Q2 2021 Goodrich Petroleum Corp Earnings Call

Part of it because that's the operator and is currently at 11 o'clock Eastern time. Please standby the conference will begin and tours of your math, Yeah and thank you. Please continue to hold the line. The conference will begin at 2 or 3 of bass. Thank you.

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Hello, and welcome to the Goodrich Petroleum second quarter, 2 I just want to you want the earnings call.

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After todays presentation, there will be an opportunity of the last questions.

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And now I would like to teleconference over to go Goodrich and chairman and CEO. Mr. Goodrich. Please go ahead.

Thank you very much good morning, everyone and thank you for participating with us on our second quarter earnings call. This morning.

Our operational achievements during the second quarter, which were led by 24% sequential production volume growth coupled with the significant upward moving forward looking natural gas prices and provided a very robust outlook for the second half of 2021 and into 2022, and we hope to share with you our outlook.

For the second half of this year.

Yes, we can this morning and have updated our 2 H 'twenty, 1 guidance to help update and refine your estimates and projections for the company in the coming quarters.

We are also selectively added to our hedge position as gas prices have rallied, which we believe further protects and strengthened future performance, while also leaving ourselves and meaningful upside to natural gas prices and 2022, and 2023 and I'll review the updated hedge position with you and just a miss.

Right.

With our current planned wells and completion cadence, we expect to see continued sequential quarterly production volume growth, which will further drive down unit price cost on a cash basis as well as enhanced margins and cash flows under the current gas price forecast.

We are extremely pleased and encouraged by our most recent haynesville well completions.

Overtime, our bias has been to reduce frac interval spacing and increased fluid volumes per frac stage, while maintaining approximately 4000 pounds of proppant per foot.

Our most recent wells completed with this methodology of further outperforming prior wells and early production performance, including our Latin and 3 and 34, H, 1 and 10000 foot of lateral and the wallets Lake area of Caddo parish, which we first reported to you in conjunction with our first quarter earn.

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The Latin had on IP of 35 million cubic feet of gas per day has now produced at an average rate of 32 million cubic feet of gas per day for the first 90 days and is currently producing in excess of 30 million cubic feet of gas per day.

More recently 240, 600 foot laterals of also and Caddo parish and just north of our Bethany Longstreet area.

Our bear more of the state 11, H, 1 and 2 wells have produced and an average rate in excess of 21 million cubic feet of gas per day for the initial 30 days have averaged 20 million cubic feet of gas per day for the first 50 days and are currently producing at approximately 18 million cubic feet of gas per day.

And.

We've again prepared a slide presentation and we invite you to fall of the slide deck. During our prepared remarks, you can access the slide presentation on the Goodrich petroleum website entitled to Q2 thousand 21 earnings presentation.

Now I'll 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 provide our E. S. G statistics and we invite you to review those at your convenience.

On slide 4 we provide an overview of the company.

We have continued to selectively add to our acreage position and the core of the Haynesville with an additional 1500 net acres added and the second quarter, which brings our current total to 27500 net acres.

We are now approaching almost 2 tcf of natural gas resource potential and the core of the play and northwest, Louisiana, and we remain focused on further expanding our footprint through selective transactions, which increase our development inventory do not negatively impact our balance sheet or materially reduce.

As our free cash flow objectives.

As I said production increased 24% sequentially over the first quarter to average over 155 million cubic feet of gas equivalents per day and the second quarter.

In addition, this morning, we are providing updated and more detailed production guidance for the second half of this year.

We are now projecting further sequential growth and <unk> and <unk> with the mid point of our 3 Q guidance ranging.

The range being approximately 170 million cubic feet of gas equivalents per day, and growing to approximately 192, and a half million cubic feet of gas equivalents per day, and the fourth quarter, resulting and updated full year per projected midpoint of guidance at 162 million.

And the cubic feet of gas equivalents per day is on average for 2021.

We're not just growing for growth's sake. However.

And what we're doing is adding and growing our P. D P value EBITDA and EBITDA.

We are on target to generate free cash flow at the upper end of our previously disclosed range.

With an estimated.

Average of approximately 2.5 bcf per.

For 1000 feet of lateral and the core of the Haynesville continues to offer low development and the lifting cost top tier cash margins and strong returns on invested capital, which are only improving with the rally and natural gas prices.

Higher production and improved net prices led to quarterly EBITDA of $24.4 million and the second quarter.

Which we are also projecting will expand meaningfully and both <unk> and <unk> with our production and cash flow guidance as well as our assumptions for natural gas future prices and the back half of the year.

Improving fundamentals also led to adjusted earnings of just under $10 million or 72 cents per basic share and the second quarter.

In addition, and the higher quarterly EBITDA further reduced our key leverage metrics to just 1.24 times on an annualized basis for the second quarter and we now project. This measure will fall below 1 turn by the end of this year.

Low per unit cash expenses drove a cash margin and the quarter of <unk> 63 per cent and return on invested capital of approximately 45 per cent.

We continue to project meaningful free cash flow in 'twenty, and 'twenty, 1 and with the improved pricing and our hedge position. We are currently and I believe that we can deliver free cash flow and a range of $25 million to $30 million and 2021.

Moving to slide 5 we again show our year end 2000, 20-F T. SEC proved reserves of 543 Bcf equivalent which is the present value using a range between $2.50 and $3 per Mcf of 338 million to 400.

And the 85 million discounted at 10% with more room to run as we go forward.

On slide 6.

Cap table as of the end of the second quarter illustrates our current capital position with approximately $90 million outstanding under our senior credit facility and $31.5 million of second lien Pik notes for a total of $121 million at the end of the core.

Annualized Q2, EBITDA would be $97.6 million and as I mentioned result, and net debt to EBITDA of 1.24 times at the end of the quarter.

On slide 7 we provide a chart of our historical production growth.

Which includes the updated forecast of average 2021 production guidance of 162 million cubic feet of gas equivalents per day on average.

Given the prolific nature of our core position in the Haynesville our situation maybe somewhat unique in today's environment as we expect to both grow at attractive rates, while also delivering significant free cash flow.

As we refine our plans for 2020.2 we will maintain both of these objectives as part of our board deliberations and planning for next year.

Moving to slide 8 you will see our updated commodity hedge position, which consist solely of natural gas swaps and collars and the second half of this year, we have swaps in place and a blended average swap price of $2.88 per Mcf.

Which we estimate should equate to approximately 63% of second half production using.

Using the midpoint of our updated guidance.

And 30 million cubic feet of gas per day, or roughly 16% of second half guidance and collars with a ceiling price of $3.50.

And 2022, you will see we have a downward trending amount of hedge volume again, and the combination of swaps and collars, which we believe provides us the appropriate downside protection as well as meaningful upside to higher prices for both incremental current production volumes and and <unk>.

The speed of growth in 2022.

Finally, we again provide details of our update of 2021guidance on slide 9.

Where are we now expect the drill approximately 22 gross 10.5 net wells this year, which is up from our previous guidance of 17 gross and 9.5 net haynesville wells.

The incremental wells are recent non op proposals and the core of the Haynesville.

And largely occurring and the second half this year with minimal production impact of anticipated in this calendar year.

We estimate the blended average lateral length for 2020, 1 will slightly slightly longer than our previous estimate or now currently approximately 8000 feet.

And we again provide the updated expected cadence of completion activity, along with our projected production and capital expenditures, including the refined guidance, the 3 Q and the <unk>, which I referred to earlier.

We also provide a range of expected cash cost per unit of production, which we expect at the midpoint.

Average of approximately 84 cents per Mcf equivalent for the full year 2021, but it will be significantly lower and the second half of this year with the midpoint of approximately 75.

Per mcf equivalent driven predominantly by better transportation agreements for the volumes, we expect to bring online and the second half and higher anticipated production and with that I'll turn the call over to Rob. Thanks, Gil revenues were $38.1 million and we had a realized loss on the cash settled derivatives.

And of 1.3 million for net revenue adjusted for cash settled derivatives of $36.8 million for the quarter.

Average realized price was $2.69 per Mcf T or $2.60 per mcf equivalent and including cash settled derivatives.

Our per unit cash operating expense, which is defined as operating expenses, excluding DD&A and noncash G&A decreased by 10% to 89 cents per Mcf fee and cash interest expense was 6 cents per mcf or a total of 95 cents per mcf equivalent.

Cash margin, including interest expense was $1.65 per Mcf or <unk> 63 per cent of realized price including settled derivatives.

As you will see and our slide deck and discuss later in my prepared remarks, both per unit cash expense and cash margin ranked first among our gas peers when comparing against their first quarter for the animals.

We expect production to grow commodity prices to be higher and per unit cost to continue to fall and therefore cash margin to continue to expand throughout the remainder of this year driving significant EBITDA growth and free cash flow.

Capital expenditures for the quarter totaled $19.7 million of which nearly all of the spend on drilling completion and facility costs associated with the Haynesville wells.

During the quarter, we conducted drilling and completion operations on line gross 4.2, net wells and added 3 gross 2.8 net wells to production.

For the year, we are slightly increasing our capital expenditure expenditure budget by $5 million at the midpoint to a range of $80 million to $90 million due to an increase in net.

Non operated activity versus the previous budget.

And we're also increasing full year production guidance as Gil has said by an average of 2 million cubic feet equivalent per day or 4 million of day for the second half of the year.

Guidance.

Interest expense totaled $2.1 million and the quarter, which included cash interest of $900000 incurred on the company's revolver and.

And non cash interest and debt amortization of $1.2 million, primarily incurred on the company's convertible notes.

Turning back to our slide deck, all of our activities remain and the core of the Haynesville beginning on slides 10, and all of them.

As mentioned before we added 1500 net acres through of deal to earn transaction during the quarter and currently have 27005 hundred net acres in the core of the play.

We continue to seek and review bolt on opportunities to expand our footprint through acquisitions and drill to earn farm outs and we believe you could see additional expansion of our footprint with this strategy and the near future.

Our acreage is currently approximately 75 per cent undeveloped and 80% of operated.

On slide 12, we show our inventory in North, Louisiana, which now totals in excess of the 1.9 Tcf of reserves.

Reserve exposure.

We've not quantified our inventory of the Angelina River or the Tms since all of our activity is planned for north Louisiana.

The activity map on slide 13 shows how consistent the players and our area and when drilling and completing wells in similar fashion.

Our acreage is fully derisked and ring fenced with extremely good wells.

We are 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 short laterals versus 403 industry wells drilled nearby and the core.

The industry pumped on average of approximately 3500 pounds per foot of profit and as you can see our 13 wells are significantly outperforming the industry wells and our 2 and a half bcf per thousand foot type curve.

Our wells shown in Green were stimulated with approximately 4000 pounds per foot of proppant with tighter cluster and interval spacing.

As we have said before regression analysis shows very good correlations between proppant loading and cluster and interval spacing to EUR.

We expect our more recent wells to continue to pull up the composite curve over time from this optimization.

Slide 15 is the cumulative production curve and shows over time, how we are outperforming our type curve.

Moving to slide 16, which reflects our 7500 foot curve, where we now show a composite of 353 industry wells with average proppant loading of 30.270 pounds per foot, which for the most part fits our 2 and a half bcf per thousand foot type curve initially, but then.

All of us below our curve as the older under stimulated wells fall off.

Like the shorter laterals, our more recent operated 7500 foot wells are materially outperforming our type curve.

Slide 17 again just shows how we are outperforming our type curve.

On slide 18, we track all of 11.10000 foot laterals against the 310 industry wells drilled and completed and our areas and as you will see from the most part track our type curve and the industry, mainly because we've only recently completed wells with the newer completion design.

And as Gil stated earlier on most recent 10000 foot well the Latin well on the border of Caddo and Desoto parish is which was which had a completed interval of 9900 feet has been exceptional and you can see on the slide that the well is significantly outperforming our type curve.

As this well flows through over time, we expect the composite curve to continue to improve and we look forward to completing additional 10000 foot wells with this optimum completion methodology.

Slide 19, again tracks cumulative production relative to our type curve.

And as we've stated before we believe our well performance speaks for itself and is driven by a number of factors quality of our acreage and the core of the play.

And the optimum completion design, where proppant concentration and fluid levels cluster and interval spacing and pump rates provide a material difference and results.

And flowback technique that minimizes daily drawdown flattens. The decline curves provides high recoveries of gas in place and most importantly maximizes returns.

We have seen very little service cost inflation to date and our economics as shown on slides 20 through 22 or as good as we've seen them and 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.

Can generate approximately of 100% of greater Irr's.

And as a reminder of the Haynesville economics are driven by high volumes attractive net backs relative to Henry hub as compared to other gas basins low lifting costs and severance tax abatement until the earlier of 2 years or payout of the well.

Profitability and value creation of driven from the attractive cash margins, which we are currently experiencing.

Moving to the slides 23, and 24 as I said previously our cash cost per unit, including interest expense of 95 cents has us ranked first among our gas peers when compared to their first quarter results and our cash margin of $1.65, or 63% of our realized price including hedges.

Again ranks first among our gas peers again, when comparing against first quarter financials.

We will update for our peers second quarter results once everyone says the reported.

Our return on invested capital as shown on slide 25 is extremely attractive at 45%.

Which has us the number 1 ranked company out of our gas peers and if you will flip to slide 26, you will see we also ranked first on this return metric and the much larger 34 company peer group, which also includes many oil companies utilizing first quarter results.

For the remainder of 2021, when you bake and higher production higher realized prices.

And lower per unit cash cost, we anticipate on cash margin and return on invested capital will move even higher.

In summary, our team is executing very well our balance sheet is and very good shape with low debt metrics and heading lower and.

And we are generating superior returns both in the field and at the corporate level.

Continue to add to our inventory depth with very accretive bolt on acquisitions and inspect more of the same and the back half of the year.

With this favorable backdrop for the remainder of 2021 and 2022, we look forward to continuing to share of results, which we believe will only get better.

With that I will turn it back to the operator for Q&A.

Yes. Thank you well now begin the question and answer session.

Well I asked the question you May Press Star then 1 on your Touchtone phone.

If you're on speaker phone please pickup your handset before pressing the keys to the.

The trying a question. Please press Star then 2 at.

At this time, we will pause momentarily to assemble the roster.

And the first question comes from hostile Cohen with Johnson Rice.

Hello, and good morning. Good morning asked most of my first question is ex <unk>.

The increase of Capex guidance, and then you mentioned some and.

And from some non op.

And being part of that change, but is there also sort of an increase and expected cost inflation baked into there or potentially a result of the completion of schedule moving forward due to some operational efficiencies.

Yeah. Austin This is Rob no. It's really it's really driven by these non op proposals as you'll see we now expect to complete 10.5, net wells, which is up a bit.

Over our previous guidance and and because those wells are getting drilled and the second half of this year, we really won't see much production.

And cash flow from those wells so.

You know it's it's.

It's something that debt, we need to do just to participate these wells are extremely economic and unfortunately, most of the benefit of of the participation is going to be in the early 2022.

Great. Thank you that's very helpful art, and it's sort of like the follow up.

Regards to the acquisition and the Haynesville and Barnett and 5100 acres.

How does that.

And the market look at this time and are there any certain deals and pipeline youre considering I know you all mentioned that theirs.

Expansion in the near future because of any sort of.

Specific information or light you could bring on that at this time.

Yeah, Austin This gill and good morning, as Rob said earlier, we are reviewing a number of opportunities I would characterize it as of.

Relatively modest in size, but a number of different opportunities, particularly.

Particularly along the drill to earn opportunity where you we can come in and bring the rig bring the capital.

And it's a win win for both the current holder of the acreage and we deliver them new producing wells and they get the capture a piece of that with our capital. So we are looking at a number of things and now if there was something we we had ready to disclose we would do it. This morning, but we are working on some things and we'll see.

What happens and no guarantees, but if we have something of many meaningful size, we'll certainly report that when it occurs.

Great and thanks for taking my questions.

Thanks, and it's also.

Thank you Andrew.

Once again, please press Star then 1 and if you would like to ask a question.

Alright.

The question and answer session and now I'd like to turn the call. It Gil Goodrich for any closing comments sure. Thank you everybody I. Appreciate your participation. This morning, we believe we can continue to deliver production growth, we have of solid hedge position and conservative balance sheet and a great team in place that should allow us to deliver solid performance with the.

Current natural gas outlook for the balance of this year and end of 2022 and thank you for participating.

Thank you and the conference has now concluded. Thank you for attending today's presentation. You may now disconnect your lines.