Goodrich Petroleum Corporation
Q2 2021 Earnings Call Transcript

Published: 7 Aug 2021

[Operator:]

Hello and welcome to the Goodrich Petroleum Second Quarter 2021 Earnings Call. All participants will be in a listen-only mode. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Gil Goodrich, Chairman and CEO. Mr. Goodrich, please go ahead.

[Gil Goodrich:]

Thank you very much. Good morning everyone. And thank you for participating with us in 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 move and forward-looking natural gas prices have provided a very robust outlook for the second half of 2021 and into 2022. We hope to share with you our outlook for the second half of this year as best we can this morning and have updated our 2H 2021 guidance to help update and refine your estimates and projections for the company in the coming quarters. We’ve also selectively added to our hedge position as gas prices have rallied, which we believe further protects and strengthens future performance, while also leaving ourselves meaningful upside to natural gas prices in 2022 and 2023, and I will review the updated hedge position with you in just a minute. 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 costs on a cash basis, as well as enhance margins and cash flows under the current gas price forecast. Additionally, we are extremely pleased and encouraged by our most recent Haynesville well completions. Over time, our bias has been to reduce frac interval spacing and increased fluid volumes per frac stage while maintaining approximately 4,000 pounds of proppant per foot. Our most recent wells completed with this methodology or further out performing prior wells in early production performance, including our Latin 3 and 34H1, a 10,000-foot lateral and the Wallace Lake Area of Caddo Parish, which we first reported to you in conjunction with our first quarter earnings. The Latin had an 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, two 4,600 foot laterals also in Caddo Parish and just north of our Bethany-Longstreet area. Our Baremore Estates 11H 1 and 2 and wells have produced 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. We have again, prepared a slide presentation, and we invite you to follow the slide deck during our prepared remarks. You can access the slide presentation on the Goodrich Petroleum website entitled 2Q 2021 earnings presentation. I will now turn to the slide presentation for those of you who would like to follow along and our standard disclaimer, forward-looking statements and risk factors are highlighted for you on Slide 2. On Slide 3, we provide our ESG 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 in the core of the Haynesville with an additional 1,500 net acres added in the second quarter, which brings our current total to 27,500 net acres. We are now approaching almost two TCF of natural gas resource potential in the core of the play in 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 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 in 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 in 3Q and 4Q with the midpoint of our 3Q guidance ranging – range being approximately 170 million cubic feet of gas equivalents per day, and growing to approximately 192.5 million cubic feet of gas equivalent per day in the fourth quarter resulting in updated full year projected midpoint of guidance at 162 million cubic feet of gas equivalents per day as an average for 2021. We are not just growing for growth’s sake, however. What we are doing is adding and growing our PDP value, EBITDA, and 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 thousand feet of lateral the core of the Haynesville continues to offer low development and lifting cost, top-tier cash margins, strong returns on invested capital, which are only improving with the rally in natural gas prices. Higher production and improved net prices led to quarterly EBITDA of $24.4 million in the second quarter, which we are also projecting will expand meaningfully in both 3Q and 4Q with our production and cash flow guidance, as well as our assumptions for natural gas future prices in the back half of the year. Improving fundamentals also led to adjusted earnings of just under $10 million or $0.72 per basic share in the second quarter. In addition, the higher quarterly EBITDA further reduced our key leverage metric to just 1.2 four times on an annualized basis for the second quarter. And we now project this measure will fall below one turn by the end of this year. Low per-unit cash expenses drove a cash margin in the quarter of 63% and return on invested capital of approximately 45%. We continue to project meaningful free cash flow in 2021 and with the improved pricing and our hedge position, we are currently believe that we can deliver free cash flow in a range of $25 million to $30 million in 2021. Moving to Slide 5. We again show our year-end 2020 SEC proved reserves of 543 Bcf equivalent, which has a present value using a range between $2.50 and $3 per Mcf of $338 million to $485 million discounted at 10% with more room to run as we go forward. On Slide 6, our 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 quarter. Annualized 2Q EBITDA would be $97.6 million and as I mentioned result in net debt 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 Hainesville, our situation may be somewhat unique in today’s environment as we expect to both grow at attractive rates, we’re also delivering significant free cash flow. As we refine our plans for 2022, we will maintain both of these objectives as part of our board deliberations and planning for next year. Moving to Slide 8, you’ll see our updated commodity hedge position, which consists solely of natural gas swaps and collars. In the second half of this year, we have swaps in place at a blended average swap price of $2.88 per Mcf, which we estimate should equate to approximately 63% of second half production using the midpoint of our updated guidance, and 30 million cubic feet of gas per day, or roughly 16% of second half guidance in collars with a ceiling price of $3.50. In 2022, you will see, we have a downward trending amount of hedge volume, again and a combination of swaps and collars, which we believe provides us appropriate downside protection, as well as meaningful upside to higher prices for both incremental current production volumes and anticipated growth in 2022. Finally, we again provide details of our updated 2021 guidance on Slide 9, where we now expect to 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, our recent non-op proposals in the core of the Haynesville and largely occurring in the second half this year with minimal production impact anticipated in this calendar year. We estimate the blended average lateral length for 2021 will slightly longer than our previous estimate, or now currently approximately 8,000 feet. We again provide the updated expected cadence of completion activity along with our projected production and capital expenditures, including the refined guidance for 3Q and 4Q, which I referred to earlier. We also provide a range of expected cash costs per unit of production, which we expect at the midpoint we’ll average approximately $0.84 per Mcf equivalent for year 2021, but we’ll be significantly lower in the second half of this year with a midpoint of approximately $0.075 per Mcf equivalent driven predominantly by better transportation agreements for the volumes we expect to bring online in the second half and higher anticipated production. And with that, I’ll turn the call over to Rob.

[Rob Turnham:]

Thanks, Gill. Revenues were $38.1 million, and we had a realized loss on cash settled derivatives 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 Mcfe or $2.60 per Mcf equivalent when including cash settled derivatives. Our per-unit cash operating expense, which is defined as operating expenses, excluding DD&A, and non-cash G&A decreased by 10% to $0.89 per Mcfe and cash interest expense was $0.06 per Mcfe or a total of $0.95 per Mcf equivalent. Cash margin, including interest expense was a $1.65 per Mcfe or 63% of realized price, including settled derivatives. As you will see in 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 our first quarter financials. We expect production to grow, commodity prices to be higher and per unit costs 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 was spent on drilling, completion and facility costs associated with Haynesville wells. During the quarter, we conducted drilling and completion operations on nine gross, 4.2 net wells and added three gross, 2.8 net wells to production. For the year, we are slightly increasing our capital expenditure budget by $5 million at the midpoint to a range of $80 million to $90 million due to an increase in 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 a day for the second half of the year at the mid-quarter guidance. Interest expense, totaled $2.1 million in the quarter which included cash interest of $900,000 incurred on the company’s revolver 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 remained in the core of the Haynesville beginning of Slides 10 and 11. As mentioned before, we added 1,500 net acres through a deal to earn during the quarter and currently have 27,500 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 in the near future. Our acreage is currently approximately 75% undeveloped and 80% operated. On Slide 12, we show our inventory in North Louisiana, which now totals in excess of 1.9, Tcf of reserve exposure. We’ve not quantified our inventory to 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 play is in our area 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 in the core. Industry pumped an average of approximately 3,500 pounds per foot of proppant, as you can see, our 13 wells are significantly outperforming the industry wells and our 2.5 Bcf per a 1,000 foot type curve. Our wells shown in green were stimulated with approximately 4,000 pounds per foot of proppant with tighter cluster and interval spacing. And 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 a cumulative production curve and shows over time how we are outperforming our type curve. Moving to Slide 16, which reflects our 7,500 foot curve where we now show a composite of 353 industry wells with average proppant loading of 3,270 pounds per foot, which for the most part fits our 2.5 Bcf per 1,000 foot type curve initially, but then falls below our curve as the older understimulated wells fall off. Like the shorter laterals are more recent operated 7,500 foot wells are materially outperforming our type curve. Slide 17 again, just shows how we were outperforming our type curve. On Slide 18, we track our on 10,000 foot laterals against the 310 industry wells drilled and completed in our areas. And as you will see for the most part, track our type curve in the industry mainly because we’ve only recently completed wells with the newer completion design. As Gil stated earlier, among recent 10,000 foot well, the Latin well on the border of Caddo and DeSoto Parishes, which was, which had a completed interval of 9,900 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 10,000 foot wells with this optimum completion methodology. Slide 19 again, tracks 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 and optimum completion design, or 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 to provide high recoveries of gas in place. And most importantly, maximizes returns. We have seen very little service cost inflation to date and our economics is shown on slides 20 through 22 or as good as we have seen them in the basin. The outperformance of our curves on the 4,600 and 7,500 foot laterals and service cost deflation across all wells has created a unique situation where a minimum of $2.50 gas can generate approximately a 100% or greater IRRs. As a reminder, the Haynesville economics are driven by high volumes, attractive netbacks relative to Henry Hub as compared to other gas basins, low lifting costs and severance tax abatement until the earlier of two years or pay out of the well. Profitability and value creation are driven from attractive cash margins, which we are currently experiencing. Moving to Slides 23 and 24 as I said, previously, our cash cost per unit, including interest expense of $0.95 has this ranked first among our gas peers when compared to their first quarter results and our cash margin of a dollar $1.65 or 63% of our realized price, including hedges again, ranks first among our gas peers. Again, when it comparing against first quarter financials. We will update for our peer’s second quarter results once everyone has reported. Our return on invested capital shown on Slide 25 is extremely attractive at 45%, 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 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 in higher production, higher realized prices and lower per unit cash costs, we anticipate our cash margin and return on invested capital will move even higher. In summary, our team is executing very well. Our balance sheet is in very good shape with low debt metrics and heading lower. And we are generating superior returns both in the field and at the corporate level. We continue to add to our inventory depth with very accretive bolt-on acquisitions and inspect more of the same in the back half of the year. With this favorable backdrop for the remainder of 2021 and 2022, we look forward to continuing to share our results, which we believe will only better. With that, I will turn it back to the operator for Q&A.

[Operator:]

Yes. Thank you. [Operator Instructions] And the first question comes from Austin Aucoin with Johnson Rice.

[Austin Aucoin:]

Hello and good morning.

[Gil Goodrich:]

Good morning, Austin.

[Austin Aucoin:]

My first question is sort of regarding the increased CapEx guidance. I know y’all mentioned an influence from some non-op being part of that change, but there also sort of an increase in expected cost inflation baked into there, or potentially result of the completion schedule moving forward due to some operational efficiencies?

[Rob Turnham:]

Yes, Austin, this is Rob. No, 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 previous guidance. And because those wells are getting drilled in the second half of this year. We really won’t see much production and cash flow from those wells. So, it’s something that, we need to do just to participate. These wells are extremely economic and unfortunately most of the benefit of that participation is going to be in early 2022.

[Austin Aucoin:]

Great, thank you. That’s very helpful. And sort of like a follow-up. In regards to the acquisition in the Haynesville buying out 1,500 acres, how does that A&D market look at this time? And are there any certain deals in the pipeline now worth considering,? I know you all mentioned that there’s a mentioned that there’s expansion in the near future. Is there any sort of specific information or light you can bring on that at this time?

[Gil Goodrich:]

Yes, Austin, this is Gil. Good morning. As Rob said earlier, we are reviewing a number of opportunities. I would characterize it as a, relatively modest in size but a number of different opportunities 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 to capture a piece of that with our capital. So we are looking at a number of things and no if there was something, we had ready to disclose, we would do it this morning, but we are working on some things. We’ll see what happens, no guarantees, but if we have something of any meaningful size, we’ll certainly report that when it occurs.

[Austin Aucoin:]

Great. Thanks for taking my questions.

[Gil Goodrich:]

Thanks. Thanks, Austin.

[Operator:]

Thank you. [Operator Instructions] All right, this concludes the question-and-answer session. I’d now like to turn the call to Gil Goodrich for any closing comments.

[Gil Goodrich:]

Sure. Thank you everybody. Appreciate your participation this morning. We believe we can continue to deliver production growth. We have a 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 into 2022. So thank you for participating.

[Operator:]

Thank you. The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect your lines.