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3rd Quarter 2026 Results November 4, 2026
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2 This presentation includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements give our current expectations or forecasts of future events. These statements include estimates of future natural gas and oil reserves, expected natural gas and oil production and future expenses, assumptions regarding future natural gas and oil prices, budgeted capital expenditures and other anticipated cash outflows, as well as statements concerning anticipated cash flow and liquidity, business strategy and other plans and objectives for future operations. Our production forecasts are dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in market prices for oil and gas, operating risks, liquidity risks, including risks relating to our debt, political and regulatory developments and legislation, and other risk factors and known trends and uncertainties as described in our Annual Report on Form 10-K for fiscal year 2025 and as updated and supplemented in our Quarterly Reports on Form 10-Q, in each case as filed with the Securities and Exchange Commission. Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in the forward-looking statements. Reserve engineering is a process of estimating underground accumulations of hydrocarbons that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could impact Comstock’s strategy and change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered. These quantities do not necessarily constitute or represent reserves as defined by the Securities and Exchange Commission and are not intended to be representative of all anticipated future well results. Comstock owns or has rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This presentation also contains trademarks, service marks and trade names of third parties, which are the property of their respective owners. The use or display of third parties’ trademarks, service marks, trade names or products in this presentation is not intended to, and does not imply, a relationship with, an endorsement or sponsorship by or of Comstock. Solely for convenience, the trademarks, service marks and trade names referred to in this presentation may appear without the ®. TM or SM symbols, but such references are not intended to indicate, in any way, that Comstock will not assert, to the fullest extend under applicable law, their rights or the right of the applicable licensor to these trademarks, service marks and trade names. Disclaimer
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3 • Production grew 9% from the third quarter of 2025 and was 8% higher than the second quarter of 2026 driven by our drilling program • Sixteen Legacy Haynesville wells were turned to sales with an average lateral length of 10,812 feet and an average per well initial production rate of 25 MMcf per day. Six were horseshoe wells • Six Western Haynesville wells were turned to sales in the third quarter with an average lateral length of 9,829 feet and an average per well initial production rate of 33 MMcf per day • Growth in production drove the third quarter 2026 financial results: • Natural gas and oil sales were $359 million for the quarter • Cash flows from operating activities was $180 million and operating cash flow before changes in working capital was $208 million or $0.71 per share • Adjusted net income was $6 million or $0.02 per share for the quarter • $450 million Haynesville shale drilling venture with Jerry Jones will generate free cash flow in 4th quarter to further strengthen the balance sheet • $1.65 billion SOCAR divestiture will substantially enhance Comstock’s balance sheet • Bank credit facility maturity was extended to November 15, 2028, and extends further to November 15, 2031, after SOCAR transaction closes and debt is retired (1) including realized hedging gains and losses (1) 3rd Quarter 2026 Highlights
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4 $450 million Drilling Venture With Jerry Jones • On August 31, 2026, Comstock entered into a Haynesville shale drilling venture with Jerry Jones, the Company’s majority stockholder • Beginning September 1, 2026, Arkoma III, a partnership owned by the Jones family, will fund the drilling and completion costs of 85% of 18 Western Haynesville wells and 80% of nine Legacy Haynesville wells • Venture will fund an estimated $300 million of capital expenditures in 2026 and an additional $150 million in 2027 on the 27 wells • Prior to September 1, Comstock has spent $180 million on these wells which will be recovered by Comstock from 100% of the net revenues from the first production of all of the wells • Arkoma III will receive the net revenues after the pre-venture costs are recovered until Arkoma III has recovered its costs and a 15% return • After the ROI is achieved, 50% of the interests in the wells will revert to Comstock • The drilling venture allows Comstock to generate free cash flow in the fourth quarter while supporting the continued development and delineation of our 547,000 net acres in the Western Haynesville as well as providing volumes to Pinnacle Gas Services
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5 Transformative Strategic Partnership with SOCAR Purchase and Sale Agreement Purchase Price Asset Perimeter Effective Date and Timeline Strategic Partnership Western Haynesville Reversion Definitive purchase and sale agreement signed on November 4, 2026 $1.65 billion cash, subject to customary adjustments; proceeds applied for debt repayment SOCAR will acquire 20% of Comstock's interest in Legacy Haynesville, 15% of Comstock's interest in Western Haynesville, and 15% of Comstock's interest in Pinnacle Gas Services July 1, 2026 effective date with closing by year-end 2026 Comstock remains Operator. The parties will jointly participate in further leasing and acquisitions in the Haynesville. SOCAR to offer future LNG marketing opportunities to Comstock SOCAR’s 15% interest in the Western Haynesville reduces to 7.5% after five years and once SOCAR has achieved a 15% return on investment in those assets which provides Comstock with increased participation in the future upside of the assets, creating a balanced structure that aligns both parties around their long-term performance
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6 Strategic SOCAR Investment Strategic Partnership Allows Comstock to Retain Significant Ownership and Upside in the Assets Texas Louisiana Arkansas Bethel Gas Plant Marquez Gas Plant Pinnacle Gas Services Western Haynesville Legacy Haynesville Legacy HSVL Western HSVL 80% 20% 85%1 15%1 62%2 11% SOCAR is paying $1.65 billion in cash to acquire: • 20% non-operated working interest in Legacy Haynesville upstream assets • 15% non-operated working interest in Western Haynesville upstream assets(1) ▪ SOCAR’s 15% interest in the Western Haynesville reduces to 7.5% after five years and once the investor has achieved a 15% return on investment in those assets • 15% of Comstock’s 73% ownership in Pinnacle Gas Services LLC (1) After five years, if SOCAR achieves a 15% return on its investment in Western Haynesville upstream assets, Comstock’s interest in those assets increases from 85% to 92.5%. (2) Sixth Street owns remaining 27% of Pinnacle Gas Services, which reduces to 19.5% after certain return hurdles are met. Comstock’s interest increases to 69.5%. 27%2
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7 Investment Considerations Key Partnership Impacts to Comstock Value Validation The $1.65 billion purchase price provides strong validation of the value implied by the quality and longevity of Comstock’s upstream assets in the Legacy Haynesville and Western Haynesville Reaffirmation of the significant midstream value embedded within the Pinnacle system servicing the Western Haynesville footprint Strategic Partnership SOCAR brings its large investment-grade balance sheet and global LNG marketing operation to create value for Comstock investors Stronger Balance Sheet Proceeds from the transaction will be used to repay the outstanding balance under the Company’s revolving credit facility with pro forma net debt decreasing to approximately $1.7 billion, compared with $3.4 billion as of September 30, 2026, resulting in a substantial reduction in financial leverage Accelerated Western Haynesville Development The resulting stronger balance sheet will support continued delineation and development of Comstock's 547,000 net acres in the Western Haynesville Maintain Control, Retain Upside Comstock will remain Operator, retain further upside in Western Haynesville through the reversion provision
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8 De-levered balance sheet permits development flexibility Partnership combines Comstock’s Gulf Coast location, access to significant gas reserves, and midstream operations with SOCAR’s LNG and trading platforms Scaled footprint across Legacy and Western Haynesville with decades of drilling inventory Alliance with long-term, strategic stakeholders - the Jones Family and SOCAR Positioned to optimally maximize natural gas pricing netbacks across domestic and international markets, while also mitigating volatility via strategic partnership in power supply and midstream investment Benefits of the Strategic Partnership
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9 $ in millions Q3 2026 Financial Results
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10 $ in millions YTD 2026 Financial Results
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11 Per Mcf Natural Gas Price Realizations 3Q 2025 4Q 2025 1Q 2026 2Q 2026 3Q 2026 NYMEX Settlement Month Average 3.07$ 3.55$ 4.96$ 2.89$ 2.95$ NYMEX Differential (0.32) (0.26) (0.69) (0.35) (0.34) Realized Prices 2.75$ 3.29$ 4.27$ 2.54$ 2.61$ NYMEX Contract Settlement Price 3.07$ 3.55$ 4.96$ 2.89$ 2.95$ NYMEX Average Spot Price 3.03$ 3.68$ 4.90$ 2.93$ 2.87$ % of Gas Sold at Index (Nominated) 72% 73% 74% 68% 67% % of Gas Sold at Spot (Daily) 28% 27% 26% 32% 33% NYMEX Reference Price 3.06$ 3.58$ 4.94$ 2.91$ 2.93$ NYMEX Differential (0.31) (0.29) (0.67) (0.37) (0.32) Realized Price 2.75$ 3.29$ 4.27$ 2.54$ 2.61$ % Hedged 57% 57% 72% 63% 59% Realized Price, after Hedging 2.99$ 3.27$ 3.45$ 2.93$ 2.93$ Realized Price, with Marketing income 2.99$ 3.26$ 3.50$ 2.94$ 2.95$ $2.75 $3.29 $4.27 $2.54 $2.61
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12 Per Mcfe Per Unit Operating Costs and Margin
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13 ($ in millions) 2026 Drilling Program Third Quarter 2026 Nine Months 2026 ($ in millions) Haynesville Drilling Program - Drilling & Completion 370.7$ 1,085.1$ Other 11.8$ 30.8$ Other Properties 0.3$ 0.6$ Total D&C 382.9$ 1,116.6$ Gross Net Gross Net Gross Net Operated - Drilled 39 28.6 16 10.0 55 38.7 Turned to Sales 32 26.2 20 18.5 52 44.7 Average Lateral Length(1) - Operated Average Initial Rates (1) - Operated (1) Turned to Sales Wells 2026 Haynesville Drilling Program Haynesville Bossier Total (feet) 11,267 28 11,192 (Mmcf per day) 29 11,071 31
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14 Bank Credit Facilities Upstream $1.5 Billion Secured Revolving Credit Facility: • $2 billion borrowing base • Maturity date November 15, 2028* • Key financial covenants- Leverage Ratio < 3.5x, Current Ratio > 1.0 Capitalization Midstream $150 Million Secured Revolving Credit Facility: • Maturity date March 26, 2030 • Key financial covenants- Leverage Ratio < 4.0x, Interest Coverage > 2.5x Pro Forma Debt Maturity *November 15, 2031, after SOCAR Transaction ($ in millions) 9/30/2026 SOCAR Pro Forma Cash and Cash Equivalents $19 $19 Upstream Credit Facility 800 (690) 110 Midstream Credit Facility - - Secured Debt $800 ($690) $110 6¾% Senior Notes due 2029 $1,624 ($1,000) $624 5⅞% Senior Notes due 2030 965 965 Total Debt $3,389 ($1,690) $1,699 Common Equity $3,196 $3,196 Total Capitalization $6,585 ($1,690) $4,895 LTM EBITDAX $1,039 $841 Credit Statistics Secured Debt / LTM EBITDAX 0.8x 0.1x Total Net Debt / LTM EBITDAX 3.2x 2.0x Liquidity Analysis Cash & Cash Equivalents $19 $19 Revolving Credit Facilities Borrowing Base 1,650 1,650 Less Revolving Credit Facility Outstanding (800) (110) Liquidity $869 $1,559
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15 Leading acreage position in Haynesville/Bossier shale play in Texas and Louisiana - 1,084,812 gross / 809,883 net acres Leon Robertson Freestone Harrison Panola Sabine Rusk Webster Bossier Caddo De Soto Red River Limestone Bienville Texas Louisiana Western Haynesville (746,573 gross/ 547,612 net) Legacy Haynesville (338,239 gross/ 262,271 net) Haynesville Shale Footprint
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16 16 • Average lateral length of location inventory is 10,212 feet • Includes 108 (86 net) U or J Hook operated locations (54 Haynesville, 54 Bossier) Legacy Haynesville As of September 30, 2026 Drilling Inventory Lateral Length Gross Net Gross Net Gross Net WI Net Mft Avg Net ft Up to 5,000 ft 6 5 174 20 180 25 117 4,680 5,000 ft to 8,500 ft 83 59 76 14 159 73 499 6,836 8,500 ft to 10,000 ft 153 112 72 9 225 121 1,134 9,372 > 10,000 ft 207 154 94 12 301 166 2,016 12,145 449 330 416 55 865 385 3,766 9,782 Lateral Length Gross Net Gross Net Gross Net WI Net Mft Avg Net ft Up to 5,000 ft 2 2 80 9 82 11 48 4,364 5,000 ft to 8,500 ft 52 43 40 10 92 53 369 6,962 8,500 ft to 10,000 ft 161 131 180 18 341 149 1,402 9,409 > 10,000 ft 235 192 54 4 289 196 2,523 12,872 450 368 354 41 804 409 4,342 10,616 Total 899 698 770 96 1,669 794 8,108 10,212 Bossier Operated Non-Operated Total Haynesville Operated Non-Operated Total
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17 17 • Assumes average working interest of 70% to 90% Drilling Inventory Western Haynesville As of September 30, 2026 Lateral Length Gross Net Gross Net Gross Net WI Net Mft Avg Net ft Up to 5,000 ft 0 0 0 0 0 0 0 5,000 ft to 8,500 ft 524 401 734 572 1,258 973 7,116 7,313 8,500 ft to 10,000 ft 290 213 390 308 680 521 4,750 9,117 > 10,000 ft 389 300 928 713 1,317 1,013 10,406 10,273 1,203 914 2,052 1,593 3,255 2,507 22,272 8,884 WESTERN HAYNESVILLE Haynesville Bossier Total
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18 Future Enhancements Unlocking Improved Economic Unlocking Additional Value Extended-Reach and Re-Entry Opportunities for Higher-Return Drilling Inventory Horseshoe economics unlock previously stranded acreage by converting two sectional laterals into a single two-mile well Future Enhancements: Horseshoe development and rotary steerable technology are driving the next generation of value creation Redevelopment opportunities continue to expand the economic inventory Longer laterals (15,000-feet to 20,000-feet) improve capital efficiency and resource recovery, particularly in the Bossier shale Drilling first 19k lateral in East Texas 20K lateral wells planned for early 2029 in Louisiana Drill-through applications have shown promising early results and may unlock previously bypassed reservoir potential Current Results and Plans: 17 operated horseshoe wells TTS to date with average lateral length of 10,223 feet 2 most recent East Texas horseshoe wells with an average lateral length of 13,518 feet Additional optimization in East Texas resulting from shallower vertical depth which should extend lateral reach 3 operated horseshoe wells in progress with average lateral length of 11,100 feet No appreciable difference recognized with initial or long-term production to date Average IP of 29 MMcfd 17 operated horseshoe wells TTS Average IP: 29 MMCFD Average lateral length: 10,223 ft 108 horseshoe locations at 9/30/26 Plans to TTS ~30 horseshoe wells in next two years
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19 Average Lateral Length (feet) Wells that reached Total Depth Uncompleted wells are estimated Legacy Haynesville Western Haynesville Lateral Lengths
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20 •38 operated wells were turned to sales with an average lateral length of 11,530 feet and an average per well IP rate of 28 MMcf per day Legacy Haynesville YTD 2026 Drilling Results Bienville Harrison Panola Sabine Bossier Caddo De Soto Red River Texas Louisiana Webster Well Name Lateral TTS Date IP Rate 1 Whitney Corp 28-33-4 #1 13,737 03/25/2026 28 2 Whitney Corp 28-33-4 #2 15,011 03/25/2026 30 3 Whitney Corp 28-33-4 #3 15,143 03/25/2026 26 4 Camptec 29-14-9 #2* 9,613 03/27/2026 41 5 Campbell 9-16-21 #3 10,189 03/28/2026 34 6 Campbell 9-16-21 #4 10,232 03/28/2026 34 7 Campbell 9-16-21 #1 14,855 03/30/2026 37 8 Campbell 9-16-21 #2 14,718 03/30/2026 36 9 Nabors 5 HU #1* 9,465 04/19/2026 25 10 Nabors 5 HU #2* 10,158 04/19/2026 15 11 Dixon 6-1 HU #1* 10,090 05/24/2026 33 12 Dixon 6 HU #1* 9,826 05/24/2026 36 13 Dixon 6 HU #2* 9,304 05/24/2026 30 14 Bedsole 3-10 #4 10,249 06/10/2026 22 15 Bedsole 3-10 #5 10,199 06/10/2026 21 16 Bedsole 3-10 #6 10,242 06/10/2026 32 17 Whitson 5-32-29 #1 15,700 06/26/2026 28 18 Whitson 5-32-29 #2 15,556 06/26/2026 33 19 Speights 5-32-29 #1 15,772 06/26/2026 34 20 Speights 5-32-29 #2 15,744 06/26/2026 26 21 Cason 31 HU #1* 9,839 07/04/2026 36 22 Cason 31 HU #2* 9,495 07/04/2026 35 23 Elva 29 HU #1* 9,940 07/15/2026 26 24 Elva 29 HU #2* 8,497 07/15/2026 20 25 McClaran HU #1* 12,013 07/20/2026 22 26 Pearl Stone Clark A #1 9,941 08/08/2026 21 27 Pearl Stone Clark B #2 10,027 08/08/2026 23 28 Pearl Stone Clark E #5 10,075 08/10/2026 25 29 Pearl Stone Clark F #6 10,123 08/10/2026 27 30 Lott 5-8-17 #1 15,564 08/22/2026 34 31 Abney Alloc #1* 15,022 09/20/2026 22 32 Baker 12-13-24 #1 10,120 09/23/2026 25 33 Baker 12-13-24 #2 10,411 09/23/2026 28 34 Baker 18-19 #1 9,718 09/23/2026 24 35 Baker 12-13-24 #3 10,731 09/25/2026 24 36 Baker 12-13-24 #4 10,642 09/25/2026 22 37 Bagley 33 HU #2* 10,070 10/10/2026 28 38 Bagley 33 HU #3* 10,093 10/10/2026 30 11,530 28 * Horseshoe Well
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21 • Seventeen operated wells were turned to sales with an average lateral length of 10,153 feet and average per well IP rate of 31 MMcf per day Western Haynesville YTD 2026 Drilling Results Leon Robertson Freestone Limestone Texas Well Name Lateral TTS Date IP Rate 1 Hutto Rodell #1 8,261 01/16/2026 20 2 Bumpurs NMH #1 11,325 03/10/2026 32 3 Bumpurs BHGJ #1 12,341 03/10/2026 32 4 Pollard TFG #1 12,710 03/16/2026 31 5 Pollard MBK #1 11,249 03/16/2026 25 6 Kiker BK #1 9,355 04/14/2026 35 7 Ericson KN #1 7,975 05/07/2026 30 8 Jensen WW #1 9,243 05/07/2026 31 9 Glass KG #1 11,182 05/15/2026 35 10 Lotspeich BJ #1 9,805 07/01/2026 34 11 Jones LA #1 10,191 07/01/2026 33 12 Kretzschmar PBH #1 7,956 08/17/2026 29 13 Kretzschmar PP #1 9,292 08/17/2026 39 14 Dollie Jones RP #1 14,783 08/17/2026 40 15 Starkey MP #1 6,936 09/05/2026 31 16 Winn CR #1 11,393 09/18/2026 31 17 Danford CS #1 8,612 10/02/2026 26 10,153 31
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22 Drilling Days to Total Depth Footage per Day Legacy Haynesville Excludes pilot holes, cores and sidetracks. Drilling Efficiency
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23 Drilling Days to Total Depth Footage per Day Western Haynesville Excludes pilot holes, cores and sidetracks. Drilling Efficiency
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24 ($ per Lateral Foot) (Laterals > 8,500 ft.) Drilling Completion Wells that reached Total Depth Wells turned to Sales Legacy Haynesville Excludes pilot holes, cores and sidetracks. D&C Costs
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25 ($ per Lateral Foot) Wells that reached Total Depth Wells turned to Sales Western Haynesville Excludes pilot holes, cores and sidetracks. D&C Costs Drilling Completion
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26 • Our primary goal continues to be advancing our Western Haynesville that will position Comstock to benefit from the longer-term growth in natural gas demand • We have five operated rigs drilling in the Western Haynesville to continue to delineate the new play • Expect to drill 19 wells and turn 20 wells to sales in 2026 • Expect drilling efficiencies and changes to our completion design to continue to drive up productivity and drive down D&C costs • Have four operated rigs drilling in Legacy Haynesville to support production growth in 2026 and 2027 • Expect to drill 52 wells and turn 45 wells to sales in 2026 • Jones drilling venture allows Comstock to generate free cash flow in the fourth quarter while supporting the ongoing delineation and development of the Western Haynesville • SOCAR transaction will allow us to retire half of our debt outstanding providing us a strong balance sheet as we enter 2027 2026 Outlook
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27 Natural Gas Hedges (Mmcf/d) $/Mmbtu (Mmcf/d) $/Mmbtu (Mmcf/d) $/Mmbtu 2026 Total $3.51 2027 Total $3.50 2028 Total $3.50 Q1 780 $3.50 x $4.35 Q1 510 $3.50 x $4.44 Q1 110 2026 Total $3.51 2027 Total $3.50 2028 Total $3.50 Q2 780 $3.50 x $4.35 Q2 510 $3.50 x $4.44 Q2 110 2026 Total $3.51 2027 Total $3.50 2028 Total $3.50 Q3 780 $3.50 x $4.35 Q3 510 $3.50 x $4.44 Q3 110 2026 Total $3.51 2027 Total $3.50 2028 Total $3.50 Q4 780 $3.50 x $4.35 Q4 510 $3.50 x $4.44 Q4 110 320 460 Swaps Collars 320 460 Swaps Collars 320 460 Swaps Collars 320 460 Swaps Collars 110 400 Swaps Collars 110 400 Swaps Collars 110 400 Swaps Collars 110 400 Swaps Collars 110Swaps Collars 110Swaps Collars 110Swaps Collars 110Swaps Collars
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28 2 Guidance Guidance 4Q 2026 Production (Mmcfe/d) 1,375 - 1,500 Total Capex ($ in Millions) $125 - $225 Pinnacle Gas Services ($ in Millions) $15 - $25 Expenses ($/Mcfe) - Lease Operating ($/Mcfe) $0.25 - $0.29 Gathering & Transportation ($/Mcfe) $0.34 - $0.40 Production & Other Taxes ($/Mcfe) $0.10 - $0.15 DD&A ($/Mcfe) $1.40 - $1.50 Cash G&A ($MM) $9 - $11 Non-Cash G&A ($MM) $7 - $9 Cash Interest ($MM) $57 - $60 Non-Cash Interest ($MM) $3 - $4 Effective Tax Rate (%) 22% - 24% Deferred Tax (%) 98% - 100%
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29 2 Non-GAAP Financial Measures $ in thousands except per share amounts Net income (loss) $ 22,270 $ 111,128 $ 138,486 $ 114,692 Unrealized loss (gain) from derivative finacial instruments (35,067) (116,441) (118,883) (25,622) Exploration 10,745 6,600 24,515 8,750 (Gain) loss on sale of assets - 2,493 (3,400) 2,493 Adjustment to income taxes 7,928 17,153 12,847 2,734 Adjusted net income (loss) $ 5,876 $ 20,933 $ 53,565 $ 103,047 Adjusted net income (loss) per share $ 0.02 $ 0.07 $ 0.18 $ 0.35 Diluted shares outstanding 294,004 $ in thousands Net income (loss) $ 25,366 $ 118,099 152,865 $ 133,434 Interest expense 58,333 56,722 166,436 166,737 Income taxes 13,973 18,623 23,126 16,834 Depreciation, depletion, and amortization 185,655 157,395 494,619 483,665 Exploration 10,745 6,600 24,515 8,750 Unrealized loss (gain) from derivative finacial instruments (35,067) (116,441) (118,883) (25,622) Stock-based compensation 7,477 5,624 23,280 15,595 (Gain) loss on sale of assets - 2,493 (3,400) 2,493 Total Adjusted EBITDAX $ 266,482 $ 249,115 $ 762,558 $ 801,886 $ in thousands Cash flows from operating activities $ 180,209 153,093 $ 622,379 675,403 Increase (decrease) in accounts receivable 43,207 (582) (18,745) (1,900) Increase (decrease) in other current assets 29 1,729 2,978 (24,152) Decrease (increase) in accounts payable and accrued expenses (15,460) 36,111 (18,224) (10,376) Operating cash flows before working capital changes $ 207,985 190,351 $ 588,388 638,975 2026 2025 2026 2025 Operating Cash Flow Quarter Ended September 30, Nine Months Ended September 30, 2026 2025 2026 2025 291,772 293,952 291,569 Adjusted EBITDAX Quarter Ended September 30, Nine Months Ended September 30, Adjusted Net Income Quarter Ended September 30, Nine Months Ended September 30, 2026 2025 2026 2025