News Release Coterra Energy Reports Second-Quarter 2025 Results, Announces Quarterly Dividend, and Provides Guidance Update HOUSTON, August 4, 2025 - Coterra Energy Inc. (NYSE: CTRA) (“Coterra” or the “Company”) today reported second-quarter 2025 financial and operating results and declared a quarterly dividend of $0.22 per share. Additionally, the Company provided third-quarter production and capital guidance and updated full-year 2025 guidance. Tom Jorden, Chairman, CEO and President of Coterra, noted, "We are pleased to report an excellent quarter with strong capital efficiency driven by lower than expected capital expenditures and higher than expected production. We are expecting to run consistent activity in the second half of 2025, with nine rigs in the Permian, two rigs in the Marcellus, and one to two rigs in the Anadarko. Our high-quality assets provide robust returns in the current environment and remain durable through the cycles. While we maintain significant operational flexibility, we expect our steady activity cadence to support a highly capital efficient 2026. Coterra provides a unique and compelling investment opportunity, with durable cash flows supported by the Company's diversified commodity mix and differentiated inventory depth and quality, all supported by a peer-leading balance sheet." Key Takeaways & Updates • For the second quarter of 2025, total BOE (barrels of oil equivalent) and natural gas production exceeded the high-end of our guidance ranges while oil volumes beat the midpoint by approximately 2%. Capital expenditures (non-GAAP) were below the low-end of our guidance range. • Increasing full-year 2025 total equivalent and natural gas production guidance, maintaining oil production midpoint. • Expect 2025 capital expenditures (non-GAAP) to be approximately $2.3 billion, which assumes consistent activity in the second half of the year with nine rigs in the Permian, two rigs in the Marcellus, and one to two rigs in the Anadarko. • Expect 2025 Free Cash Flow (non-GAAP) to total $2.1 billion, at recent strip prices. • Second-quarter 2025 direct shareholder returns totaled approximately 58% of Free Cash Flow (non-GAAP), which includes our declared dividend of $0.22 per share, or approximately $168 million, and $23 million of share repurchases. Additionally, the Company repaid $100 million of term loans bringing total returns to 89% of Free Cash Flow (non-GAAP). In 2025, Coterra remains committed to reducing leverage and executing opportunistic share repurchases. • Announcing a new power netback gas sale agreement in the Permian, expected to start in 2028, further diversifying our natural gas marketing portfolio. • Coterra published its 2025 Sustainability Report on August 4, 2025. The report can be found under "Sustainability" on the Company's website. 1 Second-Quarter 2025 Highlights • Net Income (GAAP) totaled $511 million, or $0.67 per share. Adjusted Net Income (non-GAAP) was $367 million, or $0.48 per share. • Cash Flow From Operating Activities (GAAP) totaled $937 million. Discretionary Cash Flow (non-GAAP) totaled $949 million. Free Cash Flow (non-GAAP) totaled $329 million. • Cash paid for capital expenditures for drilling, completion and other fixed asset additions (GAAP) totaled $620 million. Incurred capital expenditures from drilling, completion and other fixed asset additions (non-GAAP) totaled $569 million, below the low end of our guidance range of $575 to $650 million. • Unit operating cost (reflecting costs from direct operations, transportation, production taxes and G&A) totaled $9.34 per BOE, near the mid-point of our annual guidance range. • Total equivalent production of 783.9 MBoepd (thousand barrels of oil equivalent per day), above the high end of guidance (710 to 760 MBoepd). ◦ Oil production averaged 155.4 MBopd (thousand barrels of oil per day), near the high end of our guidance range (147 to 157 MBopd). ◦ Natural gas production averaged 2,998.6 MMcfpd (million cubic feet of gas per day), exceeding the high end of guidance (2,700 to 2,850 MMcfpd). ◦ NGLs production averaged 128.7 MBopd. • Realized average prices: ◦ Oil was $62.80 per Bbl (barrel), excluding the effect of commodity derivatives, and $64.01 per Bbl, including the effect of commodity derivatives. ◦ Natural Gas was $2.20 per Mcf (thousand cubic feet), excluding the effect of commodity derivatives, and $2.27 per Mcf, including the effect of commodity derivatives. ◦ NGLs were $18.72 per Bbl. 2 Shareholder Return Highlights • Common Dividend : On August 4, 2025, Coterra's Board of Directors approved a quarterly dividend of $0.22 per share, equating to a 3.6% annualized yield, based on the Company's $24.39 closing share price on July 31, 2025. The dividend will be paid on August 28, 2025 to holders of record on August 14, 2025. • Share Repurchases : During the quarter, the Company repurchased 0.9 million shares for $23 million, leaving $1.1 billion remaining as of June 30, 2025 on its $2.0 billion share repurchase authorization. • Shareholder Returns: During the quarter, direct shareholder returns amounted to approximately $191 million, comprised of approximately $168 million of declared dividends and $23 million of share repurchases, totaling approximately 58% of Free Cash Flow (non-GAAP).The Company also repaid $100 million of debt during the quarter. • Reiterate Shareholder Return Strategy: Coterra expects to return 50% or greater of annual Free Cash Flow (non-GAAP) to shareholders through the cycles via its base dividend and share repurchases. However, in 2025, after payment of its base dividend, the Company is prioritizing debt reduction as it looks to retire the outstanding $650 million term loans, associated with the Company's Delaware Basin acquisition in first quarter. Coterra retired $350 million of term loans in the first half of 2025. Guidance Updates • Expect 2025 capital expenditures (non-GAAP) of approximately $2.3 billion. • Announcing third-quarter 2025 guidance, including total equivalent production of 740 to 790 MBoepd, oil production of 158 to 168 MBopd, natural gas production of 2,750 to 2,900 MMcfpd, and capital expenditures (non-GAAP) of $625 to $675 million. • Estimate full-year 2025 effective tax rate of 22%, which we expect to be 40% to 60% current tax. • For more details on annual and third-quarter 2025 guidance, see 2025 Guidance Section in the tables below. Announcing New Power Sales Agreement in the Permian Coterra is announcing a new power netback gas sale agreement with CPV Basin Ranch Energy Center, a proposed 1,350 megawatt (MW) combined-cycle natural gas power plant designed with the option to include a carbon capture system. The agreement to sell 50 MMcf per day for a seven-year term is expected to start in 2028, and will be indexed to ERCOT West pricing, adding to the Company’s two existing power netback deals in the Marcellus which currently comprise 330 MMcf per day. Coterra has also secured a right to purchase up to 250 MW per day of power from the facility, located in Ward County, Texas. This is the first power netback deal secured by Coterra in the Permian Basin. Coterra will continue to explore ways to further diversify its gas sales portfolio across all three of its operating basins through power, LNG, data centers and other long-term opportunities. Strong Financial Position In conjunction with the closing of the Franklin Mountain Energy and Avant Natural Resources acquisitions in late January, Coterra issued $1.0 billion of new debt through its term loan agreements. Subsequently, Coterra has paid down $350 million of the term loans year-to-date, including an incremental $100 million during the second quarter, 3 leaving $650 million of term loan debt outstanding. As of June 30, 2025, Coterra had total debt outstanding of $4.15 billion (principal balance). The Company exited the quarter with cash and cash equivalents of $192 million, and no debt outstanding under its $2.0 billion revolving credit facility, resulting in total liquidity of approximately $2.19 billion. Coterra's Net Debt to trailing twelve-month Adjusted Pro Forma EBITDAX ratio (non-GAAP) at June 30, 2025 was 0.9x, pro forma for the Franklin and Avant acquisitions. The Company remains committed to near-term debt reduction. See “Supplemental non-GAAP Financial Measures” below for descriptions of the above non-GAAP measures as well as reconciliations of these measures to the associated GAAP measures. Committed to Sustainability and ESG Leadership Coterra is committed to environmental stewardship, sustainable practices, and strong corporate governance. The Company's sustainability report can be found under "Sustainability" on www.coterra.com. Coterra published its 2025 Sustainability report on August 4, 2025. Second-Quarter 2025 Conference Call Coterra will host a conference call tomorrow, Tuesday, August 5, 2025, at 9:00 AM CT (10:00 AM ET), to discuss second-quarter 2025 financial and operating results. Conference Call Information Date: August 5, 2025 Time: 9:00 AM CT / 10:00 AM ET Dial-in (for callers in the U.S. and Canada): (800) 715-9871 International dial-in: +1 (646) 307-1963 Conference ID: 4309719 The live audio webcast and related earnings presentation can be accessed on the "Events & Presentations" page under the "Investors" section of the Company's website at www.coterra.com. The webcast will be archived and available at the same location after the conclusion of the live event. About Coterra Energy Coterra is a premier exploration and production company based in Houston, Texas with focused operations in the Permian Basin, Marcellus Shale, and Anadarko Basin. We strive to be a leading energy producer, delivering sustainable returns through the efficient and responsible development of our diversified asset base. Learn more about us at www.coterra.com. 4 Cautionary Statement Regarding Forward-Looking Information This press release contains certain forward-looking statements within the meaning of federal securities laws. Forward-looking statements are not statements of historical fact and reflect Coterra's current views about future events. Such forward-looking statements include, but are not limited to, statements about returns to shareholders, enhanced shareholder value, reserves estimates, future financial and operating performance, and goals and commitment to sustainability and ESG leadership, strategic pursuits and goals, and other statements that are not historical facts contained in this press release. The words "expect," "project," "estimate," "believe," "anticipate," "intend," "budget," "plan," "predict," "potential," "possible," "may," "should," "could," "would," "will," "strategy," "outlook", "guide" and similar expressions are also intended to identify forward-looking statements. We can provide no assurance that the forward-looking statements contained in this press release will occur as projected and actual results may differ materially from those projected. Forward-looking statements are based on current expectations, estimates and assumptions that involve a number of risks and uncertainties that could cause actual results to differ materially from those projected. These risks and uncertainties include, without limitation, the volatility in commodity prices for crude oil and natural gas; changes in U.S. and international economic policy (including tariffs and retaliatory tariffs and the impacts thereof); cost increases; the effect of future regulatory or legislative actions; actions by, or disputes among or between, the Organization of Petroleum Exporting Countries and other producer countries; market factors; market prices (including geographic basis differentials) of oil and natural gas; impacts of inflation; labor shortages and economic disruption, (geopolitical disruptions such as the war in Ukraine or conflict in the Middle East or further escalation thereof); determination of reserves estimates, adjustments or revisions, including factors impacting such determination such as commodity prices, well performance, results of future drilling and marketing activities (including seismicity and similar data), operating expenses and completion of Coterra’s annual PUD reserves process, as well as the impact on our financial statements resulting therefrom; the presence or recoverability of estimated reserves; the ability to replace reserves; environmental risks; drilling and operating risks; exploration and development risks; competition; the ability of management to execute its plans to meet its goals; the impact of public health crises, including pandemics and epidemics and any related company or governmental policies or actions, financial condition and results of operations; and other risks inherent in Coterra's businesses. In addition, the declaration and payment of any future dividends, whether regular base quarterly dividends, variable dividends or special dividends, will depend on Coterra's financial results, cash requirements, future prospects and other factors deemed relevant by Coterra's Board. While the list of factors presented here is considered representative, no such list should be considered to be a complete statement of all potential risks and uncertainties. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. For additional information about other factors that could cause actual results to differ materially from those described in the forward-looking statements, please refer to Coterra's annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and other filings with the SEC, which are available on Coterra's website at www.coterra.com. 5 Forward-looking statements are based on the estimates and opinions of management at the time the statements are made. Except to the extent required by applicable law, Coterra does not undertake any obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. Readers are cautioned not to place undue reliance on these forward-looking statements that speak only as of the date hereof. 6 Operational Data The tables below provide a summary of production volumes, price realizations and operational activity by region and units costs for the Company for the periods indicated: Quarter Ended June 30, Six Months Ended June 30, 2025 2024 2025 2024 PRODUCTION VOLUMES Marcellus Shale Natural gas (Mmcf/day) 2,061.3 2,114.4 2,146.4 2,212.6 Daily equivalent production (MBoepd) 343.5 352.4 357.7 368.8 Permian Basin Natural gas (Mmcf/day) 669.4 484.5 627.1 485.6 Oil (MBbl/day) 148.1 99.6 140.6 98.3 NGL (MBbl/day) 98.9 78.1 86.0 74.1 Daily equivalent production (MBoepd) 358.6 258.4 331.2 253.3 Anadarko Basin Natural gas (Mmcf/day) 266.5 179.4 246.1 170.3 Oil (MBbl/day) 7.2 7.5 7.6 6.5 NGL (MBbl/day) 29.6 20.6 27.4 20.3 Daily equivalent production (MBoepd) 81.3 58.0 76.1 55.2 Total Company Natural gas (Mmcf/day) 2,998.6 2,779.8 3,021.1 2,869.9 Oil (MBbl/day) 155.4 107.2 148.4 104.9 NGL (MBbl/day) 128.7 98.8 113.6 94.5 Daily equivalent production (MBoepd) 783.9 669.2 765.4 677.7 AVERAGE SALES PRICE (excluding hedges) Marcellus Shale Natural gas ($/Mcf) $ 2.57 $ 1.66 $ 3.13 $ 1.94 Permian Basin Natural gas ($/Mcf) $ 0.88 $ (0.53) $ 1.28 $ 0.25 Oil ($/Bbl) $ 62.76 $ 79.37 $ 66.02 $ 77.30 NGL ($/Bbl) $ 17.98 $ 18.95 $ 19.66 $ 19.70 Anadarko Basin Natural gas ($/Mcf) $ 2.66 $ 1.35 $ 3.03 $ 1.70 Oil ($/Bbl) $ 63.25 $ 79.40 $ 67.10 $ 77.45 NGL ($/Bbl) $ 21.20 $ 21.75 $ 23.81 $ 22.39 Total Company Natural gas ($/Mcf) $ 2.20 $ 1.26 $ 2.74 $ 1.64 Oil ($/Bbl) $ 62.80 $ 79.37 $ 66.08 $ 77.31 NGL ($/Bbl) $ 18.72 $ 19.53 $ 20.66 $ 20.28 7 Quarter Ended June 30, Six Months Ended June 30, 2025 2024 2025 2024 AVERAGE SALES PRICE (including hedges) Total Company Natural gas ($/Mcf) $ 2.27 $ 1.40 $ 2.74 $ 1.76 Oil ($/Bbl) $ 64.01 $ 79.39 $ 66.52 $ 77.25 NGL ($/Bbl) $ 18.72 $ 19.53 $ 20.66 $ 20.28 Quarter Ended June 30, Six Months Ended June 30, 2025 2024 2025 2024 WELLS DRILLED (1)(2) Gross wells Marcellus Shale 13 8 13 22 Permian Basin 110 63 177 111 Anadarko Basin 6 11 14 19 129 82 204 152 Net wells Marcellus Shale 6.3 8.0 6.3 21.0 Permian Basin 37.6 26.8 82.7 50.0 Anadarko Basin 4.4 7.0 10.0 13.7 48.3 41.8 99.0 84.7 TURN IN LINES (2) Gross wells Marcellus Shale 3 12 8 23 Permian Basin 120 56 181 98 Anadarko Basin 24 26 28 31 147 94 217 152 Net wells Marcellus Shale 3.0 12.0 3.0 23.0 Permian Basin 49.4 22.6 86.5 44.5 Anadarko Basin 9.1 15.2 9.3 15.3 61.5 49.8 98.8 82.8 AVERAGE OPERATED RIG COUNTS Marcellus Shale 2.0 1.2 1.0 1.6 Permian Basin 10.9 8.0 11.3 8.0 Anadarko Basin 2.0 1.3 1.9 1.7 _______________________________________________________________________________ (1) Wells drilled represents wells drilled to total depth during the period. (2) Wells drilled and turn in lines include both operated and non-operated wells. 8 Quarter Ended June 30, Six Months Ended June 30, 2025 2024 2025 2024 AVERAGE UNIT COSTS ($/Boe) (1) Direct operations $ 3.32 $ 2.62 $ 3.26 $ 2.56 Gathering, processing and transportation 3.81 3.99 4.00 3.99 Taxes other than income 1.21 0.89 1.32 1.04 General and administrative (excluding stock-based compensation) 1.00 0.85 1.06 0.92 Unit Operating Cost $ 9.34 $ 8.35 $ 9.64 $ 8.52 Depreciation, depletion and amortization 8.11 7.34 7.83 7.12 Exploration 0.07 0.09 0.10 0.08 Stock-based compensation 0.18 0.26 0.21 0.24 Interest expense, net 0.71 0.23 0.69 0.15 $ 18.41 $ 16.26 $ 18.48 $ 16.10 _______________________________________________________________________________ (1) Total unit costs may differ from the sum of the individual costs due to rounding. 9 Derivatives Information As of June 30, 2025, the Company had the following outstanding financial commodity derivatives: 2025 Oil Third Quarter Fourth Quarter WTI oil collars Volume (MBbl) 5,152 5,152 Weighted average floor ($/Bbl) $ 61.34 $ 61.34 Weighted average ceiling ($/Bbl) $ 79.00 $ 79.00 WTI NYMEX oil swaps Volume (MBbl) 1,748 1,748 Weighted average price ($/Bbl) $ 69.18 $ 69.18 WTI Midland oil basis swaps Volume (MBbl) 5,520 5,520 Weighted average differential ($/Bbl) $ 1.02 $ 1.02 2026 Oil First Quarter Second Quarter Third Quarter Fourth Quarter WTI oil collars Volume (MBbl) 2,700 2,730 2,760 2,760 Weighted average floor ($/Bbl) $ 56.67 $ 56.67 $ 56.67 $ 56.67 Weighted average ceiling ($/Bbl) $ 70.68 $ 70.68 $ 70.68 $ 70.68 WTI NYMEX oil swaps Volume (MBbl) 900 910 920 920 Weighted average price ($/Bbl) $ 66.14 $ 66.14 $ 66.14 $ 66.14 WTI Midland oil basis swaps Volume (MBbl) 1,800 1,820 1,840 1,840 Weighted average differential ($/Bbl) $ 0.95 $ 0.95 $ 0.95 $ 0.95 10 2025 Natural Gas Third Quarter Fourth Quarter NYMEX gas collars Volume (MMBtu) 87,400,000 87,400,000 Weighted average floor ($/MMBtu) $ 3.08 $ 3.08 Weighted average ceiling ($/MMBtu) $ 4.88 $ 5.66 Transco Leidy gas basis swaps Volume (MMBtu) 18,400,000 18,400,000 Weighted average differential ($/MMBtu) $ (0.70) $ (0.70) Transco Zone 6 Non-NY gas basis swaps Volume (MMBtu) 18,400,000 18,400,000 Weighted average differential ($/MMBtu) $ (0.49) $ (0.49) Waha gas basis swaps Volume (MMBtu) 13,800,000 13,800,000 Weighted average differential ($/MMBtu) $ (2.05) $ (2.05) 2026 Natural Gas First Quarter Second Quarter Third Quarter Fourth Quarter NYMEX gas collars Volume (MMBtu) 81,000,000 54,600,000 55,200,000 55,200,000 Weighted average floor ($/MMBtu) $ 3.06 $ 3.21 $ 3.21 $ 3.21 Weighted average ceiling ($/MMBtu) $ 6.39 $ 5.76 $ 5.76 $ 5.76 Waha gas basis swaps Volume (MMBtu) 13,500,000 13,650,000 13,800,000 13,800,000 Weighted average differential ($/MMBtu) $ (1.86) $ (1.86) $ (1.86) $ (1.86) 11 CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited) Quarter Ended June 30, Six Months Ended June 30, (In millions, except per share amounts) 2025 2024 2025 2024 OPERATING REVENUES Oil $ 888 $ 774 $ 1,774 $ 1,475 Natural gas 601 319 1,499 857 NGL 219 176 425 349 Gain (loss) on derivative instruments 232 (16) 120 (16) Other 25 18 51 39 1,965 1,271 3,869 2,704 OPERATING EXPENSES Direct operations 236 160 452 316 Gathering, processing and transportation 271 242 553 492 Taxes other than income 87 54 183 128 Exploration 4 5 14 10 Depreciation, depletion and amortization 579 447 1,085 879 General and administrative (excluding stock-based compensation) 70 52 146 114 Stock-based compensation 14 16 30 29 1,261 976 2,463 1,968 Gain on sale of assets 4 1 4 — INCOME FROM OPERATIONS 708 296 1,410 736 Interest expense 53 34 106 53 Interest income (2) (19) (10) (35) Other (income) expense (1) — (1) — Income before income taxes 658 281 1,315 718 Income tax provision (benefit) Current 97 62 227 169 Deferred 50 (1) 61 (23) Total income tax provision 147 61 288 146 NET INCOME $ 511 $ 220 $ 1,027 $ 572 Earnings per share - Basic $ 0.67 $ 0.30 $ 1.35 $ 0.77 Weighted-average common shares outstanding 763 742 759 746 12 CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited) (In millions) June 30, 2025 December 31, 2024 ASSETS Cash and cash equivalents $ 192 $ 2,038 Other current assets 1,330 1,283 Properties and equipment, net (successful efforts method) 22,097 17,890 Other assets 363 414 $ 23,982 $ 21,625 LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITY Current liabilities $ 1,352 $ 1,136 Long-term debt, net 4,175 3,535 Deferred income taxes 3,331 3,274 Other long term liabilities 560 550 Cimarex redeemable preferred stock 8 8 Stockholders’ equity 14,556 13,122 $ 23,982 $ 21,625 13 CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited) Quarter Ended June 30, Six Months Ended June 30, (In millions) 2025 2024 2025 2024 CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 511 $ 220 $ 1,027 $ 572 Depreciation, depletion and amortization 579 447 1,085 879 Deferred income tax expense (benefit) 50 (1) 61 (23) Gain on sale of assets (4) (1) (4) — Gain (loss) on derivative instruments (232) 16 (120) 16 Net cash received in settlement of derivative instruments 35 36 13 62 Stock-based compensation and other 15 13 30 25 Income charges not requiring cash (5) (5) (9) (9) Changes in assets and liabilities (12) (167) (3) (108) Net cash provided by operating activities 937 558 2,080 1,414 CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures for drilling, completion and other fixed asset additions (620) (479) (1,092) (936) Capital expenditures for leasehold and property acquisitions (20) (2) (57) (3) Cash consideration paid for business combinations, net of cash received (3) — (3,222) — Purchases of short-term investments — — — (250) Proceeds from sale of assets 4 1 4 1 Other (3) — (3) — Net cash used in investing activities (642) (480) (4,370) (1,188) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from issuance of debt 350 — 1,350 499 Repayments of debt (450) — (700) — Common stock repurchases (23) (140) (47) (290) Dividends paid (168) (156) (346) (314) Tax withholding on vesting of stock awards (3) — (24) — Other (5) (1) (4) (7) Net cash provided by (used in) financing activities (299) (297) 229 (112) Net (decrease) increase in cash, cash equivalents and restricted cash $ (4) $ (219) $ (2,061) $ 114 14 Supplemental Non-GAAP Financial Measures (Unaudited) We report our financial results in accordance with accounting principles generally accepted in the United States (GAAP). However, we believe certain non-GAAP performance measures may provide financial statement users with additional meaningful comparisons between current results and results of prior periods. In addition, we believe these measures are used by analysts and others in the valuation, rating and investment recommendations of companies within the oil and natural gas exploration and production industry. See the reconciliations below that compare GAAP financial measures to non-GAAP financial measures for the periods indicated. We have also included herein certain forward-looking non-GAAP financial measures, including, among others, the reinvestment rate, which is defined as capital expenditures (non-GAAP) as a percentage of Discretionary Cash Flow (non-GAAP). We believe the reinvestment rate provides investors with useful information on management's projected use and reinvestment of its future cash flows back into Coterra's operations. Due to the forward-looking nature of these non-GAAP financial measures, we cannot reliably predict certain of the necessary components of the most directly comparable forward-looking GAAP measures, such as changes in assets and liabilities (including future impairments) and cash paid for certain capital expenditures. Accordingly, we are unable to present a quantitative reconciliation of such forward-looking non-GAAP financial measures to their most directly comparable forward-looking GAAP financial measures. Reconciling items in future periods could be significant. Reconciliation of Net Income to Adjusted Net Income and Adjusted Earnings Per Share Adjusted Net Income and Adjusted Earnings per Share are presented based on our management's belief that these non-GAAP measures enable a user of financial information to understand the impact of identified adjustments on reported results. Adjusted Net Income is defined as net income plus gain and loss on sale of assets, non-cash gain and loss on derivative instruments, stock-based compensation expense, severance expense, and tax effect on selected items. Adjusted Earnings per Share is defined as Adjusted Net Income divided by weighted-average common shares outstanding. Additionally, we believe these measures provide beneficial comparisons to similarly adjusted measurements of prior periods and use these measures for that purpose. Adjusted Net Income and Adjusted Earnings per Share are not measures of financial performance under GAAP and should not be considered as alternatives to net income and earnings per share, as defined by GAAP. Quarter Ended June 30, Six Months Ended June 30, (In millions, except per share amounts) 2025 2024 2025 2024 As reported - net income $ 511 $ 220 $ 1,027 $ 572 Reversal of selected items: Gain on sale of assets (4) (1) (4) — (Gain) loss on derivative instruments (1) (197) 52 (107) 78 Stock-based compensation expense 14 16 30 29 Acquisition related expense 1 — 14 — Tax effect on selected items 42 (15) 18 (24) Adjusted net income $ 367 $ 272 $ 978 $ 655 As reported - earnings per share $ 0.67 $ 0.30 $ 1.35 $ 0.77 Per share impact of selected items (0.19) 0.07 (0.06) 0.11 Adjusted earnings per share $ 0.48 $ 0.37 $ 1.29 $ 0.88 Weighted-average common shares outstanding 763 742 759 746 _______________________________________________________________________________ (1) This amount represents the non-cash mark-to-market changes of our commodity derivative instruments recorded in Gain (loss) on derivative instruments in the Condensed Consolidated Statement of Operations. 15 Reconciliation of Discretionary Cash Flow and Free Cash Flow Discretionary Cash Flow is defined as cash flow from operating activities excluding changes in assets and liabilities. Discretionary Cash Flow is widely accepted as a financial indicator of an oil and gas company’s ability to generate available cash to internally fund exploration and development activities, return capital to shareholders through dividends and share repurchases, and service debt and is used by our management for that purpose. Discretionary Cash Flow is presented based on our management’s belief that this non-GAAP measure is useful information to investors when comparing our cash flows with the cash flows of other companies that use the full cost method of accounting for oil and gas producing activities or have different financing and capital structures or tax rates. Discretionary Cash Flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities or net income, as defined by GAAP, or as a measure of liquidity. Free Cash Flow is defined as Discretionary Cash Flow less cash paid for capital expenditures. Free Cash Flow is an indicator of a company’s ability to generate cash flow after spending the money required to maintain or expand its asset base, and is used by our management for that purpose. Free Cash Flow is presented based on our management’s belief that this non-GAAP measure is useful information to investors when comparing our cash flows with the cash flows of other companies. Free Cash Flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities or net income, as defined by GAAP, or as a measure of liquidity. Quarter Ended June 30, Six Months Ended June 30, (In millions) 2025 2024 2025 2024 Cash flow from operating activities 937 $ 558 $ 2,080 $ 1,414 Changes in assets and liabilities 12 167 3 108 Discretionary cash flow 949 725 2,083 1,522 Cash paid for capital expenditures for drilling, completion and other fixed asset additions (620) (479) (1,092) (936) Free Cash Flow $ 329 $ 246 $ 991 $ 586 Reconciliation of Capital Expenditures Capital expenditures is defined as cash paid for capital expenditures for drilling, completion and other fixed asset additions less changes in accrued capital costs. Quarter Ended June 30, Six Months Ended June 30, (In millions) 2025 2024 2025 2024 Cash paid for capital expenditures for drilling, completion and other fixed asset additions (GAAP) $ 620 $ 479 $ 1,092 $ 936 Change in accrued capital costs (51) (2) 29 (9) Capital expenditures for drilling, completion and other fixed asset additions (non-GAAP) $ 569 $ 477 $ 1,121 $ 927 16 Reconciliation of Adjusted EBITDAX Adjusted EBITDAX is defined as net income plus interest expense, interest income, income tax expense, depreciation, depletion, and amortization (including impairments), exploration expense, gain and loss on sale of assets, non-cash gain and loss on derivative instruments, stock-based compensation expense, and acquisition-related expenses. Adjusted EBITDAX is presented on our management’s belief that this non-GAAP measure is useful information to investors when evaluating our ability to internally fund exploration and development activities and to service or incur debt without regard to financial or capital structure. Our management uses Adjusted EBITDAX for that purpose. Adjusted EBITDAX is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities or net income, as defined by GAAP, or as a measure of liquidity. Quarter Ended June 30, Six Months Ended June 30, (In millions) 2025 2024 2025 2024 Net income $ 511 $ 220 $ 1,027 $ 572 Plus (less): Interest expense 53 34 106 53 Interest income (2) (19) (10) (35) Other income (1) — (1) — Income tax expense 147 61 288 146 Depreciation, depletion and amortization 579 447 1,085 879 Exploration 4 5 14 10 Gain on sale of assets (4) (1) (4) — Non-cash (gain) loss on derivative instruments (197) 52 (107) 78 Acquisition-related expenses 1 — 14 — Stock-based compensation 14 16 30 29 Adjusted EBITDAX $ 1,105 $ 815 $ 2,442 $ 1,732 Trailing Twelve Months Ended (In millions) June 30, 2025 December 31, 2024 Net income $ 1,576 $ 1,121 Plus (less): Interest expense 159 106 Interest income (37) (62) Other expense (1) — Income tax expense 366 224 Depreciation, depletion and amortization 2,046 1,840 Exploration 29 25 Gain on sale of assets (7) (3) Non-cash (gain) loss on derivative instruments (84) 101 Acquisition-related expenses 14 — Stock-based compensation 63 62 Adjusted EBITDAX (trailing twelve months) $ 4,124 $ 3,414 17 Reconciliation of Adjusted Pro Forma EBITDAX Adjusted Pro Forma EBITDAX is defined as pro forma net income plus pro forma interest expense, pro forma interest income, pro forma income tax expense, pro forma depreciation, depletion, and amortization (including impairments), pro forma exploration expense, pro forma gain and loss on sale of assets, pro forma non-cash gain and loss on derivative instruments, pro forma acquisition-related expenses, and pro forma stock-based compensation expense. Adjusted Pro Forma EBITDAX represents the effects of the Franklin Mountain Energy and Avant Natural Resources acquisitions as if they had occurred on January 1, 2024. Adjusted Pro Forma EBITDAX is presented on our management’s belief that this non-GAAP measure is useful information to investors when evaluating our ability to internally fund exploration and development activities and to service or incur debt after the acquisitions without regard to financial or capital structure. Our management uses Adjusted Pro Forma EBITDAX for that purpose. Adjusted Pro Forma EBITDAX is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities, pro forma net income or net income, as defined by GAAP, or as a measure of liquidity. Trailing Twelve Months Ended (In millions) June 30, 2025 December 31, 2024 Pro forma net income $ 1,795 $ 1,475 Plus (less): Pro forma interest expense 234 250 Pro forma interest income (37) (62) Pro forma other income (1) — Pro forma income tax expense 404 297 Pro forma depreciation, depletion and amortization 2,267 2,195 Pro forma exploration 29 25 Pro forma gain on sale of assets (7) (3) Pro forma non-cash (gain) loss on derivative instruments (84) 101 Pro forma acquisition-related expenses 14 14 Pro forma stock-based compensation 63 62 Adjusted Pro Forma EBITDAX (trailing twelve months) $ 4,677 $ 4,354 18 Reconciliation of Net Debt The total debt to total capitalization ratio is calculated by dividing total debt by the sum of total debt and total stockholders’ equity. This ratio is a measurement which is presented in our annual and interim filings and our management believes this ratio is useful to investors in assessing our leverage. Net Debt is calculated by subtracting cash and cash equivalents and short-term investments from total debt. The Net Debt to Adjusted Capitalization ratio is calculated by dividing Net Debt by the sum of Net Debt and total stockholders’ equity. Net Debt and the Net Debt to Adjusted Capitalization ratio are non-GAAP measures which our management believes are also useful to investors when assessing our leverage since we have the ability to and may decide to use a portion of our cash and cash equivalents and short-term investments to retire debt. Our management uses these measures for that purpose. Additionally, as our planned expenditures are not expected to result in additional debt, our management believes it is appropriate to apply cash and cash equivalents and short-term investments to reduce debt in calculating the Net Debt to Adjusted Capitalization ratio. (In millions) June 30, 2025 December 31, 2024 Long-term debt, net 4,175 3,535 Total debt 4,175 3,535 Stockholders’ equity 14,556 13,122 Total capitalization $ 18,731 $ 16,657 Total debt $ 4,175 $ 3,535 Less: Cash and cash equivalents (192) (2,038) Net debt $ 3,983 $ 1,497 Net debt $ 3,983 $ 1,497 Stockholders’ equity 14,556 13,122 Total adjusted capitalization $ 18,539 $ 14,619 Total debt to total capitalization ratio 22.3 % 21.2 % Less: Impact of cash and cash equivalents 0.8 % 11.0 % Net debt to adjusted capitalization ratio 21.5 % 10.2 % Reconciliation of Net Debt to Adjusted EBITDAX Total debt to net income is defined as total debt divided by net income. Net debt to Adjusted EBITDAX is defined as net debt divided by trailing twelve month Adjusted EBITDAX. Net debt to Adjusted EBITDAX is a non-GAAP measure which our management believes is useful to investors when assessing our credit position and leverage. (In millions) June 30, 2025 December 31, 2024 Total debt $ 4,175 $ 3,535 Net income 1,576 1,121 Total debt to net income ratio 2.6 x 3.2 x Net debt (as defined above) $ 3,983 $ 1,497 Adjusted EBITDAX (Trailing twelve months) $ 4,124 $ 3,414 Net debt to Adjusted EBITDAX 1.0 x 0.4 x 19 Reconciliation of Net Debt to Adjusted Pro Forma EBITDAX Total debt to net income is defined as total debt divided by net income. Net debt to Adjusted Pro Forma EBITDAX is defined as net debt divided by trailing twelve month Adjusted Pro Forma EBITDAX. Net debt to Adjusted Pro Forma EBITDAX is a non-GAAP measure which our management believes is useful to investors when assessing our credit position and leverage. (In millions) June 30, 2025 December 31, 2024 Total debt $ 4,175 $ 3,535 Net income 1,576 1,121 Total debt to net income ratio 2.6 x 3.2 x Net debt (as defined above) $ 3,983 $ 1,497 Adjusted Pro Forma EBITDAX (Trailing twelve months) 4,677 4,354 Net debt to Adjusted Pro Forma EBITDAX 0.9 x 0.3 x 20 2025 Guidance The tables below present full-year and quarterly 2025 guidance. Full Year Guidance 2025 Guidance (February) Updated 2025 Guidance Low Mid High Low Mid High Total Equivalent Production (MBoed) 710 — 740 — 770 755 — 768 — 780 Gas (Mmcf/day) 2,675 — 2,775 — 2,875 2,875 — 2,913 — 2,950 Oil (MBbl/day) 152 — 160 — 168 157 — 160 — 163 Net wells turned in line Marcellus Shale 10 — 13 — 15 No change Permian Basin 150 — 158 — 165 No change Anadarko Basin 15 — 20 — 25 No change Capital expenditures ($ in millions) Total Company $2,100 — $2,250 — $2,400 $2,100 — $2,200 — $2,300 Drilling and completion Marcellus Shale $250 midpoint $350 Permian Basin $1,570 midpoint $1,520 Anadarko Basin $230 midpoint $230 Midstream, saltwater disposal and infrastructure $200 midpoint $200 Commodity price assumptions: WTI ($ per bbl) $71 $66 Henry Hub ($ per mmbtu) $4.22 $3.67 Cash Flow & Investment ($ in billions) Discretionary Cash Flow $5.0 $4.4 Capital Expenditures $2.1 — $2.3 — $2.4 $2.1 — $2.2 — $2.3 Free Cash Flow (DCF - incurred capex) $2.7 $2.1 $ per boe, unless noted: Lease operating expense + workovers + region office $2.50 — $3.05 — $3.60 No change Gathering, processing, & transportation $3.25 — $3.75 — $4.25 No change Taxes other than income $1.25 — $1.50 — $1.75 No change General & administrative (1) $0.90 — $1.00 — $1.10 No change Unit Operating Cost $7.90 — $9.30 — $10.70 No change _______________________________________________________________________________ (1) Excludes stock-based compensation and severance expense 21 Quarterly Guidance Second Quarter 2025 Guidance Second Quarter 2025 Actual Third Quarter 2025 Guidance Low Mid High Low Mid High Total Equivalent Production (MBoed) 710 — 735 — 760 783.9 740 — 765 — 790 Gas (Mmcf/day) 2,700 — 2,775 — 2,850 2,998.6 2,750 — 2,825 — 2,900 Oil (MBbl/day) 147 — 152 — 157 155.4 158 — 163 — 168 Net wells turned in line Marcellus Shale 3 3 4 Permian Basin 45 — 55 — 65 49 40 — 45 — 50 Anadarko Basin 9 9 6 Capital expenditures ($ in millions) Total Company $575 — $613 — $650 $569 $625 — $650 — $675 22 Investor Contact Daniel Guffey - Vice President of Finance, IR & Treasurer 281.589.4875 Hannah Stuckey - Investor Relations Manager 281.589.4983 23

the item shown at left

other guidance in this release

Text is the filed exhibit, verbatim.