Good day, and thank you for being here. Welcome to the Comstock Resources Second Quarter 2021 Earnings conference call. Currently, all participants are in a listen-only mode. Following the presentation, there will be a question-and-answer session. I will now turn the call over to your speaker, Jay Allison, Chairman and CEO. Please proceed.

Again, thank you for the introduction. I know that we're reporting on the second quarter 2021 today. I know that. But we're super excited about what we see for the second half of this year. We advertised that we were front-end loading our capital expenditures in 2021 through the first half of the year, which we did. And now we see and actually have it today, corporate record high natural gas production at Comstock, which we are selling at high natural gas prices. The world of natural gas looks really solid with natural gas trading at $4 range plus this morning as I looked on the ticker, especially Haynesville dry natural gas that is a primary feedstock gas for LNG exports staged in Europe as well as to Mexico. Global demand for natural gas is very strong for industrial power generation as well as electrical demand for cooling and heating, while supply is low-to-moderate in part due to the disciplined use of capital expenditure dollars across the entire oil and gas sector, as you are all aware of in this earnings season. Our corporate strength lies in our best-in-class, low-cost structure, which creates our high margins as well as the 1,900 plus net drilling locations within our 300,000 to 323,000 net acre Haynesville/Bossier footprint, which we operate 91% of. One of the major tasks in 2021 was to reduce our cost of capital, which we took mighty steps forward with our 5.875% senior notes being issued in the second quarter 2021. We do feel the wind in our sails as we look at the third and fourth quarter of 2021 and 2022 and want to recommit to you with our goal of reducing our leverage ratio to less than 2x at the end of 2022 or before, if possible. With the refinancing in place, we reduced our interest costs per mcfe by 25% this quarter to $0.36 and are committed to continue working to reduce that number by year-end 2021, if possible. The denominator of Comstock is our consistent drilling results quarter after quarter in a Tier 1 Haynesville/Bossier region, which speaks volumes about all of our departments, especially our operations department. And through our quality Haynesville/Bossier rock, we have decades of that quality rock to drill. I know that that denominator is why Jerry Jones and his family invested $1 billion in Comstock since August 2018, and we believe that is why you, the bondholders, banks, and equity owners buy Comstock – proven rock quality, proven results over many, many years. Now I'll start the formal second quarter 2021 results. Welcome to the Comstock Resources Second Quarter 2021 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 presentations. There, you'll find a presentation entitled Second Quarter 2021 Results. I am Jay Allison, Chief Executive Officer of Comstock. With me is Roland Burns, our President and Chief Operating Officer; and Ron Mills, our VP of Finance and Investor Relations. If you go to Slide 2, please refer to Slide 2 in our presentation and note that our discussions today will include forward-looking statements within a meaning of securities laws. While we believe the expectations and such statements to be reasonable, there could be no assurance that such expectations will prove to be correct. Now if we'll go over to the second quarter 2021 highlights. We cover the highlights of the second quarter on Slide 3. In the second quarter, we reported adjusted net income of $55 million or $0.22 per diluted share. Production for the quarter averaged approximately 1.4 bcfe a day and was 98% natural gas. Our average daily production for the quarter was 8% higher than the first quarter of 2021 and 6% higher than the second quarter of 2020. Revenues, including realized hedging losses, were $325 million, 40% higher than the second quarter of 2020. Adjusted EBITDAX of $251 million was 55% higher than the second quarter of 2020. Operating cash flow for the quarter was $196 million or $0.71 per diluted share. For the quarter, we generated $20 million of free cash flow as preferred dividends, increasing our year-to-year free cash flow to $53 million. That's a good start toward reaching our annual free cash flow generation goal of over $200 million. With the stronger commodity prices we're seeing in the second half of the year, we now expect free cash flow to come in well above that goal of $200 million. Lastly, we completed the task of refinancing all of our higher coupon senior notes in the second quarter, which substantially reduced our cost of capital going forward. If you turn over to Slide 4, we recap the refinancing transaction, which closed on June 28. We issued $965 million of new 5.875% senior notes which are due in 2030. The proceeds from the offering were used to redeem the remainder of our 9.75% quarter bonds. The refinancing transaction reduced our reported annual interest expense by $33 million, and we will save $28 million in annual cash interest payments. Combined with the March refinancing that we did, our annual interest payments were reduced by $48 million. The lower cash interest expense will also drive significant improvements in our cash interest costs per mcfe produced, as I mentioned earlier – on a pro forma basis, assuming the refinancing was completed at the beginning of the quarter, our second-quarter interest cost for mcfe would have been $0.36 per mcfe as compared to a $0.48 rate in the first quarter. In addition to lowering our cost of capital, we also improved our weighted average maturity of our senior notes to 7.6 years, up from 6.3 years.

Thank you, Jay. On Slide 5, we present our financial results for the recently concluded second quarter. It was a strong quarter, driven by a 6% production increase alongside higher oil and gas prices compared to last year. Our total production for the second quarter was 124 bcf of natural gas and 362,000 barrels of oil, which is 6% more than in the second quarter of 2020 and an 8% increase from the first quarter of this year. Consequently, our oil and gas sales, including losses from our hedging program, rose by 40% to $325 million. The average oil price was $55.82 per barrel, and our gas price averaged $2.46 per mcfe, factoring in our hedges. Natural gas prices were 31% higher than what we achieved in the same second quarter last year. It’s worth noting that the NYMEX contract for the quarter averaged only $2.83, so the recent spike in gas prices will be more evident starting in July. On the cost side, production costs increased by about 6%, aligning with the production growth. General and administrative expenses fell by 5%, while non-cash depreciation, depletion, and amortization rose by 18% for the quarter. Our adjusted EBITDAX was $251 million, 55% higher than the second quarter last year. Operating cash flow reached $196 million, a 67% increase from the second quarter of 2020. We reported a net loss of $184 million for the second quarter, or $0.80 per share, primarily due to a significant mark-to-market loss on our hedge contracts of $205 million and a $114 million charge linked to the early retirement of senior notes from our refinancing on June 28. Adjusted net income, excluding the unrealized hedging loss and early retirement debt charges along with other unusual items, was a profit of $55 million or $0.22 per fully diluted share. On Slide 6, we outline our financial results for the first half of the year. For the first six months, production totaled 241.5 bcfe, including 688,000 barrels of oil, which is approximately 1% lower than our production for the same period in 2020. However, our oil and gas sales, after accounting for any realized hedging losses, were $657 million, marking a 30% increase compared to the first half of 2020. Oil prices for this period averaged $52.06 per barrel, which is 22% higher than last year, while our realized gas prices averaged $2.62 per mcf, also considering the effect of hedging, reflecting an increase of 34% over last year. For the first half, we reported adjusted EBITDAX of $513 million, which is 41% higher than the same period last year. Operating cash flow was $403 million, 47% higher than last year. Overall, we faced a loss of $322.5 million, or $1.39 per share, due to charges from the early extinguishment of debt related to our March and June refinancings and the mark-to-market unrealized loss on our hedge positions. Excluding these items, our adjusted net income would demonstrate a profit of $118 million or $0.46 per diluted share. Slide 7, we recap our hedging program. During the second quarter, we had 68% of our gas volumes hedged. That reduced our realized gas price to $2.46 per mcfe from the actual $2.59 per mcfe we realized from selling our gas production. We also had about 38% of our oil volumes hedged, which decreased our realized oil price to $55.82 per barrel versus the $61.25 we actually realized. Overall, our hedging program resulted in realized losses of $18.8 million in the quarter. For the remainder of this year, we have natural gas hedges covering 976 million cubic feet per day, which is around 70% of our expected production in the second half of this year. 59% of those hedges are fixed price swaps, but 41% are collars, which give us exposure to the higher prices we're now seeing. For 2022 or next year, we have about 40% to 45% of our expected production hedged. Almost half of those or 49% are in the form of collars, which give us substantial exposure to the higher prices that we're kind of now seeing for next year. On Slide 8, we summarized the shut-in activity during the second quarter. We had a good quarter on this front. We had only 52 million a day shut-in during the second quarter, which is 3.8% of our production, and that came down substantially from the 6.4% we had shut-in, in the first quarter. There really were no significant disruptions due to storms or other matters in the quarter, and the shut-ins that we had were very routine and related primarily to production we shut in to conduct offset frac activity. On Slide 9, we detail our operating cost per mcfe. We had a good quarter there. Our operating cost per mcfe averaged $0.54 in the second quarter, and that was $0.01 lower than the first quarter rate. Gathering costs were $0.25, taxes $0.08 and the other lifting cost in the field were $0.21, very comparable to the first quarter rates. Slide 10, on corporate overhead per mcfe. That again, came in at $0.05 in the second quarter. It's one of the lowest in the industry. Again, very consistent to what we expected and what we've had in the past. We do expect cash G&A to remain in this $0.05 to $0.07 range going forward. Slide 11. That's the depreciation, depletion and amortization per mcfe produced. That came in at $0.96 in the second quarter. It was $0.01 higher than the $0.95 rate we had in the first quarter of this year. Slide 12. It's a picture of our balance sheet at the end of the second quarter, reflecting our June 28 refinancing transaction, which closed right at the end of the quarter. We ended the quarter with $475 million drawn on our revolving credit facility, which has a $1.4 billion borrowing base. We expect to continue to reduce that as we generate free cash flow the rest of the year. Free cash flow is being designated to continue to reduce our debt. We now have approximately $2.459 billion of senior notes outstanding, comprised of $244 million of the 7.5% senior notes due in 2025 and $1.25 billion of new 6.75% senior notes due in 2029 that we issued in March. The new $965 million of new 5.875% senior notes due in 2030 were issued at the end of the second quarter. We plan to retire the 2025 7.5% bonds probably sometime early next year by targeting the free cash flow that we generate and using that as a permanent debt reduction move by the company. Slide 13 recaps the second quarter capital expenditures. In the second quarter, we spent $165 million on our development activities, and $154 million of that relates to our operated Haynesville shale properties. We drilled 21 or 15.7 net operated horizontal Haynesville wells, and then we returned 16 or 14.2 net operated Haynesville wells to sales in the recently completed second quarter. We also spent about $10.9 million on non-operated activity and other development activity. In addition to funding our development program, we've also invested $7.6 million on leasing new exploratory acreage. Given the tremendous success of that leasing program, we have decided to increase our budget up to a maximum of $20 million to spend on putting new leases in to support our Haynesville shale drilling program in the future. We're currently operating five operated drilling rigs for our 2021 program, and we see kind of maintaining those five as we look ahead into 2022. Based on this current operating plan, we expect to spend about $525 million to $560 million on this year's drilling plan, which will drill 55 net wells and turn to sales about 48 net wells. This is a small increase from what we expected at the beginning of the year. Most of that is really due to changes in the timing of when completions happen and also higher-than-expected non-operated activity. We definitely are focused on generating significant free cash flow. With the current gas prices, we now anticipate significantly exceeding our original target of $200 million of free cash flow for this year. We'll use that incremental free cash flow to accelerate the delevering of our balance sheet.

Okay. Thank you, Roland. Flip over on Slide 14. You'll see the map outlined in the summary of our new well completions. Since the last call, we've turned 21 new additional wells to sales. The 21 wells were tested at rates ranging from 15 million cubic feet a day up to 32 million cubic feet a day with a 22 million cubic feet per day average IP rate. The wells had lateral lengths ranging from 4,580 feet to 11,388 feet, and we had an average for the quarter of 8,251 feet. In addition to the wells we listed here, we currently have 13 additional wells that we have in various stages of completion. Regarding the activity levels this past May, we did drop down from six to five rigs. That's where we are today, and we intend to hold our activity flat at this level for the remainder of the year and into next year. Our fiscal DUC count currently stands at 23 wells, and we're actively running three frac crews. Over on Slide 15, as an updated D&C call stream for our benchmark long lateral wells. These are our laterals greater than 8,000 feet in length. Through the end of the second quarter, 73% of all the wells turned to sales this year have been long lateral wells. During the second quarter, our total D&C cost averaged $1,051 a foot. This represents a 3% increase compared to the first quarter and is 2% higher than the full year 2020 total D&C cost. Our drilling costs in the second quarter increased by 7% compared to the first quarter. This is primarily attributable to a lower average lateral length versus the first quarter but still 15% less than our drilling cost in 2020. Our completion costs remained relatively flat with only a 2% increase from the first quarter but are still running 16% higher than 2020. This is due to the large number of smaller fracs that were pumped in 2020, which led to the lower costs last year. For the remainder of the year, we expect our completion costs will remain relatively flat, and we do not foresee any material increase in costs. By building on our basin-leading drilling performance and keeping our current completion costs in check, we expect to maintain our total D&C cost for our benchmark long lateral wells in this $1,025 to $1,050 foot range. Also, I want to add that we're currently drilling two 15,000-foot laterals that we spud in June. This is the first for the company. We expect to complete these wells during the fourth quarter. We also have two additional 15,000-foot wells that we will spud later this month that will be completed in the first quarter of next year. These longer laterals are going to help bolster our efforts to further increase our lateral lengths and drive down our costs.

Okay, Dan, that's short and sweet. It's usually about ten pages, and we've condensed it. That's a good report and Roland, same here. We'll conclude before we open it up for questions. If you look at the 2021 outlook, I'd like to direct you to Slide 16, where we summarize our outlook for the remainder of this year. Our operating plan for this year is expected to provide for around 8% to maybe 10% production growth and most importantly, generate in excess as Roland said, $200 million of free cash flow and maybe a lot more than that. Our primary focus this year is to improve our balance sheet, reduce our leverage, and lower our cost of capital, which we've made great strides on. Our June refinancing transaction was another significant step to reducing our cost of capital with the $28 million annual savings in interest payments. We will primarily focus on absolute debt reduction and seek to retire, as Roland said, our 2025 bonds with free cash flow that we generate the rest of this year. If natural gas prices stay at current levels, we would expect our leverage ratio to improve to less than a 2.5X at the end of 2021, down from that 3.8 million at the end of 2020. Based on our current plans and the price outlook, we'd anticipate our leverage ratio further improving to less than 2X at the end of 2022. We remain focused on maintaining and improving our industry-leading low-cost structure and best-in-class well drilling returns with our industry-leading low-cost structure. Our Haynesville drilling program generates some of the highest drilling returns in all of North America. Our large inventory of Haynesville/Bossier drilling locations provide us with decades of drilling inventory. We'll also focus on lowering our greenhouse gas emissions and are currently evaluating participating in one of the programs to certify our gas as responsibly sourced while we have very strong liquidity, as Roland mentioned, at $945 million.

Thanks, Jay. On the guidance page, we just updated the guidance for the remainder of this year. Production guidance remains at the 1.33 to 1.425 bcfe per day number that we had previously provided. As mentioned on the call, our development capex guidance is $525 million to $560 million, and we anticipate remaining at the five rigs we're currently running over the remainder of the year. Meanwhile, the leasing capital has increased to $15 million to $20 million as we continue to add acreage. On the cost side, LOE, GTC, really all the cost items remain unchanged from the prior quarter, and so we continue to hit all of our targets on the cost side.

Our first question comes from Derrick Whitfield with Stifel.

Thanks, and good morning all. With my first question, I wanted to focus on your revised 2021 capital budget. With the understanding that nearly 40% of the revision was focused on leasing, which is arguably the most accretive dollar you could spend, could you help frame the remaining components of the increase on the development side?

Sure, Derek. That's a good question. It's a modest increase despite overall. But what we are seeing is, given the higher prices in the Haynesville, obviously seeing more nonoperated opportunities. We've set a very high bar trying – we said only the ones that have very high returns are we participating in and the ones that have a lower return, we have actually been able to sell down to other investors. Unfortunately, a lot of them have a very high return. So it's hard to not participate in those. On the operated side, where we do control that, a lot of the actual dollars really depend on when you complete the wells. We have a consistent drilling operation now, and that's stayed relatively the same, and we've actually probably achieved a little bit quicker drilling times. It really comes down to timing. That changes all the time based on when do the completion dollars fall? Do they actually hit this year? Do they go into next year? It can actually be the difference between $10 million and $20 million very easily in our budget, and we're constantly looking at that. To Ron's credit, we've also probably in the past, kind of looked at our projects and put them into three buckets: the 5,000-foot laterals to 7,500-foot laterals, the 10,000-foot laterals and budgeted that way. I think we've developed a very accurate formula that takes the exact footage and comes up with a better estimate, especially when wells fall in between those different numbers. So we do see that working really well now.

Yes. My only comment is, there's efficiencies that we've managed, but they've moved dollars forward. They probably moved them forward quicker than we want. We try to manage that by being very selective on non-operated opportunities and then just managing; 96% of what we own is HBP. So we manage this drilling program. We've kept the rig count flat. I think Dan has done a really good job historically on the completion side; you can see that's pretty predictable now and on the drilling side. We've got significantly quicker. So you move a bunch of these wells forward. That's why we have more DUCs today than we normally have. But we did increase that budget a little bit, and some of that is just adding acreage, which we think will be accretive to Comstock in the future.

Great. Makes complete sense to me. And really, as my follow-up, I wanted to build on Roland's comments and focus really on the trajectory of your D&C cost per lateral foot. Referencing Slide 15, it makes sense to me that D&C costs are higher per lateral foot when you're drilling shorter laterals. As you look out into the second half of 2021 and further out into 2022 when laterals will approach 10,000 feet, how should we think about the trajectory of your D&C costs, assuming a flat price/activity environment?

Well, if you look at the 10,000 to 15,000-foot laterals, we think that, again, it's a little early to predict it, but we think those costs will be below $1,000 a foot.

Yes. A great example is looking at the first quarter and second quarter, where the first quarter happened to be dominated by wells that averaged over 11,000 feet. And you can see the impact on the significant savings derived from the longer laterals. So as we continue to get more long laterals into the mix, we can revert back to averaging closer to where the first quarter was, if we have that type of lateral in excess of 10,000 feet.

Yes. So we got to the comment about the longer lateral. We've got a lot more longer laterals in the pipeline, especially on the Texas side, where you're not confined by one, two, three sections, one of those three buckets. Our goal is to get longer. We already have several wells coming in at below $1,000 a foot, and if we can get that average up, we mean to further reduce those costs.

Charles, as you look at the strip and the next seven months, we're looking on the strip right now. If you told me three months ago, I'd have $3.37 natural gas in the Haynesville, I'd be pretty happy. I like $4 better, but it looks pretty good. We did front-end load 2022. So we have that flexibility.

My first question is on gas differentials. So in Q2, you returned to your historical differential range of the mid-20s. I was wondering if you could talk about your expectations into Q3 and Q4 and also into 2022.

That's a good question. We had the benefit of the premium winter storm prices in the first quarter, which gave us a much more attractive differential in the first quarter. We expect to return to normal, just as we thought we would for this quarter. Third quarter, we expect it to be very similar. Fourth quarter is when we hope to see improved marketing opportunities with the Acadian extension. That is still planned to come into service in October, and we hope to be able to move additional gas away from the Perryville hub.

That's great. And then my next question relates to cost inflation. You had already shared some detail on some of the pressures that you're seeing today. As you think about 2022, do you have a rough estimate of how we should be thinking about cost inflation in aggregate?

Yes. I think we've seen a few really small increases and they've been really small, like 5% and less. For this year, we are pretty good. Next year, based on where we think the markets are going, I think next year, we'll probably, on average, be a little higher. That's in the 5% to 10% range. We haven't gotten any indicators from any of our providers that anything really major is coming.

We see capital discipline. We don't see a whole lot of rigs, particularly on the natural gas side, I mean, there's 103 rigs drilling for natural gas in the United States. So we don't see that increase. If it was in the frothy days before COVID, you might expect a lot of new rigs. But with this capital discipline, we're not seeing runaway inflation on our side. I think it's going to be moderate, controlled, probably in the 5% to 8% range. Given the demand for our gas and our feed gas to Europe and Asia, the demand growth for the export facilities being built and the fact that we haven't encumbered our gas with firm transportation commitments. So we are focusing on the long ball in the next 18 to 24 months. But again, we are not looking to do something just to get larger. We're in great shape. Our maturity schedule has improved significantly, and we are fighting that for a while; we've consolidated our personnel, and we're not looking to do that again. You cannot like it, but I think proper management with the balance sheet we have is essential for us in the future.

I wanted to pick up a little bit on the theme you were just touching on with locations and ask you about the Bossier. I think back, it was years ago, you guys drilled some of the first really good Bossier wells that have opened a lot of people's eyes. But since then, my impression is that you guys are really, really just focused on the Haynesville zone.

I'm going to turn this over to Dan because he's supposed to be the calm one. The two Bossier wells we just hit are the best wells we've drilled in the quarter. Nobody brought that up. I think you sniffed that out. Half of our locations are Bossier, and consulting groups love the Bossier. If you look at VINE IPO, half of their upside is Bossier. If you look at Indigo, it's Bossier. We don't talk about Bossier nearly enough – that is a great question.

We do like the Bossier. The two longest laterals we have drilled to date are a Bossier well. We plan to develop a lot of our Bossier with those long laterals.

That's one of the things we've been thinking about the Bossier as we want to migrate to the 15,000-foot laterals; the Bossier is relatively undeveloped in our acreage, and there's a lot more room to do longer laterals or we can convert a much higher percentage of our Bossier inventory into the 15,000-foot laterals than we probably can realistically on the Haynesville acreage.

We're sitting in a sweet spot with solid production upside, solid EBITDA growth, and stronger-than-expected realized pricing. You cannot be unhappy with that.

Our next question comes from Umang Choudhary with Goldman Sachs.

My first question is on your plans for absolute debt reduction. As you mentioned, gas features are very favorable. You can potentially generate free cash flow of well over $200 million. Can you talk to your plans to address the remaining maturities and once you pay down your borrowings on the credit facility?

Those are great questions. We are now that we've got the cost down on long-term debt and got the maturities in a great spot, really focused on debt reduction. We do have a significant amount of debt that we can retire with the bank facility debt. We purposely did not refinance the remaining bonds outstanding because we thought that was also a good target for debt reduction.

We would look to get the leverage down, if we can get that leverage down just to that one-handled number. We'll consider dividends. Our stakeholders would be happy to see them.

The covenant currently stands at 50% of proved developed production reserves at each borrowing base redetermination. We're currently at those levels for 2022 if we choose not to add any more hedges.

Thank you. Our next question comes from Bertrand Donnes with Truist Bank.

I was wondering, in the prepared remarks, you said you were going to hold production flat. And I just wasn't sure exactly with the lower spend in the back half, whether that might kind of drift down in 4Q and 1Q 2022 and then maybe back up in 2Q?

I don't think you talked about holding production flat. We actually talked about that this year, we're seeing about 8% to 10% growth. On the final slide, that's what our operating plan calls for.

We're not going to try to pick production and drop it off. We're going to try to level it out in our model in 2022. We know we have that. But we have a lot of DUCs that we can complete. We can shift some capex dollars around to complete those DUCs. Today, with $4.00 gas, we are at a corporate high natural gas production at Comstock.

We're going to be able to continue to hit all of our targets on the cost side.

This concludes today's conference call. Thank you for participating. You may now disconnect.