The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the accompanying consolidated financial statements and related notes. The following discussion and analysis contain forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those factors discussed in “Cautionary Statement Concerning Forward-Looking Statements” and under the heading “Item 1A. Risk Factors” in this Quarterly Report and the 2025 Annual Report; all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may or may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law. Overview Permian Resources Corporation is an independent oil and natural gas company focused on driving returns to our stockholders through the acquisition, optimization and development of high-return oil and natural gas properties. Our assets and operations are located in the Permian Basin, with a concentration in the core of the Delaware Basin. Our principal business objective is to increase shareholder value by efficiently developing our oil and natural gas assets, with an overall objective of improving our rates of return and generating sustainable free cash flow. Unless otherwise specified or the context otherwise requires, all references in these discussions to “Permian Resources,” “we,” “us,” or “our” are to Permian Resources Corporation and its consolidated subsidiaries, including Permian Resources Operating, LLC (“OpCo”). Market Conditions Our revenue, profitability and ability to return cash to stockholders can depend substantially on factors beyond our control, such as economic, political and regulatory developments. Prices for crude oil, NGLs and natural gas have experienced significant fluctuations in recent years and may continue to fluctuate widely in the future. Oil prices declined through the end of 2025 and into early 2026, reflecting concerns regarding global economic growth, elevated interest rates, persistent inflation, increased global oil supply, and evolving tariffs and international trade policies. While global demand remained relatively strong and geopolitical risks persisted, higher‑than‑anticipated production increases from OPEC and the potential impact on global inventory levels contributed to additional downward pressure on prices during this period. More recently, oil prices have increased, with NYMEX WTI prices reaching a high of $112.95 per barrel on April 7, 2026, driven primarily by supply disruptions associated with heightened geopolitical tensions in the Middle East, including disruptions to key shipping routes in the Strait of Hormuz and the Red Sea, which has adversely affected global supply conditions. Significant uncertainty remains regarding the ability to resolve these conflicts, reopen trade and shipping routes and their ultimate impact on global oil supply and prices. Throughout 2025 and 2026, natural gas prices in the Permian Basin have been adversely impacted by low demand as a result of pipeline capacity constraints out of the basin, pipeline maintenance, and higher production levels. These factors have led to lower or, during certain periods, negative regional gas prices being realized for natural gas sales at the Waha Hub in West Texas. Notably during the second quarter of 2026, Waha natural gas prices averaged negative $3.14 per Mcf and traded as low as negative $9.52 per Mcf on April 16, 2026. The oil and natural gas industry is cyclical, and it is likely that commodity prices, as well as commodity price differentials, will continue to be volatile due to fluctuations in global supply and demand, inventory levels, geopolitical events and conflicts, federal and state government regulations, weather conditions, growth in alternative energy sources, supply chain constraints and other factors. The following table highlights the quarterly average price trends for NYMEX WTI spot prices for crude oil and NYMEX Henry Hub index price for natural gas since the first quarter of 2024: 2024 2025 2026 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Crude oil (per Bbl) $ 76.96 $ 80.55 $ 75.16 $ 70.28 $ 71.42 $ 63.71 $ 64.95 $ 59.13 $ 71.93 $ 92.85 Natural gas (per MMBtu) $ 2.41 $ 2.04 $ 2.08 $ 2.42 $ 4.27 $ 3.16 $ 3.07 $ 3.69 $ 4.84 $ 2.93 Lower commodity prices and lower futures curves for oil and gas prices can result in impairments of our proved oil and natural gas properties or undeveloped acreage and may materially and adversely affect our operating cash flows, liquidity, financial condition, results of operations, future business and operations, and/or our ability to finance planned capital expenditures. 29 Table of Contents Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. The cost of oilfield goods and services are closely linked to commodity price trends, rising when prices increase and decreasing when prices fall. In addition, the U.S. saw higher levels of inflation during 2025 and 2026 due to concerns, among other things, over international conflicts, tariffs, potential sanctions and trade policies. Inflationary pressures such as these may also result in increases to the costs of our oilfield goods, services and personnel, which can in turn cause our capital expenditures and operating costs to rise. 2026 Highlights Corporation Reorganization On January 7, 2026, we completed a corporate reorganization pursuant to which we, among other things, reorganized under a new public holding company (the “Reorganization”). In connection with the Reorganization, the public holding company prior to the Reorganization became a wholly owned subsidiary of the new public holding company, which, following completion of the Reorganization, changed its name to “Permian Resources Corporation,” became the successor issuer of the prior public holding company and replaced the prior public holding company, with its shares of Class A Common Stock continuing to trade on the NYSE on an uninterrupted basis. In connection with the Reorganization, certain holders of our Class C Common Stock exchanged all of their Common Units for Class A Common Stock on a one-for-one basis (and their corresponding shares of Class C Common Stock were cancelled for no consideration). Separate from and subsequent to the Reorganization, the remaining Class C Common stockholders exchanged all of their outstanding Common Units for Class A Common Stock, which fully eliminated our noncontrolling interest as of March 31, 2026. 2026 Bolt-On Acquisitions During the six months ended June 30, 2026, we completed multiple acquisitions of oil and natural gas properties for a cumulative adjusted purchase price of approximately $482.3 million. These acquisitions are part of our ongoing bolt-on and grassroots acquisition programs. Subsequently on July 31, 2026, we completed an acquisition of approximately 20,500 net leasehold acres and approximately 950 net royalty acres inclusive of both operated and non-operated wells and associated infrastructure for an unadjusted purchase price of $520.0 million. The acreage acquired is located in Ward County, Texas, directly offset our existing position in the core of the Southern Delaware Basin, which allows for seamless integration into our existing operations and provides for extended lateral lengths in future drilling and completion locations and higher working interest on existing properties. Return of Capital Program We have declared and paid quarterly base dividends of $0.16 per share of Class A Common Stock each quarter for a total of $0.32 per share for the six months ended June 30, 2026. The cash dividends paid totaled $269.1 million for the six months ended June 30, 2026. Financing During the first quarter of 2026, we achieved investment grade corporate and issuer credit ratings from Standard & Poor’s Financial Services LLC (“S&P”). Subsequently, on April 1, 2026, we achieved investment grade corporate and issuer credit ratings from Moody’s Ratings (“Moody’s”). Previously, in July 2025, we achieved investment grade corporate and issuer credit ratings from Fitch Ratings Inc. (“Fitch”). As a result, we are now rated investment grade by all three rating agencies, which we believe reflects the strength of our balance sheet, our disciplined acquisition and capital financing, and our growing scale. We anticipate this achievement will result in reduced interest expense, improved access to capital markets, and enhanced liquidity, among other benefits. On April 15, 2026, we redeemed all of our outstanding 8.00% senior notes due 2027 at a redemption price equal to 100% of the aggregate principal amount outstanding of $550 million plus accrued and unpaid interest up to, but excluding, the redemption date. On April 30, 2026, we entered into a new credit agreement with a syndicate of banks that provides for a $3.0 billion senior unsecured revolving credit facility maturing on April 30, 2031 (the “Credit Agreement”). In connection with entering into the Credit Agreement, we terminated our existing secured revolving credit facility without penalty. Refer to Liquidity and Capital Resources for additional information regarding the Credit Agreement. On July 15, 2026, we redeemed all of the outstanding 9.875% senior notes due 2031 at a redemption price equal to 104.938% of the aggregate principal amount outstanding of $325.0 million plus accrued and unpaid interest up to, but excluding, the redemption date. 30 Table of Contents Results of Operations Three Months Ended June 30, 2026 Compared to Three Months Ended June 30, 2025 The following table provides the components of our net revenues and net production (net of all royalties, overriding royalties and production due to others) for the periods indicated, as well as each period’s average prices and average daily production volumes: Three Months Ended June 30, Increase/(Decrease) 2026 2025 $ % Net revenues (in thousands): Oil sales $ 1,762,893 $ 1,007,450 $ 755,443 75 % NGL sales 182,570 158,019 24,551 16 % Natural gas sales (120,702) 30,172 (150,874) (500) % Purchased gas sales, net 33,274 1,955 31,319 1,602 % Oil and gas sales $ 1,858,035 $ 1,197,596 $ 660,439 55 % Net production: Oil (MBbls) 18,024 16,064 1,960 12 % NGL (MBbls) 7,843 8,900 (1,057) (12) % Natural gas (MMcf) 50,313 60,486 (10,173) (17) % Total (MBoe)(1) 34,253 35,046 (793) (2) % Average daily net production: Oil (Bbls/d) 198,071 176,533 21,538 12 % NGL (Bbls/d) 86,191 97,804 (11,613) (12) % Natural gas (Mcf/d) 552,885 664,686 (111,801) (17) % Total (Boe/d)(1) 376,409 385,118 (8,709) (2) % Average sales prices: Oil (per Bbl) $ 97.81 $ 62.71 $ 35.10 56 % Effect of derivative settlements on average price (per Bbl) (12.44) 2.61 (15.05) (577) % Oil including the effects of hedging (per Bbl) $ 85.37 $ 65.32 $ 20.05 31 % NGL (per Bbl) $ 23.28 $ 17.75 $ 5.53 31 % Natural gas (per Mcf) $ (2.40) $ 0.50 $ (2.90) (580) % Effect of derivative settlements on average price (per Mcf) 2.12 0.23 1.89 822 % Effect of purchased gas sales on average price (per Mcf) 0.66 0.03 0.63 2,100 % Natural gas including the effects of hedging (per Mcf) $ 0.38 $ 0.76 $ (0.38) (50) % (1) Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe. 31 Table of Contents Oil and Gas Sales. Total net revenues for the three months ended June 30, 2026, were $660.4 million (or 55%) higher than total net revenues for the three months ended June 30, 2025. Revenues are primarily a function of oil, NGL and natural gas volumes sold and average commodity prices realized. Average realized sales prices for oil and NGLs increased by 56% and 31%, respectively, between periods. The 56% increase in the average realized oil price was mainly the result of higher NYMEX WTI crude prices during the three months ended June 30, 2026, compared to the same 2025 period, driven primarily by supply disruptions associated with heightened geopolitical tensions in the Middle East, as discussed in the “Market Conditions” section above. The 31% increase in the average realized NGL price was primarily attributable to higher Mont Belvieu spot prices for plant products in the second quarter of 2026 compared to the same 2025 period. These increases were partially offset by lower realized sales prices for natural gas, which decreased to negative $2.40 per Mcf in the second quarter of 2026 compared to $0.50 per Mcf in the second quarter of 2025 due to negative regional market prices as discussed under the “Market Conditions” section above. The negative gas price realized during the three months ended June 30, 2026, was mitigated in part by $33.3 million in net proceeds from our purchased gas sales, which facilitate additional gas sales at markets that had more favorable pricing during the period. Net production volumes for oil also increased by 12% between periods. This increase in oil production resulted from additional production added from wells placed online since the second quarter of 2025 that were partially offset by normal production declines across our existing wells. NGLs and natural gas are produced concurrently with our crude oil volumes, which typically results in a high correlation between fluctuations in oil quantities sold and NGL and natural gas quantities sold. However, NGL and natural gas volumes decreased 12% and 17%, respectively, between periods, reflecting production curtailments of certain wells with higher gas-to-oil production ratios during periods of negative natural gas prices. Operating Expenses. The following table sets forth selected operating expense data for the periods indicated: Three Months Ended June 30, Increase/(Decrease) 2026 2025 Change % Operating costs (in thousands): Lease operating expenses $ 189,956 $ 187,972 $ 1,984 1 % Severance and ad valorem taxes 143,743 94,930 48,813 51 % Gathering, processing and transportation expenses 36,538 55,754 (19,216) (34) % Operating cost metrics: Lease operating expenses (per Boe) $ 5.55 $ 5.36 $ 0.19 4 % Severance and ad valorem taxes (% of revenue) 7.7 % 7.9 % (0.2) % (3) % Gathering, processing and transportation expenses (per Boe) $ 1.07 $ 1.59 $ (0.52) (33) % Lease Operating Expenses. Lease operating expenses (“LOE”) for the three months ended June 30, 2026, compared to the three months ended June 30, 2025, stayed relatively consistent while our LOE per Boe for the second quarter of 2026 increased 4% to $5.55 from $5.36 during the second quarter of 2025. The increase in our LOE per Boe rate was primarily driven by the decrease in total production volumes between periods as discussed above. Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the three months ended June 30, 2026, increased $48.8 million compared to the three months ended June 30, 2025. Severance taxes are based on the market value of our production at the wellhead, while ad valorem taxes are generally based on the assessed taxable value of our proved developed oil and gas properties and vary across the different counties in which we operate. Severance taxes for the second quarter of 2026 increased $51.1 million, or 64%, compared to the same 2025 period primarily due to the 55% higher total oil and gas sales between periods. This increase was partially offset by ad valorem taxes that decreased $2.3 million for the second quarter of 2026 compared to the same 2025 period primarily due to lower ad valorem tax assessments between periods, which also drove the decrease in our severance and ad valorem taxes as a percentage of revenues between periods. 32 Table of Contents Gathering, Processing and Transportation Expenses. Gathering, processing and transportation costs (“GP&T”) for the three months ended June 30, 2026, decreased $19.2 million as compared to the three months ended June 30, 2025. This decrease in expense was mainly attributable to lower NGL and natural gas volumes sold between periods, which in turn resulted in a lower amount of plant processing fees and gathering costs being incurred. Additionally, the decrease was the result of changes to certain gathering agreements resulting in a greater portion of gathering, processing and transportation fees being reflected as a net reduction to our NGL and natural gas sales than as GP&T expense. Our GP&T per Boe rate decreased to $1.07 for the three months ended June 30, 2026, from $1.59 for the three months ended June 30, 2025, driven primarily by the changes in our gathering agreements and by NGL and natural gas volumes declining more than our total production volumes between periods. Refer to Note 12—Revenues under Part I, Item 1 of this Quarterly Report for additional information regarding our treatment of GP&T fees. Depreciation, Depletion and Amortization. The following table summarizes our depreciation, depletion and amortization (“DD&A”) for the periods indicated: Three Months Ended June 30, (in thousands, except per Boe data) 2026 2025 Depreciation, depletion and amortization $ 500,160 $ 506,410 Depreciation, depletion and amortization per Boe $ 14.60 $ 14.45 For the three months ended June 30, 2026, DD&A expense amounted to $500.2 million, a decrease of $6.3 million over the same 2025 period. The primary factor contributing to lower DD&A expense in 2026 was the decrease in our overall production volumes between periods, which decreased DD&A expense by $11.5 million, while our slightly higher DD&A rate of $14.60 per Boe increased DD&A expense by $5.2 million between periods. Our DD&A rate can fluctuate as a result of finding and development costs incurred, acquisitions, and impairments, as well as changes in proved developed and proved undeveloped reserves. General and Administrative Expenses. The following table summarizes our general and administrative (“G&A”) expenses for the periods indicated: Three Months Ended June 30, (in thousands) 2026 2025 Cash general and administrative expenses $ 29,754 $ 30,546 Stock-based compensation 18,199 19,293 General and administrative expenses $ 47,953 $ 49,839 Cash general and administrative expenses per Boe $ 0.87 $ 0.87 G&A expenses for the three months ended June 30, 2026, were $48.0 million compared to $49.8 million for the three months ended June 30, 2025. Lower G&A for the second quarter of 2026 compared to the same 2025 period was primarily the result of a $1.1 million decrease in stock-based compensation between periods based on the timing of grants and the vesting of our equity awards. Interest Expense. The following table summarizes our interest expense for the periods indicated: Three Months Ended June 30, (in thousands) 2026 2025 Credit facility $ 2,678 $ 2,379 5.375% Senior Notes due 2026 — 3,882 8.00% Senior Notes due 2027 1,711 11,000 3.25% Convertible Senior Notes due 2028 — 1,381 5.875% Senior Notes due 2029 10,281 10,281 9.875% Senior Notes due 2031 8,023 8,023 7.00% Senior Notes due 2032 17,500 17,500 6.25% Senior Notes due 2033 15,625 15,625 Amortization of debt issuance costs, discount and premium 2,743 2,160 Other interest expense 1,087 539 Total $ 59,648 $ 72,770 33 Table of Contents Interest expense decreased $13.1 million for the three months ended June 30, 2026, as compared to the three months ended June 30, 2025, primarily due to less interest incurred on our senior notes that were redeemed since June 30, 2025. Refer to Note 4—Long-Term Debt under Part I, Item 1 of this Quarterly Report for additional information regarding our senior notes. Net Gain (Loss) on Derivative Instruments. Net gains and losses are a function of (i) changes in derivative fair values associated with fluctuations in the forward price curves for the commodities underlying each of our hedge contracts outstanding; and (ii) monthly cash settlements on any closed out hedge positions during the period. The following table presents gains and losses on our derivative instruments for the periods indicated: Three Months Ended June 30, (in thousands) 2026 2025 Realized cash settlement gains (losses) $ (117,412) $ 55,763 Non-cash mark-to-market derivative gain (loss) 256,558 17,256 Total $ 139,146 $ 73,019 Income Tax Expense. The following table summarizes our pre-tax income and income tax expense for the periods indicated: Three Months Ended June 30, (in thousands) 2026 2025 Income before income taxes $ 1,015,852 $ 307,507 Income tax expense (223,388) (62,486) For the three months ended June 30, 2026, we generated pre-tax net income of $1.0 billion and recorded income tax expense of $223.4 million. During the three months ended June 30, 2025, we generated pre-tax net income of $307.5 million and recorded income tax expense of $62.5 million. The primary factor decreasing our income tax expense below the U.S. statutory rate was the portion of pre-tax income attributable to our non-controlling interest partners that is not taxable to the Company. 34 Table of Contents Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025 The following table provides the components of our net revenues and net production (net of all royalties, overriding royalties and production due to others) for the periods indicated, as well as each period’s average prices and average daily production volumes: Six Months Ended June 30, Increase/(Decrease) 2026 2025 $ % Net revenues (in thousands): Oil sales $ 2,990,487 $ 2,117,221 $ 873,266 41 % NGL sales 336,963 343,041 (6,078) (2) % Natural gas sales (139,206) 111,830 (251,036) (224) % Purchased gas sales, net 57,937 1,955 55,982 2,864 % Oil and gas sales $ 3,246,181 $ 2,574,047 $ 672,134 26 % Net production: Oil (MBbls) 35,335 31,811 3,524 11 % NGL (MBbls) 17,143 16,641 502 3 % Natural gas (MMcf) 113,581 121,091 (7,510) (6) % Total (MBoe)(1) 71,409 68,635 2,774 4 % Average daily net production: Oil (Bbls/d) 195,226 175,754 19,472 11 % NGL (Bbls/d) 94,717 91,940 2,777 3 % Natural gas (Mcf/d) 627,517 669,013 (41,496) (6) % Total (Boe/d)(1) 394,529 379,196 15,333 4 % Average sales prices: Oil (per Bbl) $ 84.63 $ 66.56 $ 18.07 27 % Effect of derivative settlements on average price (per Bbl) (7.72) 1.80 (9.52) (529) % Oil including the effects of hedging (per Bbl) $ 76.91 $ 68.36 $ 8.55 13 % NGL (per Bbl) $ 19.66 $ 20.61 $ (0.95) (5) % Natural gas (per Mcf) $ (1.23) $ 0.92 $ (2.15) (234) % Effect of derivative settlements on average price (per Mcf) 1.63 0.16 1.47 919 % Effect of purchased gas sales on average price (per Mcf) 0.51 0.02 0.49 2,450 % Natural gas including the effects of hedging (per Mcf) $ 0.91 $ 1.10 $ (0.19) (17) % (1) Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe. 35 Table of Contents Oil and Gas Sales. Total net revenues for the six months ended June 30, 2026, were $672.1 million (or 26%) higher than total net revenues for the six months ended June 30, 2025. Revenues are primarily a function of oil, NGL and natural gas volumes sold and average commodity prices realized. The average realized sales price for oil increased by 27% between periods which was mainly the result of higher NYMEX WTI crude prices during the first half of 2026 compared to the same 2025 period. This increase was partially offset by lower realized sales prices for natural gas and NGLs, which decreased 234% and 5%, respectively, in the first half of 2026 compared to the same 2025 period. Our average realized natural gas price decreased to negative $1.23 per Mcf during the first half of 2026 compared to $0.92 per Mcf in the same 2025 period due to negative regional market prices as discussed under the “Market Conditions” section above. The negative gas price realized during the six months ended June 30, 2026, was mitigated in part by $57.9 million in net proceeds from our purchased gas sales, which facilitate additional gas sales at markets that had more favorable pricing during the period. The 5% decrease in the average realized NGL price was primarily attributable to lower Mont Belvieu spot prices for plant products for the first half of 2026 compared to the same 2025 period. Net production volumes for oil also increased 11% between periods as a result of additional production added from wells placed online since the second quarter of 2025, which was partially offset by normal production declines across our existing wells. NGLs and natural gas are produced concurrently with our crude oil volumes, which typically results in a high correlation between fluctuations in oil quantities sold and NGL and natural gas quantities sold. However, NGL volumes increased only 3% between periods, below the 11% increase in oil volumes, while natural gas volumes decreased 6% between periods. Lower NGL and natural gas volumes compared to oil during the period were the result of production curtailments of certain wells with higher gas-to-oil production ratios during periods of negative natural gas prices. Further, certain processors of our raw gas operated in higher ethane-recovery mode during the first half of 2026 as compared to the same 2025 period, resulting in a higher percentage of NGLs being recovered from our wet gas stream as compared to natural gas. Operating Expenses. The following table summarizes our operating expenses for the periods indicated: Six Months Ended June 30, Increase/(Decrease) 2026 2025 Change % Operating costs (in thousands): Lease operating expenses $ 382,838 $ 367,599 $ 15,239 4 % Severance and ad valorem taxes 245,055 202,923 42,132 21 % Gathering, processing and transportation expenses 87,177 102,404 (15,227) (15) % Operating cost metrics: Lease operating expenses (per Boe) $ 5.36 $ 5.36 $ — — % Severance and ad valorem taxes (% of revenue) 7.5 % 7.9 % (0.4) % (5) % Gathering, processing and transportation expenses (per Boe) $ 1.22 $ 1.49 $ (0.27) (18) % Lease Operating Expenses. LOE per Boe for the six months ended June 30, 2026 and 2025, stayed consistent at $5.36 during each period. While LOE per Boe remained unchanged, total LOE for the six months ended June 30, 2026, increased by $15.2 million compared to the six months ended June 30, 2025, and was the direct result of our higher well count between periods primarily due to additional wells placed on production since June 30, 2025. Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the six months ended June 30, 2026, increased $42.1 million compared to the six months ended June 30, 2025. Severance taxes are based on the market value of our production at the wellhead, while ad valorem taxes are generally based on the assessed taxable value of our proved developed oil and gas properties and vary across the different counties in which we operate. Severance taxes for the first half of 2026 increased $47.9 million, or 28%, compared to the same 2025 period primarily due to the 26% higher total oil and gas sales between periods. This increase was partially offset by ad valorem taxes that decreased $5.8 million for the first half of 2026 compared to the same 2025 period primarily due to lower ad valorem tax assessments between periods, which also drove the decrease in our severance and ad valorem taxes as a percentage of revenues between periods. Gathering, Processing and Transportation Expenses. Total GP&T expense for the six months ended June 30, 2026, decreased $15.2 million compared to the six months ended June 30, 2025. This decrease in expense was mainly attributable to lower natural gas volumes sold between periods, which in turn resulted in a lower amount of plant processing fees and gathering costs being incurred. Additionally, the decrease was the result of changes to certain gathering agreements resulting in a greater portion of gathering, processing and transportation fees being reflected as a net reduction to our NGL and natural gas sales than as GP&T expense. 36 Table of Contents Our GP&T per Boe rate decreased to $1.22 for the first half of 2026 from $1.49 for the first half of 2025, driven primarily by the changes in our gathering agreements and by our natural gas volumes declining more than our total production volumes between periods. Refer to Note 12—Revenues under Part I, Item 1 of this Quarterly Report for additional information regarding our treatment of GP&T fees. Depreciation, Depletion and Amortization. The following table summarizes our DD&A for the periods indicated: Six Months Ended June 30, (in thousands, except per Boe data) 2026 2025 Depreciation, depletion and amortization $ 1,026,448 $ 980,613 Depreciation, depletion and amortization per Boe $ 14.37 $ 14.29 For the six months ended June 30, 2026, DD&A expense amounted to $1.0 billion, an increase of $45.8 million over the same 2025 period. The primary factor contributing to higher DD&A expense in 2026 was the increase in our overall production volumes between periods, which increased DD&A expense by $39.6 million during the first half of 2026, while slightly higher DD&A rates between periods increased DD&A expense by $6.2 million for the six months ended June 30, 2026. Our DD&A rate can fluctuate as a result of finding and development costs incurred, acquisitions, impairments, as well as changes in proved developed and proved undeveloped reserves. General and Administrative Expenses. The following table summarizes our G&A expenses for the periods indicated: Six Months Ended June 30, (in thousands) 2026 2025 Cash general and administrative expenses $ 58,363 $ 57,403 Stock-based compensation expense 33,362 35,492 General and administrative expenses $ 91,725 $ 92,895 Cash general and administrative expenses per Boe $ 0.82 $ 0.84 G&A expenses for the six months ended June 30, 2026, were $91.7 million compared to $92.9 million for the six months ended June 30, 2025. Lower G&A for the first half of 2026 was the result of a $2.1 million decrease in stock-based compensation compared to the same 2025 period. Stock-based compensation fluctuates between periods based on the timing of grants and the vesting of our equity awards. This was partially offset by $1.0 million of higher cash G&A between periods, mainly related to our overall corporate growth. Interest Expense. The following table summarizes our interest expense for the periods indicated: Six Months Ended June 30, (in thousands) 2026 2025 Credit facility $ 4,996 $ 4,732 5.375% Senior Notes due 2026 — 7,771 8.00% Senior Notes due 2027 12,711 22,000 3.25% Convertible Senior Notes due 2028 — 2,762 5.875% Senior Notes due 2029 20,562 20,562 9.875% Senior Notes due 2031 16,046 17,151 7.00% Senior Notes due 2032 35,000 35,000 6.25% Senior Notes due 2033 31,250 31,250 Amortization of debt issuance costs, discount and premium 4,489 4,299 Other interest expense 1,614 1,082 Total $ 126,668 $ 146,609 Interest expense was $19.9 million lower for the six months ended June 30, 2026, compared to the same 2025 period primarily due to less interest incurred on our senior notes that were fully or partially redeemed or repurchased since June 30, 2025. Refer to Note 4—Long-Term Debt under Part I, Item 1 of this Quarterly Report for additional information regarding our senior notes. 37 Table of Contents Net Gain (Loss) on Derivative Instruments. Net gains and losses are a function of (i) changes in derivative fair values associated with fluctuations in the forward price curves for the commodities underlying each of our hedge contracts outstanding and (ii) monthly cash settlements on any closed out hedge positions during the period. The following table presents gains and losses on our derivative instruments for the periods indicated: Six Months Ended June 30, (in thousands) 2026 2025 Realized cash settlement gains (losses) $ (88,039) $ 77,071 Non-cash mark-to-market derivative gain (loss) (112,739) 53,679 Total $ (200,778) $ 130,750 Income Tax Expense. The following table summarizes our pre-tax income and income tax expense for the periods indicated: Six Months Ended June 30, (in thousands) 2026 2025 Income before income taxes $ 1,079,732 $ 798,404 Income tax expense (236,874) (162,820) For the six months ended June 30, 2026, we generated pre-tax net income of $1.1 billion and recorded income tax expense of $236.9 million. During the six months ended June 30, 2025, we generated pre-tax net income of $798.4 million and recorded income tax expense of $162.8 million. The primary factor decreasing our income tax expense below the U.S. statutory rate was the portion of pre-tax income attributable to our non-controlling interest partners that is not taxable to the Company. 38 Table of Contents Liquidity and Capital Resources Overview Our primary sources of liquidity have been cash flows from operations, borrowings under our credit facility, proceeds from offerings of debt or equity securities, or proceeds from the sale of oil and gas properties. Our future cash flows are subject to a number of variables, including oil and natural gas prices, which have been and will likely continue to be volatile. Lower commodity prices can negatively impact our cash flows and our ability to access debt or equity markets, and sustained low oil and natural gas prices could have a material and adverse effect on our liquidity position. To date, our primary uses of capital have been for drilling and development capital expenditures and the acquisition of oil and natural gas properties. During 2026, we achieved investment grade credit ratings from S&P and Moody’s. We previously achieved investment grade credit ratings from Fitch in 2025. We believe this achievement enhances our financial flexibility by broadening our access to investment grade debt markets, reducing our cost of borrowing, and expanding potential investors eligible to hold our indebtedness. We continually evaluate our capital needs and compare them to our capital resources. During the six months ended June 30, 2026, our total capital expenditures incurred for drilling and development activity were $987.7 million. We funded our capital expenditures for the six months ended June 30, 2026, entirely from cash flows from operations, and we expect to fund the remainder of our 2026 capital expenditures budget entirely from cash flows from operations given our anticipated level of oil and gas production, current commodity prices and our commodity hedge positions in place. We are the operator of a high percentage of our acreage and can control the amount and timing of our capital expenditures. Accordingly, we can choose to defer or accelerate a portion of our planned capital expenditures depending on a variety of factors, including but not limited to: (i) prevailing and anticipated prices for oil and natural gas; (ii) oil and gas storage or transportation constraints; (iii) the success of our drilling activities; (iv) the availability of necessary equipment, infrastructure and capital; (v) the receipt and timing of required regulatory permits and approvals; (vi) seasonal conditions; (vii) property or land acquisition costs; and (viii) the level of participation by other working interest owners. We plan to return capital to shareholders primarily through our base dividend, in addition to opportunistic share repurchases. During the six months ended June 30, 2026, we declared and paid quarterly dividends of $0.16 per share of Class A Common Stock for a total of $0.32 per share. The cash dividends paid totaled $269.1 million for the six months ended June 30, 2026. Our stock repurchase program can be used to reduce our shares of common stock outstanding. Such repurchases would be made at terms and prices determined by us based upon prevailing market conditions, applicable legal requirements, available liquidity, compliance with our debt agreements and other factors. In addition, we may, from time to time, seek to retire or purchase our outstanding senior notes through cash purchases and/or exchanges for debt in open-market purchases, privately negotiated transactions or otherwise. During the second quarter of 2026, we redeemed our 8.00% senior notes due 2027 at a redemption price equal to 100% of the $550.0 million principal amount outstanding, plus accrued and unpaid interest. Additionally, on July 15, 2026, we redeemed our 9.875% senior notes due 2031 at a redemption price equal to 104.938% of the $325.0 million principal amount outstanding, plus accrued and unpaid interest. Although we cannot provide any assurance that cash flows from operations or other sources of needed capital will be available to us at acceptable terms, or at all, and noting that our ability to access the public or private debt or equity capital markets at economic terms in the future will be affected by general economic conditions, the domestic and global oil and financial markets, our operational and financial performance, the value and performance of our debt or equity securities, prevailing commodity prices and other macroeconomic factors outside of our control, we believe that based on our current expectations and projections, we will have sufficient capital available to fund our capital expenditure requirements through the 12-month period following the filing of this Quarterly Report and the long-term. Additionally, our recently achieved investment grade credit ratings from each of S&P, Moody’s and Fitch are expected to further support our access to the debt capital markets at favorable terms. Analysis of Cash Flow Changes The following table summarizes our cash flows for the periods indicated: Six Months Ended June 30, (in thousands) 2026 2025 Net cash provided by operating activities $ 2,320,764 $ 1,936,728 Net cash used in investing activities (1,516,262) (1,485,129) Net cash used in financing activities (826,470) (479,940) 39 Table of Contents For the six months ended June 30, 2026, we generated $2.3 billion of cash from operating activities, an increase of $384.0 million from the same period in 2025. Cash provided by operating activities increased primarily due to higher realized prices and production volumes for oil, more purchased gas sales, less cash interest expense and lower GP&T expense during the six months ended June 30, 2026, as compared to the same 2025 period. These increasing factors were partially offset by lower realized prices for NGLs and natural gas, less realized cash settlements on our derivative contracts, higher severance and ad valorem taxes and lease operating expenses, as well as the timing of collections on our receivables during the six months ended June 30, 2026, as compared to the same 2025 period. Refer to “Results of Operations” for more information on the impact of volumes and prices on revenues and on fluctuations in our operating costs between periods. During the six months ended June 30, 2026, cash flows from operating activities and cash on hand were used to (i) fund $987.7 million of drilling and development cash capital expenditures; (ii) redeem $550.0 million of our senior notes; (iii) fund acquisitions of oil and gas properties of $534.3 million; and (iv) pay $269.1 million in dividends to our shareholders. During the six months ended June 30, 2025, cash flows from operating activities and proceeds of $176.0 million primarily from the sale of oil and natural gas gathering systems that were acquired during a prior year acquisition were used to (i) fund $1.0 billion of drilling and development cash capital expenditures; (ii) fund acquisitions of oil and gas properties of $650.3 million; (iii) pay $241.6 million in dividends and cash distributions to our shareholders and holders of our Common Units; (iv) redeem $177.7 million of our senior notes; and (v) repurchase $43.3 million of our Class A Common Stock. Credit Agreement We have a revolving Credit Agreement that provides for a senior unsecured revolving credit facility. As of June 30, 2026, we had no borrowings outstanding and $3.0 billion in available borrowing capacity under the Credit Agreement. The Credit Agreement has a scheduled maturity date of April 30, 2031, and includes an option to extend the term for successive one-year periods, subject to, among certain other terms and conditions, the consent of the lenders holding greater than 50% of the commitments then outstanding under the Credit Agreement. The Credit Agreement provides for aggregate commitments of $3.0 billion, with an option to request increases in the aggregate commitments to an amount not to exceed $4.0 billion, subject to certain terms and conditions and includes a swingline subfacility and a letter of credit subfacility. Borrowings under the Credit Agreement bear interest, at our election, based on either SOFR plus an applicable margin or the Alternate Base Rate plus an applicable margin. The applicable margins for SOFR and Alternate Base Rate borrowings, as well as commitment fees for undrawn commitments, are based on our credit rating for our long-term senior unsecured indebtedness. As of June 30, 2026, the applicable margin for SOFR and Alternate Base Rate Loans is 150 basis points and 50 basis points, respectively, and the commitment fee is 20 basis points. The Credit Agreement contains representations, warranties, covenants and events of default that we believe are customary for investment grade, senior unsecured commercial bank credit agreements, including a financial covenant for the maintenance of a ratio of Total Indebtedness to Capitalization Ratio (as defined in the Credit Agreement) of no greater than 65%. Senior Notes OpCo had $3.0 billion in debt outstanding as of June 30, 2026, consisting of senior unsecured notes with maturity dates ranging from 2029 to 2033. For further information on our debt instruments, refer to Note 4—Long-Term Debt under Part I, Item 1 of this Quarterly Report. Contractual Obligations Our contractual obligations include operating and transportation agreements, drilling rig contracts, office and equipment leases, asset retirement obligations, long-term debt obligations and cash interest expense on long-term debt obligations, which we routinely enter into, modify or extend. Since December 31, 2025, there have not been any significant, non-routine changes in our contractual obligations. Critical Accounting Policies and Estimates There have been no material changes to the critical accounting policies as disclosed in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates in our 2025 Annual Report. New Accounting Pronouncements Refer to Note 1—Basis of Presentation and Summary of Significant Accounting Policies under Part I, Item 1 of this Quarterly Report for a discussion of the potential effects of new accounting pronouncements. 40 Table of Contents