Q1 2023 Comstock Resources Inc Earnings Call
Speaker 2: Thank you for standing by and welcome to the Comstock Resources first quarter 2023 earnings conference call. At this time, all participants are on a listen-only mode. After the speakers' presentations, there will be a question and answer session. To ask a question at that time, please press star 11 on your telephone. This is reminding us today's call is being recorded.
Speaker 2: I will now turn the conference to your host, Mr. Jay Allison, Chairman and CEO . Please go ahead. Perfect. Thank you and good morning, everyone.
Speaker 3: I'd like to welcome all of you to the Comstock Resources first 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 and downloading it.
Speaker 3: The quarterly results presentation. Here you'll find a presentation entitled, First Quarter 2023 Results. I have Jay Allison, Chief Executive Officer of CopsHawk with me as Roland Burns, our President and Chief Financial Officer. Dan Harrison, our Chief Operating Officer, and Ron Mills, our VP of Finance and Best Relations.
Speaker 3: If you'll flip over to slide two, please refer to slide two in our presentation to note that our discussions today will include forward-looking statements within the meeting 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.
Speaker 3: If you'll step over to slide three.
Speaker 3: I want to kind of a
Speaker 3: address the issues. You know, I've read, I think, all of the analyst reports that have been published.
Speaker 3: and understand the concerns.
Speaker 3: None are of new concerns. We understand them. If you look at where oil is today plus yesterday, it's down $7. I think where natural gas is yesterday and today is down $0.20.
Speaker 3: So, you know, we all know that we're experiencing pressure with low natural gas prices currently in the short term.
Speaker 3: However, we're extremely positive on the outlook for natural gas in the future.
Speaker 3: Looking ahead several years we recognize the growing need for natural gas around the world.
Speaker 3: Our long-term goal is to be a significant supplier to the growing LNG market that is developing several hundred miles from our Haynesville Shill operations, including our emerging Western Haynesville area. Around the world today...
Speaker 3: Over a trillion dollars of natural gas infrastructure is being built. Over the next five years in the United States, we see more than 100 billion dollars worth of new LNG plants being operational. We're currently in discussions to enter into long term contracts with major LNG shippers who are following our new plague with significant interest.
Speaker 3: 14 drilled wells by year-end 2023. We also plan to wrap up our leasing efforts that we started almost three years ago. In the first quarter, we made great strides by materially adding to our acreage position as you've noted.
Speaker 3: The well results in our traditional hang fill area where we had six to seven rigs running continue to be very solid. Now we'll be down to five rigs in the next couple of weeks. The first quarter still has some inflation baked into the well cost, but we see that abating in the next several quarters.
Speaker 3: We're continuing to re-evaluate our rig count in our traditional Haynesville area, as well as our completion timing, to be responsive to the weak price environment we're in, as we're very focused on maintaining the strong balance sheet that we've worked so hard to create last year.
Speaker 3: 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.
Speaker 3: We'll monitor our plan to delineate our Western Haynesville plate. We'll adjust it based upon the results that we achieve. We'll continue to prioritize our longer term goals while being very proactive to protect our strong balance sheet, which is allowing us to whether the current short term headwinds we see.
Speaker 3: If you go to slide 3, we'll include some of the first quarter highlights.
Speaker 3: Our production increased 11% to 1.4 billion cubic feet of gas equivalent per day. We had oil and gas sales of $390 million. And operating gas flow were $255 million, or 92 cents per diluted shear. Adjusted EBITDAX for the quarter was $293 million.
Speaker 3: Our adjusted net income for the first quarter was $92 million, or 33 cents per share. The financial results in the quarter reflect the weaker natural gas prices following the warm winter weather that we had. In the first quarter, we drilled 18, or 13.7 net operated gas prices.
Speaker 3: Haynesville and Bossier horizontal wells, which had an average lateral length of 12,075 feet.
Speaker 3: We also announced our third successful exploratory well at our western Haynesville play, the Campbell Well, which had an initial production rate of 36 million cubic feet per day, which is a rate that we expect to produce it at. We had an active quarter requiring additional acreage in our western Haynesville play. So now I'll turn it over to Roland to discuss the financial results. Roland. Thanks Jay. On slide four, we cover a quick summary of our financial results that we reported for the first quarter. As Jay said, our production in the first quarter increased 11% to 1.4 BCF per day as compared to the first quarter of 2022.
Speaker 3: Oil and gas sales in the quarter, including hedging gains, decreased by 4% to 390 million, as lower natural gas prices offset the production growth that we had in the quarter. Our EBITDAX decreased by 12% to 293 million, and we generated 255 million of cash flow during the quarter.
Speaker 3: 14% less than 2022's first quarter.
Speaker 3: We reported adjusted net income $92 million for the first quarter, and our earnings per share came in at 33 cents as compared to 51 cents in the first quarter of 2022.
Speaker 3: On slide five, we provide a breakdown of our natural gas price realizations.
Speaker 3: the quarter. During the first quarter, the quarterly NYMEX settlement price, which averaged $3.42, was substantially higher than the average Henry Hebb spot price in the daily market of $2.67.
Speaker 3: 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.
Speaker 3: So the estimated NYMEX reference price for our sales in the first quarter would have been $3.29.
Speaker 3: I realize gas price during the first quarter averaged $2.98, reflecting a 31-cent differential to the reference price.
Speaker 3: That differential was higher than our normal for us due to the continued weaker Houston Ship Channel and KD Hub prices that persisted during a good bit of the first quarter due to the Freeport LNG facility shutdown.
Speaker 3: 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 are currently selling 21% of our gas directly to LNG shippers.
Speaker 3: In the first quarter we were also 53% hedged, which improved our realized gas price to $3.07.
Speaker 3: third-party gas.
Speaker 3: This generated about $9 million of profit and improved our gas price realization by another $0.07.
Speaker 3: On slide six, we detail our operating costs per MCFE and our EVA DAX margin. Our operating costs for MCFE averaged 83 cents in the first quarter, seven cents higher than our fourth quarter rate. The increased unit costs are related primarily to startup, the startup phase that we're having at our Western Hingsville area.
Speaker 3: where fixed costs are being spread over lower production volumes. We expect them to come down as our production grows in that area.
Speaker 3: Our gathering cost increased by four cents during the quarter, and our lifting cost increased by three cents.
Speaker 3: Our production taxes remain the same as we had in the fourth quarter.
Speaker 3: Our EBITDAX margin after hedging came in at 73% in the first quarter, down from the 82% we had in the fourth quarter, where we had substantially stronger gas prices. In slide 7, we recap our spending and our drilling and other development activity in the first quarter.
Speaker 3: During the quarter, we spent a total of $325 million on development activities, including $278 million spent on our operated Haynesville and Bossier shale drilling program.
Speaker 3: We also spent another $32 million on non-operated wells.
Speaker 3: Spending on other development activity, which includes installing production tubing, offset frack protection, and other workovers totaled $14 billion in the quarter. In the first quarter, we drilled 18 or 13.7 net to our interest operated horizontal Haynesville-Bocher wells.
Speaker 3: and we turned 19 wells or 11.6 net operated wells to cells.
Speaker 3: These wells had an average initial production rate of 24 million cubic feet per day.
Speaker 3: On slide 8, we recap our balance sheet at the end of the first quarter. We ended the quarter with no borrowings outstanding under our credit facility and with $2.2 billion in long-term debt. We ended the quarter with no borrowings outstanding under our credit facility and with $2.2 billion
Speaker 3: In April , the 17 banks in our bank group reaffirmed our $2 billion dollar borrowing base with $1.5 billion of electric commitments.
Speaker 3: Our revolving credit facility matures in 2027. So we ended the first quarter with financial liquidity of more than $1.5 billion.
Speaker 3: I now turn it over to Dan to discuss our operations in more detail. 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 four buckets. Our short lateral is up to 5,000 feet. Our medium lateral is about 2,000 feet.
Speaker 4: that run between.
Speaker 4: 5,000 and 8,000 feet. Our long laterals run from 8,000 to 11,000 feet and are recently created category of our extra long laterals for our wells that exceed 11,000 feet levels.
Speaker 4: Our total operated inventory currently stands at 1,810 gross locations, 1,364 net locations, which equates to a 75% average working interest on the operated inventory.
Speaker 4: A non-operated inventory, we have 1,310 gross locations and 182 net locations.
Speaker 4: which represents a 14% average working interest on our non-operated inventory.
Speaker 4: Based on the success of our recent extra long lateral wells, we continue to leverage our acreage position where possible to modify our drilling inventory and extend our future laterals specifically targeting the 10,000 to 15,000 foot range.
Speaker 4: In our extra long lateral bucket, we currently have 459 gross operated locations and 334 net operated locations.
Speaker 4: And to recap, to recap our gross operated inventory, we have 313 short laterals, 298 medium laterals, 740 long laterals.
Speaker 4: and the 459 extra long laterals.
Speaker 4: 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 8928 feet. This is slightly from our 8870 feet we had at the end of 2022.
In addition to the economic uplift, the longer laterals release our surface footprint and help us to reduce our greenhouse gas and methane intensity levels.
Based on our planned 2023 activity level, this inventory provides us with a 25-year runway of future drilling locations.
23 activity level, this inventory provides us with a 25-year runway of future drilling locations.
On slide 10, there's a chart. This outlines the average lateral length we've drilled by year.
During the first quarter, we turned 19 wells to cells with an average lateral length of 9,898 feet. The individual laterals ranged from 4,514 feet on the short end up to a 15,584 foot long lateral on the long end.
15 of the 19 wells we turned to sales during the quarter were our mince-march long lateral wells that are greater than 8,000 feet long.
Five of the wells were beyond 11,000-foot laterals. We had two little adders coming in longer than 15,000 feet.
Our record long lateral well still stands at 15,726 feet. This is on our East Texas acreage and that well was turned to sales during the fourth quarter of last year. Included in the group is the third well we recently completed on our Western Haynesville acreage, the Campbell-Dorsey-Dorsey. The first well was turned to sales during the fourth quarter of last year.
EOB number 2H well, which was completed in the Beaux-Gare 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. 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...
We had really good well performance again on this group of wells with the individual IP rates ranging from 13 million a day up to 37 million cubic feet a day with an average test rate of 23 million a day.
The average lateral length was 11,042 feet with individual laterals ranged from 4,514 feet up to 15,584 feet.
Included in this latest well activity are six 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 percent versus the dry gas well.
The average IP rate for a working interest ownership in the 15 wells for the corridor is 25 million a day, which is comparable to park orders even with the six 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 Campbells number two well.
which was completed in the Beaux-Arts with a 12,763 foot long lateral.
in the Bossier with the 12,763 foot long lateral. Let's turn to sales in March.
We tested the well with an IP rate of 36 million cubic feet a day, and we are currently flowing the well at this rate today and plan to produce the well at this same rate.
In addition, we are currently completing our fourth well on the acreage and have a fifth 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 two rigs on our western Haynesville acreage that is currently drilling our sixth and seventh wells. Slide 12 summarizes our DNC cost through the first quarter for our benchmark long ladder wells, which covers all our wells greater than 8,000 feet on our legacy core.
East Texas, North Louisiana, Acres position. 14 of the 19 wells returned to sales during the quarter were these benchmark long ladder wells in the first quarter.
Our DNC cost averaged $1,579 per foot.
which is an 11% increase compared to the fourth quarter and a 19% increase over our full year 2022 D&C costs.
Our first quarter drilling costs came in at $663 a foot.
which is a 14% increase compared to the fourth quarter. A majority of the drilling cost increase is attributable to a shorter average lateral length of this quarter versus the last, along with inflation, as most of the wells returned to sales were drilled in the third quarter and early fourth quarter.
Our first quarter completion costs came in at $916 a foot, which is a 9% increase compared to the fourth quarter. The primary contributor to our higher completion costs during the first quarter was the fact that only 20% of our first quarter well completions refract with our Titan Natural Gas Fleet.
as opposed to more than half of our fourth quarter wells per fracuse in the Titan natural gas fleet.
As mentioned on a previous call, 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 second Titan fleet within the next couple of months.
To sum up where we stand on activity levels, we are currently running eight rigs. One of these will be released in a couple of weeks to bring us down to seven rigs.
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%, which is a 16% improvement versus 2021.
We achieved those emissions improvements despite our turn to sales lateral feed increasing by 10% in 2022.
Adjusting for lateral length completed for our turn to sales wells. Our greenhouse gas emissions per lateral foot turned to sales.
Improved 10% while our methane emissions per lateral foot turned to cells 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 gases responsibly sourced. A natural gas powered frac fleet eliminated approximately 5 million gallons of diesel by utilizing natural gas, offsetting approximately 10,200 metric tons of CO2 equivalent.
As a reminder, our first natural gas part frack fleet began operating in April , so that data reflects just nine months of contribution to our 2022 numbers.
With our second natural gas-fired fleet arriving in the field by the end of the second quarter, we should see continued reductions in our emissions.
Our dual fuel drilling rigs eliminated approximately 0.6 million gallons of diesel by utilizing natural gas which offset approximately 1,900 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. Thank you, Dan. And I believe that we're the first Haynesville Bossier company to have 100% of our natural gas certified by MIQ standards, which tells you that all the gas we produced is
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. You know, we will continue to de-risk and delineate our Western Ansel 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're 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 two rigs on our legacy hay footprint within the next couple of weeks, which we discussed at the last conference call, in order to pull our activity in response to this low natural gas prices.
In addition to evaluating additional changes to our rig count, we are looking at delaying some completions. We were focused on maintaining the strong balance sheet that we had created last year. Our industry-leading lowest cost structure provides acceptable drilling returns even at current natural gas prices.
as our cost structure is substantially lower than the other public natural gas producers. We do plan to retain the quarterly dividend of that 12.5 cents for common share. Lastly, we'll continue to maintain our very strong financial liquidity as Roland reported on.
which totaled more than $1.5 billion at the end of the first quarter. I'll turn it over to Ron now for specific guidance for the rest of the year. Ron? Thanks, Jay. On slide 15, we provided the financial guidance for 2023. Second quarter production guidance.
of 1.375 to 1.435 BCF a day is consistent with our prior commentary that the second quarter production should be similar to that of the first quarter. Full year guidance remains unchanged.
from our initial guidance for the year 1.425 to 1.55 BCFB per day. During the second quarter, we do plan to turn to sales between 11 and 14 net wells. As Jay mentioned, our 2023 wells, as Dan mentioned, will have an average lateral length of about 1.5 inches.
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.
Second quarter, DNC CapEx is $260 to $310 million, and the full year DNC CapEx remains unchanged at that $950 to $1.15 billion range. In terms of our infrastructure and other spending, we continue to budget $15 to $30 million in spending during the second quarter, and $75 to $125 million for
the full year. In addition to what we spend on the drilling program noted above, we now anticipate spending between $50 and $60 million this year on leasing activity. That number has increased due to our robust leasing activity in the first quarter when we spent almost $41 million on new leases.
LOE is now expected to average 22 to 26 cents in the second quarter and the full year, while our GTC costs are expected to.
be between 32 and 36 cents per unit, both in the second quarter and in the full year.
Production and ad valorem taxes are now expected to average 12 to 16 cents in the second quarter and 14 to 18 cents for the full year, primarily related to the impact of lower gas prices on production taxes.
DD&A rate remains unchanged between the $0.95 to $1.05 range.
Our cash DNA is still expected to total $7 to $9 million in the quarter and $32 to $36 million for the year, while the non-cash DNA continues to be about $2 million per quarter.
Cash interest expense expected to be $34 to $36 million in the second quarter and $150 to $155 million 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 taxes this year, primarily related to the lower commodity prices. And as well as our activity level, we'll now turn the call back over to the operator to answer questions from analysts.
your lines open.
Thanks, and good morning, all.
Good morning all. Good morning. Good morning. 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's a service cost feedback loop.
What does a five to 10 well completion deferral do to your second half production in free cash flow profile? And is that a reasonable toggle if we see gas prices down in the buck 50 range? Yeah, Derek, that's a good question. I mean, um,
Yeah, I think that that's something we certainly can look at as kind of as delaying completions, especially if we see continued weakness and gas prices kind of stretching beyond the second quarter. You know, and you know, obviously we have, you know, I think
our production, which is still kind of forecasted to grow some year over year, especially compared to last year, kind of the, as you saw in the first quarter, you know, 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.
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 know, you're really going to be affecting next year's production levels.
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 entirely within 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 four quarters based on Contango. And separately, how do you think the banks would likely view that scenario? Well, the companies, it has its strong liquidity now and the great balance sheet kind of created by last year's debt pay downs. So with that said, here is what we think method might be.
I still think based on the current gas prices and all that, we may go backwards a step or two, but nothing to create any kind of concern for the banks. We have a significant borrowing base that was just redetermined even beyond the commitment we have from them. Time finally came and emotions can be changed persist kicked in. Typically sometimes the fact that the reason why it would have made us wanna pets like
So I don't see any significant, real deterioration in the balance sheet, even if we don't change any of our plans. So yeah, it's really, as you look ahead to next year, do you have an environment that is weak next year or is it?
Is it going to kind of get back into the range with the futures prices are saying next year you've got you know you know gas closer to 350.
So it's really a short-term phenomena, you know, and so we recognize that and you know, we'll continue to manage it very proactively. You know, you saw this quarter you have kind of the convergence of 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 industry. And we're still very profitable even with these low gas prices. Our breakeven cost is almost 50 cents for MCF lower than our public gas peers.
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.
And I think our initial comment would be we, you know, we run the strip for the, you know, the 2nd, half of 23, all the 24.
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?
We also, you know, really on a weekly basis, almost on a daily basis, look at hedging.
You know, 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 22. We put, you know, 25% collars in the second half of 2023. We added those. So I think you as a stakeholder need to know that we do take looks 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 gas prices have dropped. So you are at that inflection point where there's a little bit more pain.
But what overrides all that is the fact that our 470,000 net angel acres are within several hundred 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 blade. And that's why we want to be very transparent in that we've got a little different business plan than most. You know most.
Most of these companies maybe have issues with inventory, we don't. Some of them have degradation issues, we don't. And most of them you have to, your option is to acquire a rival for M&A. We're not looking to do that either. So it is a little different coloring book, a little different play book.
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 and the future.
Thanks, guys. I know we're really solving for three to six months and that the outlook is quite constructive. So, certainly, thank you for taking the more difficult questions.
Thank you. Great question.
Thank you. Great question. Thank you. One moment, please.
Our next question comes from the line of Jake Roberts of TPHO. Your line is open. Good morning, guys.
Our next question comes from the line of Jake Roberts of TPHO. Your line is open. Good morning, guys. Good morning. Good morning.
I was 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 to provide an acreage map and things like that to the market.
Well, you know, we said at the very beginning that we started leasing there three 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 the 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. It didn't tell us to put a third, fourth, fifth rig there. It told us to 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 high-pitched it, connected to cells, only as of last month. And then we're completing a well right now. We're waiting to complete fifth well, and we're drilling two more.
And then we looked at our long term debt that's not due till 29 at 10, 20, 30. And that's at five and seven, eight, six and three quarters debt. Then we looked at the amount of money that we had. And you notice all the footprint that we own in the Western Haynesville. I mean, it was paid for out of cash flow.
and the wells that we're drilling, we think that they should be drilled. We have really great expectations, which we should, but we'll see how this progresses. 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 you know that. That is where we're looking. But we're looking there cautiously. And we're keeping you updated quarterly.
Great, appreciate that. And then maybe 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 in those longer term contracts, and just how those discussions have been going. Thank you. Yeah, obviously that, you know, for us the ideal structure is
year and I think you know that the 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 can free up more gas that we're currently producing from other commitments, we continue to want to power ourselves to the LNG shippers that are kind of driving.
have done some 10-year contracts and I think that as we can free up more gas that we're currently producing from other commitments, you know, we continue to want to power ourselves to the L&T shippers that are kind of driving, you know, the gas demand.
You're really not going to get the majority of it from Appalachia nor the Permian in our opinion and in their opinion. So if you could get it from the Haynes-Woolbozier, that's where you would rather get it.
So, you know, we do treat it as the precious commodity and we try to de-risk this western Gainesville because they're really looking for commitments not for 2027 but for 2047.
who has the inventory that they can do business with that's predictable, that's got the balance sheet and a 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.
has the inventory that they can do business with that's predictable, that's got the balance sheet and a 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. Thank you very much. Appreciate the time, guys.
Thank you. One moment, please. Our next question comes from the line of Bertrand Donnis of Truist. Your line is open. Hey, morning, guys. You added the well in the western Haynesville and, you know, a result in the top Datasuffering.
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 the Casey Blackwell just too high of a watermark to use as a comparison? Yeah, this is Dan. So you're right, we did. We IPed the Casey Blackwell at $42 million today.
The circle M and the Casey Blackhead equivalent lateral lengths of just under 8,000 foot, you know, we're really longer on this Campbell Well. But the Campbell Well looks really good. We're just trying to be real conservative on managing the drawdown. We certainly could have IP'd this Campbell Well a lot higher. We just chose not to. We IP'd it on a smaller choke.
It's got really low drawdown and so we just, you know, we basically want to produce the well, you know, at this rate. We got the Circle M is still flowing at 30 million. We had it shut in for about 35 days for an offset frack here recently and just getting it back up to pace and then, you know, the Casey Blackwells.
is flowing between 25 and 30 million a day, and then we're going to flow this Campbell at 36 and just manage the drawdown. Okay, great. And then maybe I missed the... How many...
How many remaining inventory do you have in the Western Haynesville? Have you guys outlined that yet, or what are you thinking there, and just how many wells were coming on this year as well?
No, we've just said that we'll drill 14 total western handful wells by year end and probably have 8 or 9 of those connected to cells.
So that, we haven't given any inventory. And all that's a little premature right now. 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, you know, gas price possible. You know, there's been two approaches, whether you want kind of a.
Henry Hub ship channel premium? Or do you want to deduct to the international pricing? And I just wasn't sure if you guys, how you viewed the two, you know, I'm sure, you know, you can get a higher price now, but it would come with some risk. So I just want to dissect that answer.
Yeah, we're still evaluating that. I think if you look at being a major supplier to at least the LNG shippers we're talking to, 80 plus percent of their business is tied to NYMEX and so 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 international markets, that's an option too. So all of those are being explored and partnerships with one particular large one is kind of being explored, where also we could partner in the transport of the gas together versus involving other midstream companies that are...
having high tariffs to move your gas to the Gulf. 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 NIMEX gas contract with low transport to the Gulf, and then if we want to explore participating in other markets, other indexes, you know, that's certainly a possibility too.
You know, 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 de-risk, you know, some inventory for the future. Thank you guys and this has been a animated panel of App of the Year 2017. We're not supposed to control our data andale. Then we'll share that with you afterwards.
And at the same time, you know, we'll give you the results of the Campbell, which is interesting that you put out an IP number and you produce it at that same number. You know, over the 36 years I've been in this business, most people IP it at three times what they produce it at. So it's a little different norm what we're doing here. Yeah, I'd say the Campbell is probably the same.
much better than the drawdowns we see in our core.
East Texas, North Louisiana area. So, you know, we're just.
We're managing the wells for longevity, for maximum value. We put the asterisks on it though.
You don't know how many more Campbell Wells are out there. You don't know the footprint and it's going to take It's going to take a long time to de-risk this. That's why we've taken the long road to do this, the slow road to do it. That's great, and 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. No, we're not. I mean we definitely have done 10 years and so I think
I think that 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'll be the trend of the future. 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...
or chemical, you know, other type of industrial users along the Gulf Coast and be a long-term, reliable supplier of those and capture, you know, capture the highest price possible by being able to be direct connected to them.
You know, and I would like to make a kind of global comment that if you look at our major stockholder, the Jerry Jones family,
He converted his bird into common in November . He gets a dividend like everybody else. He gets equity appreciation like everybody else. And he has a total of about 1.1 billion 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 the little different nuance that we have and why we have it. 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, two 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 two rigs that we got rid of before anybody had a conference call last time. We got rid of those. So we want to advertise it. We will toggle things around.
to make sure that one, we always protect the balance sheet. Thank you. One moment, please. Our next question comes from the line of Charles Mead of Johnson Reis. Your line is open. Good morning, Jay and Roland, and to the rest of the Comstock team.
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...
well that is waiting on completion was drilled as a Haynesville. We'll be starting to frack that well late next, late this month I should say, late May and turning it to sales probably early July . But that, you know, the reason we drilled the first wells as Mosers were simply we just looked at was trying to give ourselves, you know, the best chance of success was.
Obviously, as you know, these wells are deeper, the temperatures are much warmer, 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 TVDs, 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. And there's a part of the field over where the Campbell is that's kind of down on the very far south.
south-southwest end of our acreage for geological reasons. You know, we only want to drill mozers there, but you know, for the rest of the play, we...
You know kind of the Hainesville is our primary target the Hainesville is the better rock Based on all the work that's been done in the play and that's you know We do expect superior results from our Hainesville completion. The other thing you know Charles if you look at a competitive advantage
Remember in 22 we bought the Pinnacle plant and then the 145 mile line. If we could drill these wells close to the Pinnacle line if they need to be drilled there, then we're going to save a lot of money on gathering costs.
We're going to have a competitive advantage there, which you don't put in the cost structure until you do it. Some of the next wells we drill will go into our line that we own that has probably 300 million capacity, more or less. We 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 five wells and call it equipped, it would still be a very good play for us as far as dollars in, dollars out, and reserves added.
That is all helpful detail. That's it for me. Thank you, Jay. Thank you, Charles. Appreciate it.
closer to 210 to 215, it 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 break even, you know, if you have a 15 cent transportation cost or 35 cent, it really makes a difference. So I think you know what, you know, last year with the with the
high gas prices and the huge margins, you know, a 10 cent or difference in transportation costs, you know, really was a rounding error in returns. But now it kind of comes back into focus. And I think that's one thing, you know, we shift back to the areas that have the lower cost structure. And you'll see, you know, even our gathering rates crept up on it because we drilled in these other areas last year with the high gas price that have higher trends.
of our large footprint in the Haynesville, you know, it can be 30 cents 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, and I think that's kind of like what we did in 2020. It's kind of one thing you can shift to kind of overall improve, get to your best wells that are making money in this environment.
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 two, 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 break-even price that you were referring to. 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 you know and to the extent that you know that that you don't have
a good outlook post this summer and going into next year. Yeah, that obviously changes maybe how you're drilling your inventory. But I do think the big shift is we need to drill our lowest cost kind of projects. And that's easier to do now that we've reduced the rig count and pulled in the activity.
and really just kind of put the other words 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 moving.
You know, and frankly the Western Haynesville, you say how does those come into play? 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 two to three wells on a pad because of the zipper frack capability and all that. But the Haynesville well, yeah, 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 you know 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 on the the Pinnacle system that Jay referenced. Okay great thanks Roland.
system and we save that transportation cost that we right now are you know 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 on the the Pinnacle system that Jay referenced. Okay great thanks Roland. Thank you.
Thank you. One moment, please. Our next question comes from the line of Umang Chaudhary.
Our next question comes from the line of Umang Chaudhry of Goldman Sachs. Your line is open. Your line is open.
Hi, good morning and thank you for taking my questions. Yes, sir. My first question was on activity levels in the Hainesville. Would you love any color you can provide on any incremental Hainesville rig or crew reductions which you are expecting based on your conversations with other operators in the basin? Ron, what's the rig count right now?
The rig count according to Inveris is in the upper 50s to 60 and that's down from a peak of about 70. Between us, Chesapeake and Southwestern, that's five or six rigs that we've...
communicated to the street that those three companies would be dropping. You know, 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 you'll end up seeing at least 15, maybe closer to 20 rigs being dropped between the two.
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, the frac fleet count go down related to private activity as well, especially since those are the type of companies that...
that do drill directly out of cash flow. 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, as we look at the strip today and assuming that holds, especially in the back half of 2024 and heading into 2025.
think that we're at all trying to time growing activity into that or trying to guess, you know, I think what we are, our priority is, you know, to whichever we think is the most important part is to kind of continue to delineate and prove up and get, you know, real grasp over the tight curve and the productivity of our new play.
And I think over this period of time, before this demand is needed, that's real critical. 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, you know, what we call the traditional Haynesville, which is our other areas, those areas that we're toggling because that's just that.
We don't have to develop that inventory at any particular time. It's a deep inventory. We can go to different parts, like we said, to kind of improve the economics. But that's more just to generate the cash flow to keep the company in great shape.
So there's really two different kind of two different priorities there that we're balancing in this market
Well, as we said earlier, you know, 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 GOMFOC want to make sure we provide our fair share of natural gas to Europe .
through Japan, wherever it needs to go. Well, that's helpful. Thank you so much for taking my questions.
Thank you. One moment, please. Our next question comes from the line of Paul Diamond of Citi. Your line is open. Hi, thank you. Good morning and thanks for taking my call. I just want to touch base on...
Kind of H2 cost structures. I know 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. Second half. I think that's as we get the Titan in.
There's a pretty much as we've tracked it, measured it against our conventional diesel fleets, you know, it's almost given us a 15% consistent savings, you know, on the completion cost, which is the, you know, the largest part of the
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 24, but also just the cost savings that it provides. And, you know, and it's an ideal location for it in the Haynesville because we have such an abundant gas supply that.
We'll swap out some rigs with lower drilling rates too. So there are some positives on the horizon for later this year to see some well cost savings there. But you know, I think they're mostly lucky. The earliest you start seeing those is the second half versus second quarter.
Okay, understood. Thanks for the clarity. And just one quick follow-up on the macro. Yes, Carl, we're selling 21% into LNG. Just kind of want to get my head around where you thought that idea level would be on the longer term.
Yeah, probably closer to 50%. You know, I think we want to be, I think we, you know, especially, you know, and a lot of it will depend on our new area, but, you know, that's probably some of our best, highest realizations right now is on our 10-year. your
contract now that we're doing. So as we seek to maximize our gas price, you know, that market and potentially other markets that are industrial users, power generators, you know, to the extent that they're competitive or beat those rates, you know, we'll also want to add that to our portfolio. But yeah, we would like to see
working our way toward over 50% plus and that probably is more 25, 26 when a lot of new capacity comes on. And then a lot of our other commitments, you know, maybe roll off.
toward over 50% plus, and that probably is more 25, 26 when a lot of new capacity comes on. And then a lot of our other commitments maybe roll off. Understood. Thanks for your time.
Thank you. Thank you. One moment, please. Our next question comes from the line of Leo Mariani of Roth. Your line is open. 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 help us out there a little bit? I mean, just in terms of what the parameters there, are you seeing maybe twice the EURs or something on these wells? Because my understanding is maybe they're roughly twice the cost early on, you know, at this point in time.
handle on sort of drill times and maybe what you think the early EURs are per foot on a couple wells. 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 you know you want twice the EUR.
And yeah, but I think the cost is early cost, you know, so I think the future cost, the development cost will be significantly better. I mean, you know, if we drill single wells in our traditional Haynesville, they will be our most costly wells. Because, you know, that's why pad drilling is such a big important part of everybody's development plan now, because the cost savings is those.
We were on the cutting edge of technology when we started doing it.
And now, you know, we've been pretty successful with the wells that we've turned to cells from completing and drilling. So as this kind of unfolds through 2023-24, then we can be, you know, give you a little more clarity on it.
Yep, 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 first quarter behind you, you've got the second quarter guidance out there. So kind of flat on production and second quarter. So do we see likeā¦
sequential growth in both 3Q and 4Q, assuming your plans don't change. Conversely, do we see CapEx kind of dropping in both 3Q and 4Q from 2Q levels? Trying to kind of get a handle on those kind of moving parts. Well, clearly, since we had nine rigs for most of the first quarter and we were dropping down to seven over the course of the second quarter, the first quarter was going to be the highest CapEx.
Great. The second quarter you have our guidance and your third and fourth quarters will probably be pretty similar because we'll be down to the seven rig count by the end of the second quarter and that's probably the way I would think about CapEx cadence from a production standpoint. At some point, you're right, there's some sequential growth in both.
the third and fourth 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 two rigs there, we'll have two completions.
every quarter or so and those come on at pretty high rates and flatter production profile. So your thoughts were correct.
Okay, but then just to clarify though on the cap back third quarter and fourth quarter pretty similar, but you think down versus kind of where second quarter shakes out a little bit just because of the activity reduction. Yes. Okay. Yep. All right. Now that's helpful. And then I guess just a question just around cash taxes. Obviously, you took your guidance down to call it fairly de minimus as a percentage of actual taxes in 2020.
then there's a chance that 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 percent, but it will continue to, it will go back down as cash prices, 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 percent deferred next year and we're just going to have to revisit that as as we get closer to the year in terms of gas pricing, gas prices for next year.
go back to that 75 to 80 percent deferred next year and we're just going to have to revisit that as we get closer to the year in terms of gas prices for next year. Okay, thank you.
Thank you, Leo. Thank you. This does include the conference today. I'd like to turn the call back over to Jay Allison for any closing remarks. Sure, you know, we all know that time is a valuable commodity, and we want to thank each one of you for giving us an hour and ten minutes of your time. We're going to be good to our first couple that we have and.
and the future looks brought here. So thank you for your time. Thank you. Ladies and gentlemen, this does conclude today's conference. Thank you all for participating. You may now disconnect. Have a great day.