Comstock Resources, Inc.

Good day, and thank you for standing by. Welcome to the fourth quarter 2025 CompStock Resources, Inc. Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask a question during the session, you will need to press star 1-1 on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star 1-1 again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Jay Allison, Chairman and CEO. Please go ahead.

Thanks for the introduction, and I want to thank everybody for joining the call. It's always a highlight to report on what happened in the prior year and then kind of give you a visual for what we think tomorrow may look like and today is a day. So welcome to the Comstock Resources Fourth Quarter 2025 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 Fourth Quarter 2025 Results. I am 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. Please refer to slide two in our presentation to note 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. If you'll turn on slide three, we highlight our major 2025 accomplishments. We added three operated rigs to our operated program with an additional rig coming in early 2026 to drive production growth in 2026 and 2027. The additional production combined with an improved 2026 gas price outlook will substantially drive down the balance sheet leverage. In 2025, we drilled 52 or 44.2 net successful operated Hainesville-Bozier wells with an average IP rate of 27 million cubic feet per day. The 2025 drilling program replaced 229% of our 2025 production with one TCFE of drilling-related approved reserve additions, achieving an overall finding cost of $1.02 per MCFE. We announced we were partnering with Nextera on a data center project in the Western Hainesville. Nextera plans to build new behind-the-meter power generation to support hyperscaler data center development with an initial capacity of 2 gigawatts with potential expansion up to 8 gigawatts. In the third and fourth quarters, we completed $445 million of divestitures, which improved our balance sheet. We completed the sale of the legacy Cotton Valley assets in September and the sale of the Shelby Trough assets in December. We recognized a pre-tax gain of $292 million on the divestitures. The assets sold consisted of 1,084 producing wells with only 17 million cubic feet per day of net production. The sales proceeds were used to reduce debt and improve our leverage position. Over the last two years, Comstock has the highest total shareholder return of any public E&P company at 162%, almost twice the second highest company's total shareholder return. For the last two years, Comstock was number one in total shareholder return among its public natural gas producers. On slide four, we summarize the highlights of the fourth quarter. Higher natural gas prices in the fourth quarter drove the improved financial results in the quarter compared to the fourth quarter of 2024. Our natural gas and oil sales grew to $365 million. We generated $222 million of operating cash flow, or 75 cents per share. Adjusted EBITDAX for the quarter was $277 million, and we reported adjusted net income of $46 million, or 16 cents per share. During the fourth quarter, we put four new Western Hainesville wells online, increasing the number of wells turned to sales in 2025 in the Western Hainesville to 12 wells. These four wells had a at an average lateral length of 8,399 feet and an average per well initial production rate of 29 million cubic feet per day. In our legacy Hainesville, we turned 35 wells to sales in 2025 with an average lateral length of 11,738 feet and a per well initial production rate of 25 million cubic feet per day. In December, We closed on the sale of our Shelby Trough assets in East Texas for total net proceeds of $417 million in net proceeds after selling expenses. We used the proceeds from the asset sale to reduce borrowings under our revolver. Roland will provide some more details on financial results that we reported today. Roland?

Thanks, Jay. Slide five, we covered the fourth quarter financial results. Our production in the fourth quarter averaged 1.2 CCFE per day, and our oil and gas sales in the quarter increased 8% to $364 million in the fourth quarter this year, despite the lower production number. EVA DAX for the quarter was $277 million, and we generated $222 million of cash flow in the fourth quarter. We reported a $281 million profit for the quarter, or 97 cents per share, Included in that number were some unusual items, including the pre-tax gain on the asset sales of $294 million, a $37 million mark-to-market unrealized gain on our hedge positions, and a $29 million impairment on our non-operated Eagle Fork shale acreage. Excluding these items and expiration expense and the related income tax, related to these items, we reported adjusted net income of $46 million for the quarter, or 16 cents per diluted share, the same as the adjusted net income in last year's fourth quarter. Slide six is the financial results for the full year 2025. For the full year in 2025, our production averaged 1.2 BCFE per day, which is 14% lower than production in 2024. But the improved natural gas prices we had in 2025 increased our oil and gas sales by 15% to $1.4 billion compared to 2024. EVA DAX for 2025 totaled $1.1 billion, and we generated $861 million of cash flow last year. For the year, we reported a $396 million profit, or $1.43 per share. That also includes the unusual items, including a pre-tax gain of $292 million on the 2025 property sales, a $62 million mark-to-market unrealized gain on the hedges, and that $29 million impairment. Excluding these items and expiration expense and related income taxes, we reported adjusted net income of $160 million for 2025, or 54 cents for diluted share. compared to net loss in 2024. On slide seven, we break down our natural gas price realizations. The quarterly NYMEX settlement price in the quarter averaged $3.55 in the fourth quarter. The average Henry Hub spot price in the quarter averaged $3.69, approximately 4% above the NYMEX settlement price. 27% of our gas was sold in the spot market in the quarter, so the appropriate NYMEX reference price for our production would have been $3.58. Our realized gas price during the fourth quarter averaged $3.29, reflecting a 26 basis differential compared to the NYMEX settlement price and a 29 differential compared to that reference price for the quarter. Also in the fourth quarter, we were 57% hedged, which decreased our realized price to $3.27. Slide eight, we detail our operating cost per MCFE and our EBITDAX margin. Our operating cost per MCFE averaged 77 cents in the fourth quarter, pretty much unchanged from the rate we had in the third quarter. Our EBITDAX margin was 77% in the fourth quarter, up 3% from the third quarter. In the quarter, our lifting cost improved by one cent in the quarter. And our production and ad valorem taxes also decreased by three cents in the quarter. That was offset by increases in both our gathering cost and cash G&A costs, which both increased by two cents in the quarter. Slide nine, we recap our spending on drilling and other development activity in 2025. We spent a total of $270 million on development activities just in the fourth quarter and $55 million for the entire year in 2025. Last year we drilled 36 or 29.6 net horizontal Hainesville shell wells and another 16 or 14.6 net Bossier shell wells for a total of 52 wells. We turned 47 of those wells to sales or 40.3 net wells and we had an average overall IP rate of 27 million cubic feet per day. Slide 10, we recap our capitalization at the end of the fourth quarter. We ended the quarter with $260 million of borrowings outstanding under our credit facility after using the proceeds from the Shelby trough sale to pay down the revolver. Our borrowing base is currently at $2 billion under the credit facility with an electric commitment of 1.5 billion. Our last 12 months leverage ratio has improved to 2.6 times and should continue to improve throughout 2026, given the growth we expect in EVA DAX. At the end of the fourth quarter, we had almost 1.3 billion of liquidity. Slot 11, we recap our approved reserves at the end of 2025, which came in at 7.2 TCFE, based on reserves determining year-end NYMEX market prices adjusted for our differentials. Proved reserves determined using year-end NOMICS prices were slightly higher than proved reserves determined under the SEC rules, and those reserves were 7 TCFE at year-end. We were able to grow our reserves 8% in 2025, excluding the impact of the Cotton Valley and Shelby Trough asset sales, which totaled 419 BCFE. 2025 drilling additions of 1.1 TCF replaced 229% of our 2025 production of 450 BCFE. We spent $1.55 million on our drilling program in 2025, giving us the total overall finding cost of $1.02 in 2025. In addition to the approved reserves that we reported, we also have 1.9 TCFE approved undeveloped reserves, which are not included in our approved reserves only because they're not expected to be drilled within the five-year rule as prescribed by SEC rules. We also have another 2.5 TCFE of 2P or probable reserves and an additional 7.7 TCFE of 3P or possible reserves or a total of 19.3 TCFE of reserves on a P3 basis. This does not include a substantial amount of the reserve potential for much of our western Hainesville acreage, where we have only included 5.4 TCFE related to the western Hainesville NRP3 reserve estimates. I'll now turn it over to Dan to discuss the drilling results we've had.