Comstock Resources Q1 2023 Earnings Call Transcript

Quartr
Provided by Quartr
May 3, 2023

There are 13 speakers on the call.

Operator

Thank you for standing by, and welcome to the Comstock Resources First Quarter 2023 Earnings Conference Call. At this time, all participants are in a listen only mode. After the speakers' presentations, there will be a question and answer session. As a reminder, today's call is being recorded. I would now like to turn the conference over to your host, Mr.

Operator

Jay Allison, Chairman and CEO. Please go ahead.

Speaker 1

Perfect. Thank you, and good morning, everyone. I'd like to welcome all of you to the Comstock Resources Q1 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 and downloading the quarterly results presentation. There you'll find a presentation entitled Q1 2023 results.

Speaker 1

I have Jay Allison, Chief Executive Officer of Comstock. With me is Roland Burns, our President and Chief Financial Officer Dan Harrison, our Chief Operating Officer and Ron Mills, our VP of Finance and Investor Relations. If you'll flip over to Slide 2, please refer To Slide 2 in our presentation, note that our discussions today will include forward looking statements within the meaning of securities laws. While we believe the expectations of such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. If you'll step over to Slide 3, I want to kind of address the issues.

Speaker 1

I've read, I think all of the analyst reports that have been published and understand the concerns. None are of new concerns. We understand them. If you look at where oil is today plus yesterday, it's down $7 Look at where natural gas is yesterday and today, it's down $0.20 So we all know We are experiencing pressure with low natural gas prices currently in the short term. However, we are extremely positive on the outlook Looking ahead, several years, we recognized the growing need for natural gas around the world.

Speaker 1

Our long term goal is to be a significant supplier to the growing LNG market that is developing several 100 miles From our Haynesville shale operations, including our emerging Western Haynesville area. Around the world today, Over $1,000,000,000,000 of natural gas infrastructure is being built. Over the next 5 years, in the United States, we see more than $100,000,000,000 worth of new LNG plants being operational. We're currently in discussions Enter into long term contracts with major LNG shippers who are following our new play with significant interest. To accomplish that goal, we must be great, great stewards of managing our dollars in this low gas price environment, while at the same time continuing to delineate our Western Angel asset.

Speaker 1

To that effect, we are continuing to run A 2 rig program that should result in 14 drilled wells by year end 2023. We also plan to wrap up our leasing efforts that we started almost 3 years ago. In the Q1, we made great strides by materially adding To our acreage position as you've noted, the well results in our traditional Haynesville area where we had 6 to 7 rigs running continue to be very solid. We'll be down to 5 rigs in the next couple of weeks. The Q1 still has some inflation baked into the well cost, but we see that abating In the next several quarters, we're continuing to reevaluate our rig count in our traditional Haynesville area as well as our completion timing to be responsive to the weak price environment we are in as we are very focused on maintaining the Strong balance sheet that we've worked so hard to create last year.

Speaker 1

In summary, we are implementing a practical business plan focused on the longer term cycle to position Comstock to benefit from the future growth in the LNG market. We'll monitor our plan to delineate our Western Haynesville play, while adjusted based upon the results that we achieved. But We'll continue to prioritize our longer term goals while being very proactive to protect our strong balance sheet, Which is allowing us to weather the current short term headwinds we see. If you go to Slide 3, we'll include some of the first Quarter highlights. Our production increased 11% to 1,400,000,000 cubic feet of gas equivalent per day.

Speaker 1

We had oil and gas sales of $390,000,000 and operating cash flow of $255,000,000 or $0.92 per diluted share. Adjusted EBITDAX for the quarter was $293,000,000 Our adjusted net income for the Q1 was $92,000,000 or $0.33 per share. The financial results in the quarter reflect the weaker natural gas prices following the warm winter weather that we had. In the Q1, we drilled 18 or 13.7 net operated Haynesville and Bossier horizontal wells, Which had an average lateral length of 12,075 feet. Since our last update, we've connected 15 or 9.8 net Operator wells to sales with an average initial production rate of 23,000,000 cubic feet per day.

Speaker 1

These wells include 6 wells with lower IP rates in the liquid rich area of Panola County, which has associated liquid production. We also announced our 3rd successful exploratory well at our Western Haynesville play, the Campbell well, which had an initial production rate of 30 6,000,000 cubic feet per day, which is a rate that we expect to produce it at. We had an active quarter of borrowing additional acreage in our Western Haynesville play. So now I'll turn it over to Roland to discuss the financial results. Roland?

Speaker 2

Thanks, Jay. On Slide 4, we cover A quick summary of our financial results that we reported for the Q1. As Jay said, our production in the Q1 increased 11% to 1.4 Bcf per day as compared to the Q1 of 2022. Oil and Gas sales in the quarter, including hedging gains decreased About 4% to $390,000,000 as lower natural gas prices offset the production growth that we had in the quarter. Our EBITDAX decreased by 12% to $293,000,000 and we generated $255,000,000 of cash flow during the quarter, 14% less than 20 22's Q1.

Speaker 2

We reported adjusted net income of $92,000,000 for the Q1 And our earnings per share came in at $0.33 as compared to $0.51 in the Q1 of 2022. On Slide 5, we provide a breakdown of our natural gas price realizations in the quarter. During the Q1, the quarterly NYMEX settlement price, Which averaged $3.42 was substantially higher than the average Henry Hub spot price In the daily market of $2.67 During the quarter, we nominated 82% of our gas to be sold at the index prices Tied to that contract settlement price and we sold the other 18% of our gas in the daily spot market. So the estimated NYMEX reference price for our sales in the Q1 would have been $3.29 Our realized gas price during the Q1 averaged $2.98 reflecting a $0.31 differential to the reference price. That differential is higher than our normal for us due to the continued weaker Houston Ship Channeling And Katy Hub prices that persisted during a good bit of the Q1 due to the Freeport LNG facility shutdown.

Speaker 2

With the Freeport startup late in the quarter, we've seen these price differentials along the Texas Gulf Coast tighten up Somewhat. About 57% of our gas is tied to the Gulf Coast market indexes and we Currently selling 21% of our gas directly to LNG shippers. In the Q1, we were also 53% hedged, Which improved our realized gas price to $3.07 And we've been using some of our excess transportation in the Haynesville to buy and resell third party gas. This generated about $9,000,000 of profit and improved our average gas price realization by another $0.07 On Slide 6, we detail our operating cost per Mcfe and our EBITDAX margin. Our operating cost per Mcfe averaged $0.83 in the Q1, dollars 0.07 higher than our Q4 rate.

Speaker 2

The increased unit costs are related primarily to start up The startup phase that we're having at our Western Haynesville area, where fixed costs are being spread over lower production volumes. We expect them to come down as our production grows in that area. Our gathering cost increased by $0.04 during During the quarter and our lifting cost increased by $0.03 Our production taxes remained the same as we had in the 4th quarter. Our EBITDAX margin after hedging came in at 73% in the Q1, down from the 82% we had in the 4th quarter Where we had substantially stronger gas prices. On Slide 7, we recap our spending on our drilling and other development activity End the Q1.

Speaker 2

During the quarter, we spent a total of $325,000,000 on development activities, including $278,000,000 Spend on our operated Haynesville and Bossier Shale drilling program. We also spent another $32,000,000 on non operated wells. Spending on other development activity, which includes installing production tubing to offset frac protection and other workovers Totaled $14,000,000,000 in the quarter. In the Q1, we drilled 18 or 13.7 net To our interest, operated horizontal HaynesvilleBossier wells and we turned 19 wells or 11.6 net operated wells to sales. These wells had an average initial production rate of 24,000,000 cubic feet per day.

Speaker 2

On Slide 8, we recap our balance sheet at the end of the first We ended the quarter with no borrowings outstanding under our credit facility and with $2,200,000,000 in long term debt. In April, the 17 banks at our bank group reaffirmed our $2,000,000,000 borrowing base with $1,500,000,000 of electric commitments. Our revolving credit facility matures in 2027. So we ended the Q1 with financial liquidity of more than $1,500,000,000 I'll now turn it over to Dan to discuss our operations in more detail.

Speaker 3

Okay. Thank you, Roland. Slide 9 is the breakdown of our 2023 Quarter end drilling inventory. Our drilling inventory is split between Haynesville and Bossier. We got it divided into 4 buckets, Short laterals up to 5,000 feet are medium laterals that run between 5000 8,000 feet.

Speaker 3

Our long laterals run from 8,000 to 11,000 feet and our recently created category of our extra long laterals For our wells at 6,011,000 feet laterals. Our total operated inventory currently stands at 1810 gross locations, 1364 net locations, which equates to a 75% average working interest on the operated inventory. Our non operated inventory, we have 13 10 gross locations and 182 net locations, which represents a 14% Average working interest on our non operated inventory. Based on the success of our recent extra long lateral wells, we continue to leverage our acreage position Where possible, the modify our drilling inventory and extend our future laterals, specifically targeting the 10000 to 15000 foot range. In our extra long lateral bucket, we currently have 4 59 gross operated locations And 3 34 net operated locations.

Speaker 3

And to recap, to recap our gross operated inventory, we have 313 Short laterals, 298 medium laterals, 7.40 long laterals and the 4.59 extra long laterals. The gross operated inventory is split 53% in the Haynesville and 47% in the Bossier. By extending our laterals, the average lateral length in our inventory now stands at 8,928 feet. This is up slightly from our 8,870 feet we had at the end of 2022. In addition to the economic uplift, the longer laterals reduce our surface footprint and help us to reduce our greenhouse gas and methane intensity levels.

Speaker 3

Based on our planned 2023 activity level, this inventory provides us with a 25 year runway of future drilling locations. On slide 10 is a chart. This outlines the average lateral length we've drilled by year. During the Q1, we turned 19 wells to sales with an average lateral length of 9,898 feet. The individual laterals range from 4,514 feet on the short end up to a 15,580 foot 584 foot long lateral on the long end.

Speaker 3

15 of the 19 wells we turned to sales during the quarter were our Mint Mark, long lateral wells that are greater than 8,000 feet long. 5 of the wells were beyond 11,000 foot laterals We had 2 of the laterals coming in longer than 15,000 feet. Our record long lateral well still stands at 15,720 This is on our East Texas acreage and that well was turned to sales during the Q4 of last year. Included in the group is the 3rd well we recently completed on our Western Haynesville acreage, the Campbell EOB 2H well, Which was completed in the Bossier formation with a 12,763 foot long lateral. Based on our current schedule, we plan to turn another 52 wells to sales by year end.

Speaker 3

22 of these 52 future wells will be extra long laterals beyond 11,000 feet And 12 of the wells will be 15,000 foot laterals. If successful, our 2023 year end average lateral length will increase to approximately 10,855 feet. Slide 11 outlines our new well activity. We have turned to sales and tested 15 new wells since the time of our last call. We had really good well performance again on this group of wells with the individual IP rates ranging from 13,000,000 a day up to 37,000,000 cubic feet a day with an average test rate of 23,000,000 a day.

Speaker 3

The average lateral length was 11,040 feet with individual laterals ranged from 4,514 feet

Speaker 1

Up to

Speaker 3

15,584 feet. Included in this latest well activity are 6 wells that were completed on our liquids rich Haynesville acreage in Panola County. The gas produced on this acreage represents 25 to 30 barrels of natural gas liquids, which in turn enhances our economics 20% to 30% versus the dry gas well. The average IP rate for our working interest ownership in the 15 wells for the quarter is 25,000,000 a day, which is comparable to prior quarters even with the 6 low IP wells as we have a lower working interest in those wells. Also included this quarter was our successful third well on our Western Haynesville acreage, the Campbell 2 well, This was completed in the Bossier with a 12,763 foot long lateral was turned to sales in March.

Speaker 3

We tested the well with an IP rate of 36,000,000 cubic feet a day and we are currently flowing the well at this rate today and and plan to produce the well at the same rate. In addition, we are currently completing our 4th well on the acreage and have a 5th well that is waiting on completion. We expect to turn both of these next two wells to sales within the next couple of months. Additionally, we're running 2 rigs on our Western Haynesville acreage that is currently drilling our 6th and 7th wells. Slide 12 summarizes our D and C costs through the Q1 for our Bit Smart Long Ladder Wells, This covers all our wells greater than 8,000 feet on our legacy core East Texas, North Louisiana acreage position.

Speaker 3

14 of the 19 wells returned to sales during the quarter were these benchmark long lateral wells. In the Q1, Our D and C cost averaged $15.79 per foot, which is an 11% increase compared to 4th quarter and a 19% increase over our full year 2022 D and C cost. Our 1st quarter drilling costs came in at $6.63 a foot, which is a 14% increase compared to the 4th quarter. A majority of the drilling cost increase is attributable to a shorter average lateral length for this quarter versus the last Along with inflation as most of the wells we turned to sales were drilled in the Q3 and early Q4. Our first quarter completion costs came in at $9.16 a foot, which is a 9% increase compared to the 4th quarter.

Speaker 3

The primary contributor to our higher completion costs during the Q1 was the fact that only 20% of our Q1 well completions Refract with our Titan natural gas fleet as opposed to more than half of our 4th quarter wells refract using the Titan natural gas fleet. As mentioned on the previous calls, we've been able to capture significant savings through the use of the Titan natural gas fuel fleet compared to the conventional diesel fleet. With that being said, we are expecting the delivery of our 2nd Titan fleet within the next couple of months. To sum up where we stand on activity levels, we are currently running 8 rigs. 1 of these will be released in a couple of weeks to bring us down to 7 rigs.

Speaker 3

On Slide 13, we highlight our continued improvement related to greenhouse gas and methane emissions. We reported a greenhouse gas intensity of 3.47 kilograms of CO2 equivalent per BOE of production. This is a 3% improvement versus 2021. Well, we reported a methane emission intensity rate of 0.045 15% improvement versus 2021. We achieved those emissions improvements despite our turn to sales Lateral feet increasing by 10% in 2022.

Speaker 3

Adjusting for lateral lengths completed for our turn to sales wells, Our greenhouse gas emissions per lateral foot turn to sales improved 10%, while our methane emissions per lateral Turn to sales improved by 22%. We deployed optical Gas imaging and aircraft leak monitoring technology at almost 100% of our production sites, which earned us the ability to certify our gas as responsibly sourced. Our natural gas powered frac fleet eliminated approximately 5,000,000 gallons of diesel by utilizing natural gas, Offsetting approximately 10,200 metric tons of CO2 equivalent. As a reminder, our 1st natural gas powered frac fleet began operating in April, so that data reflects just 9 months of contribution to our 2022 numbers. With our 2nd natural gas fired fleet arriving in the field by the end of the second quarter, we should see continued reductions in our emissions.

Speaker 3

Our dual fuel drilling rigs eliminated approximately 600,000 gallons of diesel by utilizing natural gas, Which offset approximately 1900 metric tons of CO2 equivalent. We installed instrument air on approximately 65% of our newly constructed production facilities, mitigating approximately 4,000 metric tons of CO2 equivalent. I'm now going to turn the call back over to Jay to sum up the 2023 outlook.

Speaker 1

Thank you, Dan. And I believe We're the first HaynesvilleBossier company to have 100% of our natural gas certified by MIQ standards, which tells you that All the gas we produced is responsibly sourced gas. In the future, that may create some additional value. But again, we're going to be stewards of the environment. If you would turn over to Slide 14, I direct you to Slide 14, where we summarize our outlook for 2023.

Speaker 1

We will continue to derisk and delineate our Western Haynesville play With the 2 rig program in 2023, which I had mentioned, our primary objective this year is to prove up our new play. At the same time, we are managing our drilling activity levels to prudently respond to the lower gas price environment as we continue to experience it. We will be releasing the second of the 2 rigs on our legacy Haynes footprint within the next couple of weeks, Which we discussed at the last conference call in order to pull our activity in to response to the slow natural gas prices. In addition to evaluating additional changes to our rig count, we are looking at delaying some completions. We remain focused on maintaining the strong balance sheet that we had created last year.

Speaker 1

Our industry leading lowest cost Structure provides acceptable drilling returns even at current natural gas prices as our cost structure is substantially lower And the other public natural gas producers, we do plan to retain the quarterly dividend of that $0.125 And lastly, we'll continue to maintain our very strong financial liquidity as Roland reported Which totaled more than $1,500,000,000 at the end of the Q1. I'll turn it over to Ron now For specific guidance for the rest of the year, Ron?

Speaker 4

Thanks, Jay. On Slide 15, we provide the financial guidance for 2023. 2nd quarter production guidance of 1.375 Bcf a day is consistent with our prior commentary that 2nd quarter production should be similar to that of the Q1. Full year guidance remains unchanged from our initial guidance for the year 1.425 Bcf to 1.55 Bcf B per day. During the Q2, we do plan to turn to sales between 11 14 net wells.

Speaker 4

As Jay mentioned, our 2023 wells, Dan mentioned, we'll have an average lateral length of about 10,850 feet, which is 8.5% to 9% longer than last year, which continues to help offset Some of the cost inflation that we had experienced. 2nd quarter D and C CapEx is $260,000,000 to $310,000,000 And the full year D and C CapEx remains unchanged at that $950,000,000 to $1,150,000,000 range. In terms of our infrastructure and other spending, we Continue to budget $15,000,000 to $30,000,000 of spending during the Q2 $75,000,000 to $125,000,000 for The full year. In addition to what we spend on the drilling program noted above, we now anticipate spending between $50,000,000 $60,000,000 this year on leasing activity. That number has increased due to our robust leasing activity in the Q1 when we spent almost $41,000,000 on new leases.

Speaker 4

LOE is now expected to average $0.22 to $0.26 in the Q2 and the full year, while our GTC costs are expected to Be between $0.32 $0.36 per unit, both in the Q2 and the full year. Production and ad valorem taxes are now expected to average $0.12 to $0.16 in the 2nd quarter and $0.14 to $0.18 for the full year, primarily related to the impact of lower gas prices on production taxes. DD and A rate remains unchanged Between the $0.95 to $1.05 range, our cash G and A is still expected to total $7,000,000 to $9,000,000 in the quarter $32,000,000 to $36,000,000 for the year, while the non cash G and A continues to be about $2,000,000 per quarter. Cash interest expense is expected to be $34,000,000 to $36,000,000 in the 2nd quarter and $150,000,000 to $155,000,000 for the year. While our effective tax rate remains unchanged in the 22% to 25%, we now expect to be able to defer 95% to 100% of our reported tax This year primarily related to the lower commodity prices and as well as our activity level.

Speaker 4

We'll now turn the call back over to the operator to answer questions from analysts who follow the company. Valerie?

Operator

Thank

Speaker 5

you.

Operator

Our first question comes from the line of Derrick Whitfield of Stifel. Your line is open.

Speaker 6

Thanks and good morning all. Good morning. Before asking my questions, let me express that I understand the challenge of managing a business in the current environment. And Really, with that said, I wanted to ask if you could place some parameters around the potential flex in your capital program for 2023, Understanding that that decision is price dependent and there is a service cost feedback loop. What does a 5 to 10 well completion deferral due to your second half production and free cash flow profile.

Speaker 6

And is that a reasonable toggle if we see gas prices down in the $1.50 range?

Speaker 2

Yes. Derek, that's a good question. I mean, yes, I think that Yes, that's something we certainly can look at as kind of as delaying completions, especially if we see continued weakness in gas prices kind of Stretching beyond the Q2. Obviously, we have I think our production, which is still kind of forecast It grows year over year, especially compared to last year, kind of at the as you saw in the Q1, that it would just kind of flatten out. So it depends on how quickly we put that in place and when we resume completions again.

Speaker 2

So most of the activity that's going to affect this year, you'd have to kind of put that in place pretty early. Otherwise, you're really going to be affecting next year's production levels.

Speaker 6

Terrific. And Roland, perhaps staying with you, with the understanding, again, that it's a delicate balance between your near and long term priorities and it's not Holly was in your control on the macro side. What degree of leverage are you comfortable operating with knowing that it will likely inflect much lower And the following 4 quarters based on contango. And separately, how do you think the banks would likely view that scenario?

Speaker 2

Well, the company has such strong liquidity now and a great balance sheet kind of created by last year's Debt pay downs. So, I still think we're based on the current gas prices and all that, I mean, We may go backwards a step or 2, but nothing to create any kind of concern for the banks. I mean, we have a significant Borrowing base, it was just redetermined that's even beyond the commitment we have from them. So I don't see any Significant real deterioration in the balance sheet even if we don't change any of our plans. So yes, it's really as you look ahead to next year, do you have an environment that is weak next year or Is it going to kind of get back into the range what the futures prices are saying?

Speaker 2

Next year you've got Gas closer to $350,000,000 So it's really a short term phenomena. And so we recognize that and We'll continue to manage it very proactively. You saw this quarter you have kind of the convergence of Yes, low gas prices and high service cost, high cost created from last year's high prices, We do start to see be able to mitigate the cost side and get back into potentially if prices stay longer For a longer period, we would expect the cost structure to come back down to where the strength of the company has always been and we have the lowest operating cost structure in the Great. And we are still very profitable even with these low gas prices. Our breakeven cost is Almost $0.50 per Mcf lower than our peers, our gas our public gas peers.

Speaker 2

So that strength Will be part of the things that help the company handle the times that we're in now. And we've obviously had Lots of experience doing that in the past.

Speaker 1

And I think our my initial comment would be we run the strip for The second half of twenty twenty three, all of twenty twenty four. And as Roland said, the gas prices, they look pretty favorable, particularly with our cost structure. So our outlook on natural gas is extremely positive. We've looked at maybe looking into non operated properties. How can we lower that commitment?

Speaker 1

We also really on a weekly basis, almost on a daily basis, look at hedging. We haven't put any hedges in, into 2024, but we look at that. We look at that weekly. That's like we did in December of 2022. We put 25 percent callers in the second half of twenty twenty three.

Speaker 1

We added those. So I think you as a stakeholder Need to know that we think we do take a look at that. We do think there's going to be some cost deflation in the future. They've kind of run up on us and Our gas prices are dropped. So you are at that inflection point where there's a little bit more pain.

Speaker 1

But what overrides all that is The fact that our 470,000 net Haynesville Acres are within several 100 miles of the Gulf corridor where 95% of all the LNG shippers are building their export facilities. So we look at that and we look at the results that we've had in our new play. And that's why we want to be very transparent in that we've got a little different business plan than most. Most of these companies maybe have issues with inventory, we don't. Some of them have degradation issues, we don't.

Speaker 1

And most of them you have to your option is to acquire a rival for M and A. We're not looking to do that either. So it is a little different coloring book, a little different playbook and we want to make sure that those that support it Know what they're supporting. I think it's based upon good judgment and it's based upon the need for natural gas globally Around the world in the future.

Speaker 6

Thanks, guys. And I know we're really solvent for 3 to 6 months and that the outlook is quite constructive. So certainly, thank you for taking the more difficult questions.

Speaker 1

Thank you. Great question.

Operator

Thank you. One moment please. Our next question comes from the line of Jake Roberts of TPHO. Your line is open.

Speaker 7

Good morning, guys.

Speaker 8

Good morning.

Speaker 5

I was

Speaker 7

hoping to hear more about the leasing program process in the Western Haynesville. In particular, how competitive has it been, maybe the size and scale of some of the deals you've done? And then perhaps thoughts on when you guys might be able Provide an acreage map and things like that to the market?

Speaker 1

Well, we said at the very beginning that we started leasing there 3 years ago. We've been very cautious on what we've been doing at the drill bit and we've moved rigs on and off, on and off based upon the performance. We said at the very onset that it was a very beginning. So take a look at it quarter by quarter by quarter. And all that we can tell you now is that it did tell us to put a second rig there.

Speaker 1

It didn't tell us to put a 3rd, 4th, 5th rig there. It tells us Put a second one there. We've looked at the performance, which has been a little sporadic because of the takeaway facility, But the Circle M has been stellar. I think the second well looks really strong. The third well, we Just copied it, connected to sales only as of last month.

Speaker 1

And then we're completing a well right now. We're waiting to complete 5th well and we're drilling 2 more. So, we have great hopes for it, but like all of these plays, You've got to be cautious and I think that's where we tell you that we took majority of our dollars last year and we paid down our debt See at our balance sheet pristine and then we looked at our long term debt that's not due till 20 9 at 10, 20, 30 and that's at 5.7 8 6.75 debt. Then we looked at the amount of money that we had and you noticed all the footprint that we owned in the Western Haynesville. I mean, It was paid for out of cash flow.

Speaker 1

And the wells that we're drilling, we think that they should be drilled. And we have really great expectations, which we should, but we'll see how this progresses. And I think by year end, we'll have leased What we think is leasable at a very low cost, which I think that's the right price for the leases right now. But we want to make sure that that is where we're looking. But we're looking there cautiously And we're keeping you updated quarterly.

Speaker 7

Great. Appreciate that. And then maybe if we could circle back to some of the prepared remarks On the longer term LNG potential, I'm just curious, what is perhaps the ideal structure you guys are after in those longer term contracts And just how those discussions have been going? Thank you.

Speaker 2

Yes. Obviously, that for us the ideal structure is to have a long term market That's the highest possible gas price that we can achieve and have certainty of markets and then Certainly apprised. So, yes, I think that we expect to be able to do Some big things in that area this year and I think Western Haynesville hopefully plays a role in that and we already are a big supplier. We have done some 10 year contracts and I think that as we could free up more gas that we're currently producing from Their commitments, we continue to want to tie ourselves to the LNG shippers that are kind of driving The gas demand.

Speaker 1

When you know we look natural gas is a precious fossil fuel. If you've got $100,000,000,000 that you're spending for LNG exporters, you need that precious gas. And if you can get it, All the narratives will tell you that they'd really like to get it from the Haynesville. You're really not going to get majority of it from Appalachia nor the Permian in opinion and in their opinion. So if you could get it from the HaynesvilleBossier, that's where you would rather get it.

Speaker 1

So, we do treat it as the precious commodity and we try to de risk this Western Haynesville Because they're really looking for commitments, not for 2027, but for 2,047. Who has the inventory That they can do business with, that's predictable, that's got the balance sheet and the management capability to deliver what They need and we need over decades. That is our longer term view of what we're doing with the company.

Speaker 7

Thank you very much. Appreciate the time, guys.

Operator

Thank you. One moment, please. Our next question comes from the line of Bertrand Donis of Truist. Your line is open.

Speaker 9

Hey, good morning guys. You added the well in the Western Haynesville and results in the top quartile of your results, but It's still a little bit below that Casey Blackwell. Was there anything geologically different between the two wells? Or is that the Casey Blackwell just too high of a watermark to use as a comparison?

Speaker 3

Yes, this is Dan. So we you're right, we did we tested we IP ed the Casey Black Will at 42,000,000 a day. We the lateral length, the Circle M and the Casey Black had equivalent lateral lengths of just under 8,000 foot. We're really longer on this Campbell well. But we the Campbell well looks really good.

Speaker 3

We're just trying to be real conservative on managing the drawdown. We certainly could have IP ed this Campbell well a lot higher. We just chose not to. We opted on a smaller choke. It's got really low drawdown.

Speaker 3

And so we just we basically want to Produce the well at this rate. We got the Circle M is still flowing at $30,000,000 We had it shut in for about 35 days for an offset frac here Recently and just getting it back up to pace and then the Casey Blackwells It's flowing between $25,000,000 $30,000,000 a day and then we're going to flow this Campbell at $36,000,000 and just manage the drawdown.

Speaker 9

Okay, great. And then maybe I missed it. How many remaining inventory do you have in the Western Haynesville? Have you guys outlined that yet? Or what are you thinking there?

Speaker 9

And just how many wells are coming on this year as well?

Speaker 1

No. We've just said that we'll drill 14 total Western Haynesville wells by year end And probably have 8 or 9 of those connected to sales. So that we haven't given any inventory All that's a little premature right now.

Speaker 9

Okay. That sounds good. And then just shifting gears on the I want to follow-up on the LNG comments. You said you're trying to get the best gas price possible. There's been 2 approaches, whether you want kind of a Henry Hub Ship Channel premium or do you want to deduct to the international pricing?

Speaker 9

And I just wasn't sure if you guys, how you viewed the I'm sure you can get a higher price now, but it would come with some risk. So I just want to dissect that answer.

Speaker 2

Yes. We're still Evaluating that, I think if you look at being a major supplier to the at least the LNG shippers we're talking 80% -plus of their business is tied to NYMEX. And so they need they're going to have to have their supply tied to NYMEX. And if you want to sell to them, if we want to buy processing capacity and sell in the international markets, that's an option So all of those are being explored and partnerships with one particular large one is kind of being explored. We're also like We could partner in the transport of the gas together versus evolving other midstream companies that are Having high tariffs to move your gas to the Gulf.

Speaker 2

So I think it's kind of all the above. I mean, the main thing we're focused on, Let's make sure we're getting the absolute like a premium NYMEX gas contract with low transport To the golf and then if we want to explore participating in other markets, other indexes, that's certainly a possibility too.

Speaker 1

And you have a better chance of doing that if you can prove that you have the quantity over the decades that everybody needs. And that's again, that's what we're advertising today is that we're going to stay the course, we're going to manage our balance sheet, We're going to try to derisk some inventory for the future. And at the same time, we'll give you the results of the Campbell, which It's interesting that you put out an IP number and you produce it at that same number. Over the 36 years I've been in this business. Most people IP it at 3 times what they produce it at.

Speaker 1

So it's a little different norm what we're doing here.

Speaker 5

Yes. I

Speaker 2

would say the Campbell is probably the strongest well potential right now. And so it may be producing at the highest level of the 3. So IPs are just a one day kind of number.

Speaker 3

Yes. And I'll just reiterate that the wells are obviously capable of flowing at higher rates. They got great pressures. The drawdown looks superb. Drawdown is much better than the drawdowns we see in our core East Texas, North Louisiana area.

Speaker 3

So we're just we're managing the wells for longevity For maximum value.

Speaker 1

We put the asterisk on it, so you don't know how many more Campbell wells are out there. You don't know the footprint And it's going to take a long time to derisk this. That's why we've taken the long road to do this, the slow road to do it.

Speaker 9

That's great color guys. And then just the second part of that LNG was what about term? Are you scared of a 20 year commitment or what's the limit to that? And that's all I got. Thank you.

Speaker 2

No, we're not. I think we definitely have done 10 years. And so I think given our long inventory life is a big advantage we have over a lot of the other potential Haynesville suppliers. And I think To the extent that we like the contract and want to be a long term partner, that's something we're comfortable with. So I think that will be the trend of the future.

Speaker 2

We'll be continuing to want to have we want to Get a lot more of our gas sold direct to the end users, whether LNG or whether power generators Or chemical, other type of industrial users along the Gulf Coast and be a long term reliable supplier of those And capture the highest price possible by being able to be direct connected to them.

Speaker 1

And I would make a kind of global comment that if you look at our major stockholder, the Jerry Jones family, He converted his preferred into common in November. He gets a dividend like everybody else and he gets equity Appreciation like everybody else. And he has a total of about $1,100,000,000 invested in the company. Because of that backstop, We're able to maneuver the way we're maneuvering today and we're taking the longer term view and we're showing you how Precious we think natural gas is and how attractive we're trying to be for LNG shippers. So that is that's a little different nuance that we have and why we have it.

Speaker 1

But also you have to look at the judgment calls that we make And see whether they've been good the last 15, 18 months, 2 years. And I think they've been pretty good. But we do want everybody to know that we do read all the analyst reports and we're with you. And we try to make changes when we need to like the 2 rigs that we got I've read before anybody had a conference call last time, we got rid of those. So we want to advertise that we are we will toggle things around To make sure that, one, we always protect the balance sheet.

Operator

Thank you. One moment please. Our next question comes from the line of Charles Meade of Johnson Rice, your line is open.

Speaker 10

Good morning, Jay and Roland and to the rest of Comstock team there.

Speaker 1

Hello, Charles. Jay, I want

Speaker 10

to ask a question about these upcoming Western Haynesville wells. My understanding is one of these up to upcoming 2 wells is going to test the deeper part of the section, actually the Haynesville As opposed to the I guess the previous 4 would all be Bossier Wells. And My understanding is you guys have a lot of vertical cores and logs through the section. What, If anything, should we be looking for that might be different from this Haynesville test? And are there any things that you, in particular, Are looking for would alert us to about whether it's higher pressure, more difficult drilling, just any your thoughts about what could be different there?

Speaker 3

Hi, Charles. This is Dan. I'll try to answer your questions. So we have everything that we have put on so far Have been Bossier wells, the 3 producers. We do have one that's fracking right now.

Speaker 3

There's also another Bossier. And but well that is waiting on completion was drilled as a Haynesville. We'll be starting to frac that well late next Late this month, I should say, late May and turning into sales probably early July. But that the reason we drilled the first wells is Bossier's. We're simply we just looked at was trying to give ourselves the best chance of success because obviously, as you know, these wells are deeper, the temperatures Or much warmer.

Speaker 3

But we've been pretty pleased with the progress we've made in a short period of time drilling just a few wells. So we just basically look at where the sticks are, where we're going to be drilling. We look at the DVDs. We look at what we think the temperatures are going to be. And then we just decide which one of the targets we need to pursue.

Speaker 3

So and there's a part of the field over where the Campbell is that's kind of down on the very Our south southwest end of our acreage for geological reasons, we only want to drill Bossier's there. But For the rest of the play, we kind of the Haynesville is our primary target. The Haynesville is the better rock Based on all the work that's been done in the play and that's we do expect superior results from our Haynesville completion.

Speaker 1

The other thing, Charles, if you look at the competitive advantage, Remember, in 2022, we bought the Pinnacle plant and then the 145 mile line. If We can drill these wells close to the Pinnacle line if they need to be drilled there. And we're going to save a lot of money On gathering costs. So we're going to have a competitive advantage there, which you don't put in the cost structure till you do it. But Some of the next wells we drill will go into our line that we own that has probably $300,000,000 of capacity More or less.

Speaker 1

So you don't think about that when we talk about the cost structure, but you look at the Western Haynesville and where we're producing that. Even if we produce the 5 wells and call it equipped, I mean, it would still be a very good play for us as far as dollars in, dollars out and reserves added.

Speaker 3

That is all helpful detail. That's it

Speaker 10

for me. Thank you, Jack.

Speaker 1

Thanks, Charles. Appreciate you.

Operator

Thank you. One moment please. Our next question comes from the line of Philip Johnston of Capital One Securities. Your line is open.

Speaker 11

Hey, guys. Thank you. Just to follow-up on some of the factors that are coming into play around Managing your activity levels. I wanted to ask about single well economics in your traditional Haynesville play. Just curious as to what you estimate the current breakeven flat gas prices at current well costs in order to Generate a NPV breakeven.

Speaker 11

The last time I ran that analysis a few months ago, I came up with roughly 250 flat. Does that sound about right to you guys?

Speaker 2

Well, we think it's a bit lower than that for Comstock. I I think that we're closer to 210 to 215 really depends on what area are we Drilling, what's the transportation cost because when you're talking about lower if you're talking about getting closer to breakeven, if you have a $0.15 transportation costs or $0.35 it really makes a difference. So I think what last year with the High gas prices and the huge margins, dollars 0.10 or difference in transportation costs, really was a rounding error And returns, but now it kind of comes back into focus. And I think that's one thing we shift back to the areas that have the lower cost structure And you'll see even our gathering rates crept up on it because we drilled in these other areas last year with a high gas price that have higher transportation. We can lean back in, in our inventory on the areas of lower transportation.

Speaker 2

So our very best stuff, we can probably get that breakeven level down to it's Much closer to where the current monthly price is now. But if we stray way out to other parts of Our large footprint in the Haynesville, it can be $0.30 difference and a lot of it is just the transportation. Some of it's EUR, Some of it is some areas cost. They're a little bit more expensive to drill certain parts of the Haynesville because they're deeper And some are easier. So I think now you can lean into, you go to your very top players now.

Speaker 2

And I think that's kind of like what we did in 2020 is kind of one thing you can shift to kind of overall improve get to your best wells that can hit that are Making money in this environment.

Speaker 11

Okay, great. That was really helpful. Thanks for that. And just I guess in terms of what might trigger you guys to drop an incremental rig or 2, I'm guessing it would just be sort of a Matter of seeing that 24 strip price move significantly lower, but probably not as low as that sort of breakeven price that you were referring to.

Speaker 2

Right. I think you obviously, if you look at really the reality is a lot of the wells that we're going to be drilling in the second half of the year are not going to even participate in this year's Prices and to the extent that you don't have a good outlook post this summer and Yes. Going into next year, yes, that obviously changes maybe how you're drilling your inventory. But I do think the big shift is like we need to drill our Low cost our lowest cost kind of projects and that's easier to do now that we reduced the rig count and pulled in the activity And really just kind of put the others back on hold until gas prices are strong again and then we can drill some of those areas like we did last year, Just to keep all parts of the inventory kind of moving. And frankly, the Western Haynesville, you say, how does that those come into play?

Speaker 2

But those are single wells, so they're not the pad drilling, which is a big, big cost saver. So we still like to drill 2 to 3 wells On a pad because of the zipper frac capability and all that. But the Haynesville well, yes, based on that, they actually can compete, Believe it or not, with the top our top low cost wells, especially when we get them on our gathering system and we save that transportation cost That we right now are the first wells are dedicated to a more higher cost system. But if you look at the overall longer term activity out there, A lot of it will be where we control the transportation cost and the Pinnacle system that Jay referenced.

Speaker 11

Okay, great. Thanks, Roland.

Speaker 1

Thank you.

Operator

Thank you. One moment, please. Our next question comes from the line of Umang Chaudhry of Goldman Sachs. Your line is open.

Speaker 8

Hi, good morning and thank you for taking my questions.

Speaker 1

Yes, sir.

Speaker 8

My first question was on Activity levels in the Haynesville, would love any color you can provide on any incremental Haynesville rig of crude reductions, Which you are expecting based on your conversations with other operators in the basin.

Speaker 1

Ron, what's the rig count, Rodnaus? The rig count according

Speaker 5

to,

Speaker 4

Enverus is in the upper 50s to 60, And that's down from a peak of about 70. Between us, Chesapeake and Southwestern, that's 5 or 6 rigs that we've Communicated to The Street that those 3 companies would be dropping. You've had some of the larger privates That have already reduced the number of rigs and I think there's more to go. So when you think about starting point of 70 rigs, I think it's somewhat you will end up seeing at least 15 maybe closer to 20 rigs being dropped between The 3 primary public operators and the private operators in the area. In terms of completion crews, I know a couple of companies have talked about potentially reducing or removing a completion crew At some point later this year, I haven't heard very much about from Private operators activity, but given the amount of rigs that the privates are dropping, it would surprise me if you don't see some of The completion count, our crew the frac fleet count go down related to private activity as well, especially since those are the type of companies That do drill directly out of cash flow.

Speaker 8

All right. That's really helpful. Thank you. I guess, I'm probably acknowledging that it's probably way too early to talk about this. But given your deep inventory and your proximity to LNG markets and your Outlook on natural gas.

Speaker 8

As we look at the strip today and assuming that holds, especially in the back half of twenty twenty four and heading into 2025, When would you like to add activity to grow into those kind of prices as you look out to next year?

Speaker 2

Well, I think that we're not thinking that we can really predict the future gas prices or be super comfortable with even what the futures market shows. So I don't think that we're at all trying to time growing activity into that or trying to guess. I think what we are our priority is to which we think is the most important part is to kind of continue to delineate and prove up And get real grasp over the type curve and the productivity of our new play. And I think over this period of time before Demand is needed. That's real critical.

Speaker 2

That way they can rely on that source and then we can develop that source based on that new market. And so that's what we see as the big priority. And then what we call the traditional Haynesville, which is our other areas, Those are the areas that we're toggling because that's just that we don't have to develop that inventory in any particular time. It's a deep inventory. We can go to different parts like we said to get kind of improve the economics, but that's more just to generate the cash flow to Keep the company in great shape.

Speaker 2

So there's really 2 different kind of 2 different priorities there that we're balancing in this market.

Speaker 1

Well, as we said earlier, the United States should be the biggest beneficiary of the invasion by Moscow into Ukraine. Why? Because of our abundant natural gas and our LNG export capability. We at Comstock want to make sure we provide our fair share Natural gas to Europe, to Japan, wherever it needs to go.

Speaker 8

That's helpful. Thank you so much for taking my questions.

Operator

Thank you. One moment please. Our next question comes from the line of Paul Diamond of Citi. Your line is open.

Speaker 12

Hi. Thank you. Good morning. Thanks for taking my call. Just wanted to touch base on kind of H2 Two cost structures.

Speaker 12

I know the with the new Titan asset coming online, we would expect a bit more utilization there. Just kind of curious how you guys Saw that running through in H2, given you included 20% or so in Q1 versus like 50% or so in Q4 of last year.

Speaker 2

Yes, second half. I think that's as we get the Titan in, there's a Pretty much as we've tracked and measured it against our conventional diesel fleets. It's almost given us a 15% consistent savings On the completion cost, which is the largest part of the cost of the well. And so we're excited about that, about having that be a real driver to not only to help us score lower emissions This year and next year in 2024, but also just the cost savings that it provides and it's an ideal Location for it in the Haynesville because we have such an abundant gas supply that is drilling around. So we've been very happy with the first one.

Speaker 2

So That but that's kind of whether the second one comes in on time is probably the big question. But hopefully And working sometime in the second half, definitely by the Q4, then you'll see a lot of our completions at a lower cost. And we'll swap out some rigs with lower drilling rates too that were so there are some positives on the horizon for later this year to see Some well cost savings there, but I think they're mostly lucky the earliest you start seeing those is second half versus 2nd quarter.

Speaker 12

Okay, understood. Thanks for the clarity. And just one quick follow-up on the macro. Yes, you're currently selling 21 Sent into LNG. Just kind of want to get my head around where you thought that idea level would be on the longer term?

Speaker 2

Yes, probably closer to 50%. I think we want to be I think we especially A lot of it will depend on our new area, but that's probably some of our best highest realizations right now is on our 10 year contract now that we're doing. So as we seek to maximize our gas price, that market and potentially Other markets that are industrial users, power generators, to the extent that they're competitive or beat those rates, we'll Also want to add that to our portfolio. But yes, we would like to see working our way toward over 50% plus And that probably is more 25, 26 when all the a lot of new capacity comes on. And then a lot of Our other commitments maybe roll off.

Speaker 12

Understood. Thanks for your time.

Speaker 1

Thank you.

Operator

Thank you. One moment please. Our next question comes from the line of Leo Mariani of ROTH. Your line is open.

Speaker 5

Thanks. I just wanted to follow-up briefly on the Western Haynesville here. You guys talked about these wells, Even though it's early days having kind of competitive returns with the Eastern, can you kind of help us out there a little bit? I mean, just in terms of With the kind of parameters there, I mean, are you seeing kind of maybe twice the EURs or something on these wells? Because my understanding is maybe they're roughly twice the costs early on at this Point in time, just trying to handle on sort of drill times and maybe what you think the early EURs are per foot on

Speaker 3

a couple of wells.

Speaker 2

That's a good way to frame it because we said basically that kind of a that's what that in order to make them competitive with the other wells, Yes. You'll want twice the EUR. And yes, but I think the cost is early cost. So I think the future cost, the development cost will be significantly better. I mean, if we drill single wells in our traditional Haynesville, they will be our most costly wells because Yes.

Speaker 2

That's why pad drilling is such a big important part of everybody's development plan now because the cost savings is so significant. So that's for the future of this play, but then also just perfecting the drilling and completion will be the other part of getting the cost up. But generally, even out of the gate, we're not starting out in a bad position.

Speaker 1

That's actually, again, we're on the cutting edge Technology, we started doing it and now we've been pretty successful with the wells that we've turned to sales and completing and drilling. So as this kind of unfolds through 2023, 2024, then we can be give you a little more clarity on it.

Speaker 5

Yes. Okay. And then just wanted to kind of ask a little bit around sort of production cadence And CapEx cadence as we move into the second half, obviously, you've got Q1 behind you, you've got the Q2 guidance out there. So Kind of flat on production in Q2. So do we see like sequential growth in both 3Q and 4Q, assuming your plans don't change?

Speaker 5

And Conversely, do we see CapEx kind of dropping in both 3Q and 4Q from 2Q levels? So trying to kind of get a handle on those kind of moving parts.

Speaker 4

Well, clearly, since we had 9 rigs for most of the Q1 and we're dropping down to 7 over the course of the Q2, the Q1 was going to be the highest CapEx Great. The Q2, you have our guidance. And your 3rd and 4th quarters, will probably be pretty similar because we'll be down to the 7 rig By the end of the Q2 and that's probably the way I would think about CapEx cadence. From a production standpoint, you're right. There is some sequential growth In both the 3rd and 4th quarters to get to that full year production guidance and A lot of that is related to if you think about the impact of the timing of completions in the Western Haynesville where going forward with 2 rigs there, we'll have And a 2 completions every quarter or so and those come on at Pretty high rates and flatter production profile.

Speaker 4

So your thoughts were correct.

Speaker 5

Okay. But then just to clarify though on the CapEx, Q3 and Q4 pretty similar, but you think down versus kind of where 2nd quarter shakes out a little bit just because of the activity reduction?

Speaker 8

Yes.

Speaker 5

Okay. Yes. All right. That's helpful. And then I guess just a question just around cash taxes.

Speaker 5

Obviously, you took your guidance down to call it fairly de minimis As a percentage of actual taxes in 2023, if we look at next year, like you said, dollars 3.50 is roughly the futures price at this point. Do you see cash taxes up significantly next year? Any kind of ballpark in terms of what percentage of total taxes will be cash in 2024 based on what you see today?

Speaker 4

We're still evaluating that. I think if you end up with a 3.50 gas price, then there's a chance The cash or the deferral rate goes back down. I don't know if it goes all the way down to the 75% to 80%, But it will continue to it will go back down as gas prices move up. This year clearly Is impacted by the such low gas price. But if you want to just conservatively go back to that 75% to 80% deferred next year and we'll just going to have to revisit that as we get closer to the year in terms of gas pricing

Operator

Thank you. This does conclude the conference for today. I'd like to turn the call back over to Jay Allison for any closing remarks.

Speaker 1

Sure. We all know that time is a valuable commodity and We want to thank each one of you for giving us an hour and 10 minutes of your time. We're going to be good stewards of the capital that we have And the future looks bright here. So thank you for your time.

Operator

Thank you. Ladies and gentlemen, this does conclude today's conference. Thank you all for participating. You may now disconnect.

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Earnings Conference Call
Comstock Resources Q1 2023
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