our current 2020 guidance on slide nine where we expect to have drilled 12 gross and five net haynesville wells by the end of the year.
While the lateral length may vary from well to well we estimate the blended average lateral length for 2021 will be approximately 8500 feet.
While we have not updated our full year guidance, we have elected to participate in for non op.
Non operated wells with a blended average working interest of approximately 17%, which are currently expected to be turned in line or turned to sales in the first quarter of next year.
We've adjusted our full year budget to accommodate for the participation in these wells. However, our board reviews and approves our capex budget quarterly with the ability to speed up or reduce the pace of development.
And with that I'll turn the call over to Rob turned them our president.
Skill.
Revenues for the quarter adjusted for cash settled derivatives totaled 27.8 million comprised of 20.5 million of oil and natural gas revenues and 7.3 million if cash settled derivatives average realized price, including cash settled derivatives was $2.21 per mcf equivalent.
For the quarter versus 232 in the previous quarter.
Our per unit cash operating expense, which is defined as operating expenses, excluding DNA and noncash DNA was one dollar and one cents per mcf fee generating a cash margin of 56% for the core.
Very importantly, if you bake in our cash interest expense of 1 million. Our total cash expense was a dollar a nine cents per mcf fee, which compares very favorably to our peers.
In fact, we will incorporate twoq financials and work this slide into our future presentations.
Capital expenditures for the quarter totaled 10.2 million of which nearly all was spent on drilling and completion costs associated with Haynesville wells.
We conducted drilling operations on six gross 2.2 net wells you're an added one grows 0.8 net wells in the quarter.
We exited the quarter with 13 gross 4.7 net wells in drilling or completion phase with six gross 2.8 net wells completing at the end of the third quarter, which as Gill said will allow for a surge in production as we head into the fourth quarter, where we see much higher natural gas prices.
Interest expense totaled 1.7 million in the quarter, which included cash interest up a million incurred on the company, who revolver and noncash interest of $700000 incurred on the Companys convertible notes and amortization of issuance cost on the revolver.
As everyone likely knows by now all of our current activities are centered in the core of the Haynesville beginning on slides 10 and 11.
With the announcement of incremental acreage in today's press release. We are currently have approximately 24000 net acres in the core of the play which meaningful adds to our inventory.
Our acreage in North, Louisiana is over 75% undeveloped and 75% operated.
We estimate over one Tcf a reserve exposure at two and a half bcf per thousand feet of lateral and 880 feet spacing in north Louisiana alone versus our book reserves of about a half of a tcf.
We also maintain approximately 3000 net acres held by production in the Angelina River trend of the Shelby trough.
The Haynesville and Bossier formations are both perspective on our Shelby trough Angeleno River trend acreage.
The evolution of the completion design in the Haynesville as shown on slide 12 is transform the play into one of two premier gas basins in the country.
Our results as shown on slide 13 are very consistent all of our acreage has now been de risked and where you're in development mode drilling predictable wells and 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 wells versus 309, 4600 foot lateral industry wells drilled in the core.
Industry pumped an average of 3100 pounds per foot, but as you can see the older wells are underperforming the newer wells.
As average proppant is lower on these older wells.
Our six wells shown in Green were stimulated with approximately 4100 pounds of profit per foot.
And tighter costing and interval cluster in interval spacing or exceeding the industry average composite results and our two and a half bcf per thousand foot type curve to an estimate of approximately 2.7 bcf per thousand feet.
Linear progression of completions to E. U R shows 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 from this optimization.
Slide 15 reflects our 7500 foot curve, where we now show a composite of 225 industry wells with average proppant concentration of approximately 3000 pounds per foot.
Which for the most parts fits our two and a half bcf per thousand foot type curve.
However, the older wells fall off as they are under stimulated like that 4600 foot laterals and fall below the curve.
Our more recent operate at 7500 foot wells are outperforming materially to a composite estimate of approximately 2.8 bcf per thousand feet due to higher proppant concentration and tighter cluster and Frac Annabelle spacing.
Slide 16, which now shows a composite result from 225 10000 foot laterals with an average of 3000 pounds per foot or profit are for the most part tracking our two and a half bcf per thousand foot type curve.
Our nine wells, which averaged approximately 9600 feet of lateral and 3500 pounds per foot of proppant are for the most part tracking against our two and a half bcf per thousand foot occur.
However, we have not recently Frac 10000 foot wells with tighter interval spacing. So we believe these results will improve Watson implemented.
As we've stated before we believe our well performance speaks for itself. It is driven by a number of factors.
One quality of our acreage to an optimum completion design more proppant concentration cluster and interval spacing and pump rates provide a material difference and results.
And finally flowback techniques that minimizes daily drawdown flattens. The decline curves provides high recoveries of gas in place and most importantly maximizes returns.
Our economics as shown on slide 17 through 19, which reflect the recent 15% to 20% reduction in service costs or as good as we've seen them in the basin, what baking in our hedge book and strip pricing.
The outperformance of our curves on the 4600 7500 foot laterals and service cost deflation across all wells has created a unique situation.
As you can see at $2 and $50 gas price, we can generate approximately 100% or greater IR ours on long laterals due to the outperformance of curves and recent reduction in costs.
As a reminder, the Haynesville economics are driven by high volumes attractive netbacks relative to Henry hub as compared to the other basins.
Oh lifting costs and severance tax abatement until the earlier of two years or pay out of the world.
In summary, our team is executing well our balance sheet is in good shape with low debt metrics our margin at 56% competes with any basin and we have a nice hedge position that is minimizing our commodity price risk yet leaves plenty of room to enjoy better pricing as we that we see in 2021 and beyond.
With that I'll turn it back to Jason for Q anyway.
Thank you well now begin the question and answer session to ask a question. You May proceed Star then one on you touched on phone.
Yeah use any speakerphone, please pick up your handset for pressing the keys to withdraw your question. Please press Star then to.
The first question comes from Duncan Macintosh from Johnson Rice. Please go ahead.
Hi, Good morning robbing Joe This is also Mike.
I have done.
Oh I was wondering if you all can provide some additional color or on the acquisition.
Specifically, how many on new locations.
Not to get rich.
I'd like to pick up that put a rig to start working there and dlts any additional opportunities under assembly.
Phil time structure.
Yeah. Dan. This is this is rob.
It is.
It's really comprised of two sections in the Bethany long Street area and it it is.
It is set up for really shorter laterals, but 16 locations.
Within those two sections at 880 feet apart so.
Quite a bit are running room.
Obviously 912 acres divided by 1200, 80, which would be that sections would give your average working interest in those two wells I'm a little bit the operator on those sections.
As far as other deal flows as you can see that's just a portion of what we've added for the year since we've gone from 22000 to 24000 so.
We continue to into kind of chip away at some bolt on opportunities.
And there are packages in the market currently that.
That we're in evaluation phase on so I think the deal flow is certainly higher than it has been a and we'll see if we can continue do you know to add to our position, but one thing we're not going to do is lever up for.
Develop locations.
Balance sheet is is the key here and obviously, we have over 16 years of inventory as it is so I think.
We just need to be conservative if we can pick things up where we have no upfront costs like like what we've done here and in 2020 that really fits in well for us because we can we can work that into our capex budget and cap or capture the opportunity without you know upfront cash.
I appreciate the color and for my follow up.
I was wondering you always stated threeq he will be the high point for turning on activity. This year and you all active on the drilling fun to keep in preparation for that.
Did you provide some color around your production trajectory for second half how do you and maybe early thoughts on the 2021 program, especially the parents tripled even.
Got it.
Yes, I've done this deal.
Yeah, you know I guess, the short answer would be would not really ready to give any change to the overall plan at this point in time.
We certainly do like where natural gas is setting up will be reviewing a second half activity as well as a preliminary look at 2021 with our board here coming up in a few weeks.
But I think for right now.
As Rob just said balance sheet is is the number one issue and we're continuing to take a more cautious mode and just stay and maintenance.
We did allude to a little bit of.
Perhaps reduced volumes coming up in the third quarter bass delay in activity, but we're expecting a very robust fourth quarter and production volumes and we'll see where that leaves us going into next year.
Thank you very much.
Thanks.
[noise] next question comes from Jeff Grampp from Northland Capital markets. Please go ahead.
[noise] My guess I point, Jeff I'd Yeah.
Maybe if I can.
So at the at the 21 commentary, maybe a little different way it certainly not right and you guys that down to from on anything, but maybe directionally. How you guys are viewing maintenance capex levels trending into next year versus you know this 40 to 50 level that we're at this year I guess that we're kind of thinking internally.
Cost efficiency, you have an inventory of wells and process that I imagine provides a capital efficiency tailwind for yet so.
Does that suggest that maintenance capex could trend down next year or are there maybe some other factors at play where maybe that's a little too ambitious expectation.
Yeah, Jeff this Rob.
It yeah, you're right on as to your analysis, we think we could hold volumes flat with less capital.
Than what we spent this year. The question is whether that's all we do and a 275 gas environment I think it's unlikely that all we're going to do is is just target holding volumes flat, we can even spend a little bit more money perhaps.
And then holding volumes flat and grow.
To some degree you won't see is likely grow dramatically, but certainly getting to a 10% growth.
Generating substantial free cash flow in spending less money is really an option to the board will consider as we as we set our budget in December.
Got it really really helpful and can you guys just touch on on your comfort level with your current liquidity position I understand leverage is very healthy, especially relative to a lot of peers out there, but and just your overall comfort level with liquidity.
If you have any expectations at least directionally on the borrowing base redetermination in the fall.
Sure. Yes. This is deal. So obviously the liquidity is what it is we've given the borrowing base number in the outstanding under the.
Under the revolver. So we got a 25 million of liquidity currently.
We will be going through a review next month with our with our Bank group.
And we will not free judge Velma, what they decide the borrowing base should be however.
The strip prices, we've talked about here on this call has improved dramatically. So as you compare about looking back to may when we put the last the revolver borrowing base in place.
The strip prices, obviously considerably higher today, so we think that bodes well for the new borrowing base.
And then that the hedges that we just recently layered on must get out all the way through the fourth quarter 2022 also will be a positively impactful when you compare that with what's likely to be the banks price that so would we like to have some more liquidity sure I. Thank everybody probably would are we comfortable yes, we are and.
Sure and we're operating in a mode that we think is very careful with the balance sheet is our number one priority.
All right that's perfect. Thanks, guys.
Yes, Jeff.
Again, if you have a question. Please press Star then one next question comes from Phillips Johnston from capital One. Please go ahead.
Good morning Philips.
Hey, guys. Thank you first question on Capex.
I guess through the first six months, you spoke about $29 million inches.
How about 63% bunch of it.
I know that and that what pumps for the second half a year or pretty close to what came online in the first so.
Can you can you talk about what factors should cause your spend rate just sort of creep a little bit low in the back half of the year. Thanks.
Sure Philips and we basically built a DUC.
Backlog as you've seen.
Currently planning to complete six gross 2.8 net wells for the remainder of the year book, but we basically drilled 13 grows 4.7 net wells that have yet to be completed so.
Even though you tie capex to turn in line, we've incurred a good bit of drilling costs that that we won't have in the back half of the year or heading into 2021. So.
As Gill said you know we watch it quarterly a you'll see us.
Based on where commodity prices are you know either differ or accelerate capital based on what the board wants to do relative to a budget, but but a lot of the cost that that we've incurred today, they've been drilling wells to put in our DUC inventory and so.
Just on paper that means less less total well cost for for wells that are being turned in line in the future.
Okay that makes sense and then I.
I know it's early in 2001, but I just wanted to clarify your comments that.
You could possibly look to grow 10% next year with some free cash flow.
Obviously your exit rate this year is gonna be pretty considerably higher than than sort of full year average, so would that 10% growth b and directionally versus the exit rate.
Yeah, Yeah. Those good question I think it's gonna be the number I quoted was really.
Year over year. However, we should we still should be a growth over the exit rate also which is it just won't be double digit and of course that double digit the 10% for example.
Is predicated on spending a certain amount of money. It we just won't get out ahead of our of our board, but it's awfully appealing when you bake in.
A less capital.
And grow 10% year over year, and still generate substantial free cash flow, which is what our modeling suggests but again December will be the date that we kind of put that the 2021 budget together and and we will jump out ahead of our board us, but you know kind of where we want to go with that.
Yeah, that's that makes sense I mean, it's pretty impressive domination either way. So thanks again, yeah. Thanks, Phil.
Again, if you have a question. Please press Star then one.
There are no more questions in the Q. This concludes our question and answer session I'd like to turn the conference back over to kill Goodrich for any closing remarks.
Thanks, everybody. We appreciate you participating this morning, and we look forward to.
Putting third quarter two in early November thank you.
The conference has now concluded. Thank you for attending today's presentation you may now disconnect.
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