Comstock Resources, Inc. (NYSE:CRK) Q3 2023 Earnings Call Transcript

Comstock Resources, Inc. (NYSE:CRK) Q3 2023 Earnings Call Transcript October 31, 2023

Operator: Good day, and thank you for standing by, and welcome to the Q3 2023 Comstock Resources, Inc. Earnings Conference Call. [Operator Instructions]. I would now like to introduce your host for today’s call, Jay Allison, Chairman and CEO. Please go ahead.

Miles Allison: Good morning, everyone. In Frisco, Texas, this morning, it’s 34 degrees. The Texas Rangers took a lead in the World Series, and I saw natural gas prices were up about $0.20 this morning. So we’re all smiles here. We started out the day the right way. The world of natural gas is something that is a big part of our business. Reported profitable third quarter with a realized gas price of only $2.41 with only 18% of our gas hedged highlights our extremely low operating cost structure and our high margins. The 18 net operated wells returned to sales since our last update on our extensive Haynesville/Bossier acreage position continued to deliver solid results from our legacy area as well as the emerging Western Haynesville.

The 2 Western Haynesville wells we recently turned to sales were “top-of-the-class” wells as were the other 5 that we turn to sell starting with our Western Haynesville well, the Circle M, which started production in April of 2022. And make no say about it, we’re extremely pleased with the results of all the Western Haynesville wells we have turned to sell so far. This year, we are focused on proving up the Western Haynesville and continuing to build our extensive acreage position. During this time of weak natural gas prices, we’re providing a dividend to our stakeholders, holding our legacy production steady while being accountable to our bank lending group have just reaffirmed our $2 billion borrowing base and proving up a much-needed new get go resource near the expanding LNG export facilities along the Texas and Louisiana Gulf Coast.

A major step in development of our Western Haynesville play is finding the right partner for the midstream build out needed to support our Western Haynesville drilling program, and we are excited to partner with Quantum Capital Solutions to that end. We want to publicly thank them for entering into this new adventure with us. If you’ll go to the main slides, we welcome you to the Comstock Resources third quarter 2023 financial and operating results conference call. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com or downloading the quarterly results presentation. There, you’ll find a presentation titled Third Quarter 2023 results. I am Jay Allison, Chief Executive Officer of Comstock.

And with me is Roland Burns, our President and CFO; Dan Harrison, our COO; and Ron Mills, our VP of Finance and Investor Relations. If you go to Slide 2, please refer to Slide 2 in our presentations and note that our discussions today include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. Now if you’ll flip to Slide 3. What we’ll do is we’ll summarize the highlights of the third quarter. The financial results were heavily impacted by the continued low natural gas prices we realized in the quarter. Oil and gas sales, including hedging were $316 million in the quarter. We generated cash flow from operations of $167 million or $0.60 per share and adjusted EBITDAX was $209 million.

Our adjusted net income was $0.04 for the quarter. We continue to have strong results from our drilling program. We drilled 13 or 10.2 net successful operated Haynesville and Bossier shale horizontal wells in the quarter with an average lateral length of 11,644 feet. Since the last conference call, we’ve connected 21 or 18.1 net operated wells to sales with an average initial production rate of 29 million cubic feet per day. We’re having great success in our Western Haynesville exploratory play. Our sixth and seventh wells were recently turned to sales with strong initial production rates, both of which were drilled in the Bossier shale. We recently entered into a new venture with Quantum Capital Solutions to fund the midstream have built out to support our Western Haynesville drilling program, which I’ll expand on the next slide.

If everyone would turn to Slide 4, this visibly shows our Bethel plant, which is part of the Pinnacle gathering and treating system we acquired last year. Pinnacle combined with our processing we have in the area will allow us to grow our Western Haynesville production up to 500 million cubic feet per day. Given how prolific these wells have been we see running out of capacity in this area by 2025. We’re excited to partner with Quantum Capital Solutions, an affiliate of Quantum Capital Group to build out this system to handle future growth. To that effect, we have set up a mid-spring partnership with QL to build out the system to increase the capacity fourfold, will contribute to Pinnacle gathering and treating system to the partnership and QL will contribute 100% of the capital required up to $300 million for the build out of the gathering and treating system.

We’ll operate the partnership, which will be called Pinnacle Gas Services and will direct is activities. Quantum receives a preferred return and 80% of distributions until the investment hurdle is achieved, then that reduces to 30%. I’ll now turn it over to Roland to cover the third quarter financial results. Roland?

Roland Burns: All right. Thanks, Jay. On Slide 5, we covered the third quarter financial results. Our production in the third quarter was $1.4 Bcfe per day, which was 1% higher as compared to the third quarter of last year and 3% higher than the second quarter. Low natural gas prices significantly impacted our oil and gas sales in the quarter, which came in at $316 million, which is 54% lower than the third quarter of 2022. EBITDAX was $209 million, and we generated $167 million of cash flow during the quarter. We reported adjusted net income of $12 million for the third quarter as compared to only $1 million in the second quarter of this year and then $326 million in the third quarter of last year. Slide 6, we have our financial results for the first 9 months of this year.

Production for the first 9 months averaged 1.4 Bcfe per day. That was 4% higher as compared to the same period in 2022. Oil and gas sales in the first 9 months of this year totaled $991 million, which is 42% lower than last year’s sales in the same period and EBITDAX was $685 million, and we generated $568 million of cash flow for the first 3 quarters of this year. We reported adjusted net income of $105 million for the first 3 quarters of this year as compared to $735 million for the same period in ’22. On Slide 7, we detail our natural gas price realizations that we had in the third quarter. The quarterly NYMEX settlement price in the third quarter averaged $2.55. It was very close to the average spot price in the quarter, which averaged $2.58.

Our realized gas price during the third quarter averaged $2.33, reflecting that $0.22 differential to the settlement price and a $0.23 differential to the reference price. The differential this quarter returned to more normal levels due to improvements in the Houston Ship Channel and Katy Hub prices following the restart of the Freeport LNG facility. In the third quarter, we were 18% hedged, which improved our realized gas price to $2.41. We’ve been using some of our excess transportation in the Haynesville to buy and resell third-party gas. We generated about $2.5 million of profits from this activity, which improved our average gas price realization by another $0.02. On Slide 8, we detail our operating cost per Mcfe produced in our EBITDAX margin.

Our operating cost averaged $0.85 per Mcfe in the third quarter. It’s 1% higher than our second quarter rate. The increased unit costs relate to higher production taxes and higher ad valorem taxes imposed in the state of Louisiana. Our gathering costs were flat this quarter at $0.36 and our other lifting costs were 3% lower than the second quarter rate at $0.24. Our production in ad valorem taxes increased $0.05 this quarter compared to the second quarter level. G&A came at $0.05 per Mcfe. That was $0.01 lower than the rate we had in the second quarter. And our EBITDAX margin after hedging came in at $0.65 — 65% in the third quarter as compared to 63% in the second quarter of this year. On Slide 9, we recap our spending on drilling and other development activity for the first 9 months of this year.

So far, we spent $958 million on our development activities, including $919 million on our operated Haynesville and Bossier shale drilling program. Spending on other development activity has totaled $38 million so far this year. In the first 9 months of this year, we drilled 52 wells or 41.3 wells net to our interest in our operated drilling program, and we’ve turned 57 or 43 net operated wells to sales. The wells we turned to sales had an average IP rate of 25 million cubic feet per day. On Slide 10, we recap our balance sheet at the end of the third quarter. We ended the quarter with $345 million of borrowings outstanding under our credit facility, giving us a total of $2.5 billion in total debt. Our $2 billion borrowing base was recently reaffirmed by our bank group this month, and we ended the third quarter with financial liquidity of almost $1.2 billion.

I’ll now turn it over to Dan to discuss the operations in more detail.

Daniel Harrison: Okay. Thank you, Roland. So Slide 11 is a breakdown of our current drilling inventory at the end of the third quarter. The drilling inventory split between the Haynesville and the Bossier and is divided into 4 categories with our short laterals that are up to 5,000 feet. We got our medium laterals that run from 5,000 to 8,000 feet. Our long laterals at 8,000 to 11,000 feet and our extra long laterals, beyond 11,000. The total operated inventory currently stands at 1,760 gross locations in 1,338 net locations. This equates to a 76% average working interest across the operated inventory. Our nonoperated inventory has 1,265 gross locations and 153 net locations, which represents a 12% average working interest across the nonop inventory.

Breaking down our gross operated inventory, we have 307 short laterals, 286 medium laterals, 712 long laterals and 455 extra long laterals. The gross operated inventory is split 52% in the Haynesville and 48% in the Bossier. 26% of the gross operated inventory for the 455 locations have the lateral lengths greater than 11,000 feet, 66 or 2/3 of the gross operated inventory has laterals exceeding 8,000 feet. The average lateral length in the inventory stands at — now stands at 8,949 feet, which is up slightly from 8,947 feet at the end of the second quarter. The inventory provides us with 25 years of future drilling locations. On Slide 12 is the chart, which outlines our progress to date on our average lateral length drilled based on the wells that we’ve turned to sales.

During the third quarter, we turned 21 wells to sales with an average lateral length of 10,460 feet, thanks to the continued success of our long lateral drilling program. The individual links range from 6,789 feet up to 15,333 feet, and our record longest lateral still stands at 15,726 feet. During the third quarter, 6 of the 21 wells we turned to sales had laterals that exceeded 11,000 feet, and 5 of these exceeded 14,000 feet. To date, we’ve drilled a total of 64 wells with laterals over 11,000 feet and 33 wells with laterals over 14,000 feet. During the third quarter, we also had 2 additional wells that turned the sales on our new Western Haynesville acreage. The Cazey MS #1 and the Lanier #1 wells were both completed in the Bossier shale.

These wells represent the sixth and seventh new vintage wells now producing in the Western Haynesville. Based on our current schedule, we plan to turn another 17 wells to sales by year-end. 13 of these will be longer than 11,000 feet and 8 of the wells longer than 14,000 feet. We expect by year-end 2023, our average lateral length will be approximately 11,000 feet. Slide 13 outlines our new well activity. We’ve turned to sales and tested 21 new wells since the time of the last call. The individual IP rates ranged from 18 million a day, up to 39 million a day at an average test rate of 29 million cubic feet a day. The average lateral length was 10,460 feet with individual laterals from 6,789 up to 15,333 feet. Included in the quarter again are the sixth and seventh in new vintage wells in our Western Haynesville acreage.

The Cazey MS, which was completed in the Bossier had a lateral length of 10,028 feet and was turned to sales in August. We tested the well with an IP rate of 34 million cubic feet a day. The Lanier #1 well, which was also completed in the Bossier, is completed with a 9,577-foot lateral and this well was turned to sales in September. We tested this well with an IP rate of 35 million cubic feet a day. In addition to the first 7 producing wells, we have 1 well that is currently waiting on completion, and we do expect to turn that well to sales in January. We currently have 2 rigs actively running on our Western Haynesville acreage that are drilling our ninth and tenth wells. Slide 14 summarizes our D&C costs through the third quarter for our benchmark long lateral wells that are located on our legacy core East Texas and North Louisiana acreage.

This covers the wells having laterals greater than 8,500 feet long. During the quarter, we turned 19 wells to sales that were on our core East Texas, North Louisiana acreage, and 13 of the 19 wells were our benchmark long lateral wells. In the third quarter, our D&C cost averaged $1,561 a foot on these 13 benchmark wells, which reflects a 1% increase compared to the second quarter. Our third quarter drilling costs averaged $719 a foot, which is a 10% increase compared to the second quarter partially due to the lower average lateral length in the quarter and some drilling issues encountered in the quarter. Our third quarter completion costs came in at $842 a foot. This is a 5% decrease compared to the second quarter. The decrease in completion cost mirrors a slight decline in service costs.

We have experienced this earlier in the year, which is associated with the lower activity levels. And to wrap up our forecasted activity levels. We’re currently running 7 rigs. We do expect to keep the same rig activity going into next year. And we are also running our 3 frac crews, and we expect to keep these 3 frac crews also working in the next year. I’ll now turn the call back over to Jay.

Miles Allison: Okay. Thank you, Dan. Thank you, Roland. For everyone, we’ll turn to Slide 15. I will direct you to Slide 15, where we summarize our outlook for the rest of 2023. We remain very focused on proving up our Western Haynesville play continuing to add to our extensive acreage position in this prolific play. We believe that we are building a great asset in the Western Haynesville that we’ll be well positioned to benefit from the substantial growth in demand for natural gas in our region that is on the horizon, driven by the growth in LNG exports that begins to show up in the second half of next year. Our new Western Haynesville midstream partnership will reduce 2024 capital expenditures that would otherwise be required to support the growth in production that we expect our industry-leading lowest cost structure is an asset in the current natural gas price environment as our cost structure is substantially lower than the other public natural gas producers.

We plan to retain the quarterly dividend of $0.125 per common share. And lastly, we’ll continue to maintain our very strong financial liquidity, which totaled almost $1.2 billion at the end of the quarter. I’ll now have Ron to provide some specific guidance for the rest of the year. Ron?

Ron Mills: Thanks, Jay. On Slide 16, we provide the financial guidance for the fourth quarter of 2023. Fourth quarter D&C CapEx guidance is $240 million to $280 million. And we’ve seen some signs of deflationary pressures on service costs relative to earlier this year. We believe most of those improvements will be seen in 2024. In terms of infrastructure and other spending, we continue to budget $15 million to $25 million of spending during the fourth quarter. On a combined basis, our D&C and infrastructure and other CapEx should remain within our past annual guidance of $1.02 billion to $1.28 billion. In addition to what we spent on our drilling program noted above, we now anticipate spending $30 million to $40 million in the fourth quarter for additional leasing activity.

Our LOE costs are expected to average $0.24 to $0.28 per Mcfe in the fourth quarter, while our gathering and transportation costs are expected to be $0.32 to $0.36 per Mcfe in the fourth quarter. Production in ad valorem taxes are expected to average $0.16 to $0.20 per unit in the fourth quarter, which is higher due to higher ad valorem taxes in Louisiana to go along with the higher production tax rate that Louisiana put into effect at the beginning of the third quarter. DD&A rate is expected to remain in the $1.05 to $1.15 per Mcfe range, while our cash G&A is expected to remain in the $7 million to $9 million range for the quarter with an additional plus roughly $2 million of noncash G&A. Due to the increase in SOFR rates, our cash interest expense is now expected to total $42 million to $46 million in the fourth quarter, while our noncash interest will remain roughly $2 million per quarter.

On taxes, the effective tax rate is still expected to be in the 22% to 25% range, and we still expect to defer 95% to 100% of our reported taxes this year. Now I’ll turn the call back over to the operator to answer questions.

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Q&A Session

Operator: [Operator Instructions]. And our first question comes from Derrick Whitfield from Stifel.

Derrick Whitfield: Regarding the Quantum partnership, I wanted to confirm a comment you made in your prepared remarks. If my numbers are correct, a fourfold in suggests you’re solving for 2 Bcf per day of capacity in the Western Haynesville. If that’s correct, could you comment on how you’re thinking about mainline egress as well?

Miles Allison: Well, I think when we looked at our footprint in the Western Haynesville, as when we look at our inventory, and we looked at the wells that we’ll be drilling between now and maybe 2028, and we look around the corner to see what type of production we may have between now and then. And a lot of that depends upon what the market needs and we think in the latter part of ’24, you’re going to need another 4.5 to 5 Bs. And every year after that, you’re going to probably need another B a day. And that’s just for LNG, exportable gas as feed gas. So when we looked around in Quantum, which is I mean, that is a Blue Ribbon financing source when we started visiting with them months ago, and they started looking at our footprint and the well performance.

We looked at, well, what do we need to do for infrastructure to build this out. We also looked at in the second quarter of 2022 when we had bought the Pinnacle facility, the Bethel in that 145-mile pipeline. What is our starting block as far as midstream company. So we evaluated all that. We looked at the rig count which, again, we will add. Our goal is to add a rig in the Haynesville — in the Western Haynesville next year. So we go from 2 rigs to 3 and then we would add another rig in 2025, and we think that’s what HPP, our footprint. So if you look at that and you look at the model for 5 years, and you look at the need for gas, we modeled it out that by 2028, we would have the capacity with the takeaway, both for transportation and the gathering with the financing from Quantum to have at least 2 Bs a day that we would have available to serve America and the globe.

That’s where we come up with this fourfold number. And it’s based upon us having about 500 million a day by kind of mid-2025 and then growing on that with investments that we would make between now and then and into the future years to 2028. That is how we backed into this, which — I think that’s a really good question because Quantum, which is known for funding midstream in the Western — in the Haynesville and now in the Western Haynesville. I mean I think they looked at everything kind of like our banks did and said, we’re really pleased with what you’ve done and we like where you’re going, and we would like to partner with you. And so we were — that’s why we publicly thank them for entering through this new venture with us. Because they give a good check mark to the rest of the world that they do approve with what we’ve been doing and where we’re going.

Remember, our first Western Haynesville well was only drilled 2 years ago. We started drilling those 2 years ago, and we started leasing the acreage 3 years ago, but we really are building the company. And when you build a company, you have to look what’s going to happen in ’27, ’28 and all that is dependent upon the feedstock that stated for LNG. That’s where we had the announcement today, and that’s where the 2 Bs come from. You did your math on that.

Derrick Whitfield: Appreciate it, Jay. Thanks for all the color, too. In the past, you guys have talked about the Western Haynesville and the asset seeing similar returns to the legacy Haynesville at kind of current operating conditions. With the understanding that you’re still in the early stages of your learning curve in the Western Haynesville, could you speak to what you’re seeing in operational efficiency gains and the degree cost could improve over time?