The following discussion and analysis of the Company’s financial condition and results of operations should be read in conjunction with the Company's condensed consolidated financial statements and related notes thereto presented in this report as well as the Company's audited consolidated financial statements and related notes included in the Company's Annual Report for the fiscal year ended December 31, 2025. The following discussion contains "forward-looking statements" that reflect the Company’s future plans, estimates, beliefs and expected performance. The Company’s actual results could differ materially from those discussed in these forward-looking statements. See "Cautionary Statement Regarding Forward-Looking Statements" and "Part II, Item 1A. Risk Factors" below and the information set forth in the Risk Factors under Part I, Item 1A of the Company's Annual Report for the fiscal year ended December 31, 2025. Overview Riley Permian is a growth-oriented, independent oil and natural gas company focused on horizontal drilling of conventional oil-saturated and liquids-rich formations in the Permian Basin that produce long-term cash flows. The majority of our acreage is located in Yoakum County, Texas and Eddy County, New Mexico. Our strategic business objectives include enhancing the rate of return on our invested capital, generating sustainable free cash flow, maintaining a strong and flexible balance sheet and maximizing returns to shareholders. We implement this strategy primarily through identification and capture of attractive development opportunities, optimization of our assets and pursuing complementary growth opportunities that increase our scale and meet our strategic and financial objectives. Recent Developments Geopolitical and Economic Conditions Commodity prices remain volatile. General domestic and international economic, market and political conditions, including military conflicts, global economic growth, unpredictability of new tariffs, actions of OPEC+ countries and changes to the current political environment could prolong market volatility and continue to cause a decline in commodity prices. We monitor the risk of cost pressures in specific areas of our operating expenses and capital expenditures. Our margins may be compressed if costs increase more than commodity prices and our revenues, net of derivatives. Additionally, the current interest rate environment remains sensitive to shifts in macroeconomic factors and central bank policies. Increased interest rates could have the effects of raising our cost of capital and the potential for depressing economic growth, either of which (or the combination thereof) could hurt the financial and operating results of our business. The Company cannot estimate the length or gravity of the future impact these events will have on the Company's results of operations, financial position, liquidity and the value of oil and natural gas reserves. Midstream Disruption During the second quarter of 2026, certain portions of our New Mexico operations continued to experience production interruptions and curtailments resulting from third-party midstream and gas processing constraints. Following the unplanned outage at a third-party gas processing facility that began in late March 2026, we continued to experience periodic processing limitations, maintenance-related curtailments, and reduced gas takeaway capacity affecting a portion of our New Mexico production during the quarter. These events resulted in the temporary shut-in of certain wells and reduced production from impacted areas. The temporary shut-in was substantially resolved by the end of May with production resuming to normal levels for June. The effects of these disruptions were partially mitigated by the limited geographic scope of the affected production, our ability to restore certain wells to production as processing capacity became available, and strong operating performance from our Texas assets. As a result, while the curtailments negatively impacted certain production volumes during the quarter, they did not materially affect our overall financial condition or liquidity. We continue to monitor the reliability and capacity of third-party midstream infrastructure serving our New Mexico acreage. To mitigate the risk of future processing and takeaway constraints of the nature experienced during the period, Targa is constructing new gathering and high-pressure trunkline infrastructure in Eddy County, New Mexico pursuant to the A&R Gas Purchase Agreement. Upon completion, this infrastructure is expected to provide increased gathering, processing, and takeaway capacity that reduces our reliance on the affected third-party processing facilities. The in-service date of the new Targa pipeline 31 system is currently expected to occur in the fourth quarter of 2026. See Note 15 – Commitments and Contingencies for additional information. Results of Operations Comparison for the three and six months ended June 30, 2026, and 2025: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 Revenues (in thousands):(1) Oil sales, net $ 182,249 $ 85,921 $ 307,217 $ 184,513 Natural gas sales, net (13,359) (874) (19,718) 710 NGL sales, net (3,040) 347 (7,768) 2,628 Oil and natural gas sales, net $ 165,850 $ 85,394 $ 279,731 $ 187,851 Production Data, net: Oil (MBbls) 1,933 1,382 3,747 2,788 Natural gas (MMcf) 3,241 2,213 7,022 4,441 NGLs (MBbls) 645 465 1,405 887 Total equivalent (MBoe) 3,118 2,216 6,322 4,415 Daily equivalent production (Boe/d) 34,264 24,352 34,928 24,392 Daily oil production (Bbls/d) 21,242 15,187 20,702 15,403 Average Realized Prices:(1) Oil ($ per Bbl) $ 94.28 $ 62.17 $ 81.99 $ 66.18 Natural gas ($ per Mcf) $ (4.12) $ (0.39) $ (2.81) $ 0.16 NGLs ($ per Bbl) $ (4.71) $ 0.75 $ (5.53) $ 2.96 Average Realized Prices, including the effects of derivative settlements:(1)(2) Oil ($ per Bbl) $ 74.25 $ 66.10 $ 68.51 $ 68.55 Natural gas ($ per Mcf) $ (3.33) $ (0.52) $ (2.44) $ 0.08 NGLs ($ per Bbl)(3) $ (4.71) $ 0.75 $ (5.53) $ 2.96 _____________________ (1)The Company's oil, natural gas and NGL sales are presented net of GP&T costs. These costs, related to natural gas and NGLs, at times exceeded the price received and resulted in negative average realized prices. (2)The Company's calculation of the effects of derivative settlements includes gains (losses) on the settlement of our commodity derivative contracts. These gains (losses), along with unrealized gains (losses) from changes in the fair value of derivatives, are included under other income (expense) on the Company’s condensed consolidated statements of operations. (3)During the periods presented, the Company did not have any NGL derivative contracts in place. 32 Oil and Natural Gas Revenues Our revenues are derived from the sale of our oil and natural gas production, including the sale of NGLs that are extracted from our natural gas during processing. Realized prices and revenues from product sales are a function of the volumes produced, product quality, market prices, gas Btu content, as well as GP&T costs. GP&T costs are allocated across natural gas and NGLs based on revenue, which leads to heightened fluctuations in such cost allocations across periods. Our revenues from oil, natural gas and NGL sales do not include the effects of derivatives. Our revenues may vary significantly from period to period as a result of changes in the volume of production sold or changes in commodity prices. The following table presents the Company's oil and natural gas sales prior to and net of GP&T costs: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 Revenues: (In thousands) Oil sales, net $ 182,249 $ 85,921 $ 307,217 $ 184,513 Natural gas sales $ (12,470) $ 2,102 $ (15,902) $ 6,582 Less: GP&T costs (889) (2,976) (3,816) (5,872) Natural gas sales, net $ (13,359) $ (874) $ (19,718) $ 710 NGL sales $ 14,167 $ 8,828 $ 27,028 $ 19,054 Less: GP&T costs (17,207) (8,481) (34,796) (16,426) NGL sales, net $ (3,040) $ 347 $ (7,768) $ 2,628 Oil and natural gas sales $ 183,946 $ 96,851 $ 318,343 $ 210,149 Less: GP&T costs (18,096) (11,457) (38,612) (22,298) Oil and natural gas sales, net $ 165,850 $ 85,394 $ 279,731 $ 187,851 Three months ended June 30, 2026, compared to three months ended June 30, 2025 The Company’s total oil and natural gas sales, net increased by $80.5 million or 94%. The following tables summarize the effects of price, volume and GP&T costs changes on our revenues from oil, natural gas and NGLs: Oil revenues Oil revenues increased by $96.3 million. Our realized oil prices increased by $32.11 per Bbl, which was the result of a $31.08 increase in the average WTI price. Average daily oil volumes increased by 40%, primarily due to new wells turned to sales and the contribution of the Silverback Acquisition. (In thousands) Oil sales, net for the three months ended June 30, 2025 $ 85,921 Price 62,072 Volume 34,256 Oil sales, net for the three months ended June 30, 2026 $ 182,249 33 Natural gas revenues Natural gas revenues decreased by $12.5 million driven by negative realized natural gas prices that more than offset an increase in production volumes. Our realized natural gas prices before GP&T costs decreased by $4.80 per Mcf, which was the result of an increase in negative Permian basis differentials due to regional pipeline constraints in addition to a $0.24 decrease in the average Henry Hub price. (In thousands) Natural gas sales, net for the three months ended June 30, 2025 $ (874) Price (15,548) Volume 976 GP&T costs 2,087 Natural gas sales, net for the three months ended June 30, 2026 $ (13,359) NGL revenues NGL revenues decreased by $3.4 million. Our realized NGL prices before GP&T costs increased by $2.98 per Bbl which was the result of an increase in the average Mont Belvieu prices realized. Our realized NGL prices net of GP&T costs decreased by $5.46 primarily due to higher allocated GP&T costs when realized natural gas prices are negative. (In thousands) NGL sales, net for the three months ended June 30, 2025 $ 347 Price 1,922 Volume 3,417 GP&T costs (8,726) NGL sales, net for the three months ended June 30, 2026 $ (3,040) Six months ended June 30, 2026, compared to six months ended June 30, 2025 The Company’s total oil and natural gas sales, net increased by $91.9 million or 49%. The following tables summarize the effects of price, volume and GP&T costs changes on our revenues from oil, natural gas and NGLs: Oil revenues Oil revenues increased by $122.7 million. Our realized oil prices increased by $15.81 per Bbl, which was the result of a $16.17 increase in the average WTI price. Daily oil volumes increased by 34%, primarily due to new wells turned to sales and the Silverback Acquisition. (In thousands) Oil sales, net for the six months ended June 30, 2025 $ 184,513 Price 59,236 Volume 63,468 Oil sales, net for the six months ended June 30, 2026 $ 307,217 Natural gas revenues Natural gas revenues decreased by $20.4 million driven by negative realized natural gas prices that more than offset an increase in production volumes. Our realized natural gas prices before GP&T costs decreased $3.75 per Mcf, which was the result of an increase in negative Permian basis differentials due to regional pipeline constraints, partially offset by a $0.15 increase in the average Henry Hub price. 34 (In thousands) Natural gas sales, net for the six months ended June 30, 2025 $ 710 Price (26,309) Volume 3,825 GP&T costs 2,056 Natural gas sales, net for the six months ended June 30, 2026 $ (19,718) NGL revenues NGL revenues decreased by $10.4 million. Our realized NGL prices before GP&T costs decreased by $2.24, per Bbl which was the result of a decrease in the average Mont Belvieu prices realized. Our realized NGL prices net of GP&T costs decreased by $8.49 primarily due to higher allocated GP&T costs when realized natural gas prices are negative. (In thousands) NGL sales, net for the six months ended June 30, 2025 $ 2,628 Price (3,153) Volume 11,127 GP&T costs (18,370) NGL sales, net for the six months ended June 30, 2026 $ (7,768) Costs and Expenses The following table presents the Company's operating costs and expenses and other (income) expenses: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 Costs and Expenses: (In thousands) Lease operating expenses $ 29,433 $ 18,880 $ 53,504 $ 37,211 Production and ad valorem taxes $ 11,430 $ 6,126 $ 20,462 $ 12,796 Exploration costs $ 466 $ 47 $ 1,433 $ 56 Depletion, depreciation, amortization and accretion $ 24,651 $ 19,563 $ 50,371 $ 38,701 Impairment of oil and natural gas properties $ — $ 1,214 $ — $ 1,214 Administrative costs $ 8,720 $ 6,199 $ 16,840 $ 13,637 Stock-based compensation expense 3,918 2,685 6,219 4,054 General and administrative expense $ 12,638 $ 8,884 $ 23,059 $ 17,691 Transaction costs $ — $ 1,926 $ — $ 1,926 Interest expense, net $ 6,770 $ 7,171 $ 13,127 $ 13,832 (Gain) loss on derivatives, net $ (33,235) $ (18,720) $ 93,735 $ (12,870) (Income) loss from equity method investment $ (45) $ 129 $ 323 $ 248 (Gain) loss on acquisitions and divestitures, net $ (961) $ — $ 1,736 $ — Income tax expense $ 27,333 $ 9,704 $ 5,045 $ 17,943 Lease Operating Expenses ("LOE") LOE are the costs incurred in the operation and maintenance of producing properties. Expenses for electricity, compression, direct labor, saltwater disposal and materials and supplies comprise the most significant portion of our lease operating expenses. Certain operating cost components, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities or subsurface maintenance result in increased production expenses in periods during which they are performed. Certain operating cost components, such as saltwater disposal 35 associated with produced water, are variable and increase or decrease as hydrocarbon production levels and the volume of water disposal increases or decreases. The Company’s LOE increased by $10.6 million for the three months ended June 30, 2026, compared to the three months ended June 30, 2025, primarily due to a $6.4 million increase related to the Silverback Acquisition, a $3.0 million increase in workover expenses to return wells to production and a $1.2 million increase in Champions' third-party water disposal costs to align with our increased drilling pace. The Company’s LOE increased by $16.3 million for the six months ended June 30, 2026, compared to the six months ended June 30, 2025, primarily due to a $10.8 million increase related to the Silverback Acquisition, a $3.1 million increase in workover expenses to return wells to production and a $1.1 million increase in Champions' third-party water disposal costs to align with our increased drilling pace. Production and Ad Valorem Tax Expense Production taxes are paid on produced oil, natural gas and NGLs based on a percentage of revenues at fixed rates established by federal, state or local taxing authorities. In general, the production taxes we pay correlate to changes in our oil, natural gas and NGL revenues. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas properties, which also trend with oil and natural gas prices and vary across the different counties in which we operate. Production and ad valorem taxes increased by $5.3 million for the three months ended June 30, 2026, compared to the three months ended June 30, 2025, primarily due to higher revenues from increased production volumes, including an increase in volumes from the Silverback Acquisition and higher oil prices. Production and ad valorem taxes increased by $7.7 million for the six months ended June 30, 2026, compared to the six months ended June 30, 2025, primarily due to higher revenues from increased production volumes, including an increase in volumes from the Silverback Acquisition and higher oil prices, partially offset by the reversal of $0.8 million for a previously accrued liability related to the Environmental Protection Agency’s waste emission charge that was nullified in the first quarter of 2025. Depletion, Depreciation, Amortization and Accretion ("DD&A") Expense DD&A expense is the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil, natural gas and NGLs. All costs incurred in the acquisition, exploration and development of properties (excluding costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes and overhead related to exploration activities) are capitalized. Capitalized costs are depleted using the units of production method. Accretion expense relates to ARO. We record the fair value of the liability for ARO in the period in which the liability is incurred (at the time the wells are drilled or acquired) with the offset to property cost. The liability accretes each period until it is settled or the well is sold, at which time the liability is removed. The following table presents the components of the Company's DD&A expense: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 (In thousands) Depletion $ 23,279 $ 17,758 $ 48,063 $ 35,315 Accretion 1,165 1,300 1,931 2,674 Depreciation and amortization 207 505 377 712 Total DD&A expense $ 24,651 $ 19,563 $ 50,371 $ 38,701 DD&A expense increased by $5.1 million and $11.7 million, respectively, for the three and six months ended June 30, 2026, compared to the three and six months ended June 30, 2025, primarily due to higher production volumes, including an increase in volumes from the Silverback Acquisition which increased depletion expense by approximately $2.4 million and $6.8 million, respectively. 36 Impairments of Oil and Natural Gas Properties There was no impairment loss during the three and six months ended June 30, 2026. There was a non-cash impairment loss on proved properties of $1.2 million during the three and six months ended June 30, 2025, which related to a decrease in fair value of certain properties in New Mexico outside of the Company's core acreage in the Red Lake field. General and Administrative ("G&A") Expense G&A expenses consist of administrative costs and stock-based compensation expense. Administrative costs include corporate overhead such as payroll and benefits for our staff, office costs, fees for professional services such as audit and legal services, technology costs, insurance and other. Stock-based compensation expense reflects costs associated with our stock granted to employees and members of our board of directors. G&A expenses are reported net of overhead recoveries. Total G&A expense increased by $3.8 million and $5.4 million for the three and six months ended June 30, 2026, compared to the three and six months ended June 30, 2025, respectively, primarily due to increased headcount and higher incentive compensation. Transaction Costs Transaction costs represent costs incurred on successful or unsuccessful commercial transactions, business combinations or unsuccessful asset acquisitions. There were no transaction costs during the three and six months ended June 30, 2026. During the three and six months ended June 30, 2025, transaction costs of $1.9 million primarily related to the Silverback Acquisition. Interest Expense, net Interest expense, net decreased by $0.4 million and $0.7 million, respectively, for the three and six months ended June 30, 2026, compared to the three and six months ended June 30, 2025, respectively, primarily due to lower interest rates on the Credit Facility and a lower principal balance on the Senior Notes. Gain (Loss) on Derivatives, net The Company recognizes settlements and changes in the fair value of our derivative contracts as a single component within other income (expense) in our condensed consolidated statements of operations. We have oil and natural gas derivative contracts, including fixed price swaps, basis swaps and collars, that settle against various indices. The following table presents the components of the Company's gain (loss) on derivatives, net: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 (In thousands) Settlements on derivative contracts $ (36,160) $ 5,151 $ (47,885) $ 6,266 Non-cash gain (loss) on derivatives 69,395 13,569 (45,850) 6,604 Gain (loss) on derivatives, net $ 33,235 $ 18,720 $ (93,735) $ 12,870 Cash gains or losses on settled derivative contracts related to contracts that settle during the period and are a function of the difference in settled versus contractual prices and the associated hedged volumes for each underlying commodity. Non-cash gains or losses on derivatives relate to unsettled contracts and are a function of changes in derivative fair values associated with fluctuations in the forward price curves for the commodities relative to contractual pricing and the associated hedged volumes for each underlying commodity for our derivative contracts outstanding. Income Tax (Benefit) Expense Current income taxes represent the amount the Company expects to owe to federal and state tax authorities in the current period, based on our taxable income. Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted 37 tax rates. See Note 12 - Income Taxes for further discussion of income taxes. Total income tax (benefit) expense is summarized below: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 (In thousands) Current income tax (benefit) expense $ (900) $ 4,838 $ 120 $ 14,903 Deferred income tax expense 28,233 4,866 4,925 3,040 Total income tax expense $ 27,333 $ 9,704 $ 5,045 $ 17,943 Effective income tax rate 23.8% 22.8% 22.9% 23.3% The increase in deferred income tax expense during the three months ended June 30, 2026, is primarily due to a higher non-cash benefit on derivatives. The decrease in current income tax expense was primarily attributable to higher capital spending during the six months ended June 30, 2026, compared to the six months ended June 30, 2025. Liquidity and Capital Resources The business of exploring for, developing and producing oil and natural gas is capital intensive. Because oil, natural gas and NGL reserves are a depleting resource, like all upstream operators, we must make capital investments to sustain and grow production. The Company’s principal liquidity requirements are to finance our operations, fund capital expenditures, fund acquisitions and joint venture commitments, pay dividends and satisfy any indebtedness obligations. Cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and the significant capital expenditures required to more fully develop the Company’s oil and natural gas properties. Historically, our primary sources of capital funding and liquidity have been our cash on hand, cash flow from operations, borrowings under our Credit Facility and the issuance of our Senior Notes. At times and as needed, we may also issue debt or equity securities, including through transactions under our shelf registration statement filed with the SEC. We estimate the combination of the sources of capital discussed above will continue to be adequate to meet our short and long-term liquidity needs. Cash on hand and operating cash flow can be subject to fluctuations due to trends and uncertainties that are beyond our control. Likewise, our ability to issue equity, debt and obtain credit facilities on favorable terms may be impacted by a variety of market factors as well as fluctuations in our results of operations. For further discussion of risks related to our liquidity and capital resources, see "Item 1A. Risk Factors." Working Capital Working capital represents the funds available to meet day-to-day operational needs and is the difference in our current assets and our current liabilities. Working capital is an indication of liquidity and potential need for short-term funding. The change in our working capital requirements is driven generally by changes in accounts receivable, accounts payable, commodity prices, credit extended to, and the timing of collections from customers, the level and timing of spending for expansion activity, and the timing of debt maturities. Our working capital fluctuates as our drilling and completion activity changes with periods of higher and lower activity. We utilize our Credit Facility and cash on hand to manage the timing of cash 38 flows and fund short-term working capital deficits. At June 30, 2026, we had $262 million of undrawn capacity under our Credit Facility. The following table presents the components of working capital: June 30, 2026 2025 (In thousands) Current Assets: Cash $ 20,686 $ 14,026 Accounts receivable, net 69,169 35,295 Prepaid expenses 5,428 2,828 Inventory 9,029 3,685 Current derivative assets 10 11,160 Total Current Assets $ 104,322 $ 66,994 Current Liabilities: Accounts payable $ 33,189 $ 9,231 Accrued liabilities 54,531 31,198 Revenue payable 77,854 32,799 Current derivative liabilities 22,106 12 Current portion of long-term debt 20,000 20,000 Other current liabilities 24,299 11,535 Total Current Liabilities $ 231,979 $ 104,775 Working Capital Deficit $ (127,657) $ (37,781) Our working capital deficit increased by $90 million primarily due to higher working capital required to fund our drilling program, revenue payable from higher oil prices and changes in our derivative assets and liabilities. Cash Flows The following table summarizes the Company’s cash flows: Six Months Ended June 30, 2026 2025 (In thousands) Net cash provided by operating activities $ 110,676 $ 84,021 Net cash used in investing activities $ (101,650) $ (70,457) Net cash used in financing activities $ (6,229) $ (12,662) Operating Activities Net cash provided by operating activities were $110.7 million for the six months ended June 30, 2026, compared to $84.0 million for the six months ended June 30, 2025, and primarily consisted of the following: Six Months Ended June 30, 2026 2025 (In thousands) Total revenues, net $ 279,731 $ 187,851 Operating expenses(1) $ (90,860) $ (65,616) Advances from joint interest owners $ 10,233 $ (8,813) Settlements on derivative contracts $ (47,885) $ 6,266 Interest paid, net of capitalized interest $ (11,307) $ (11,187) Income tax liabilities paid $ (24,203) $ (14,784) _____________________ (1)Operating expenses include LOE, production and ad valorem taxes, administrative costs, transaction costs and other miscellaneous operating expenses. 39 The increase in net cash provided by operating activities was primarily due to higher revenues from increased production and higher oil prices, along with an increase in advances from joint interest owners, partially offset by higher operating expenses associated with increased production and derivative settlement losses resulting from higher oil prices. Investing Activities Net cash flows used in investing activities were $101.7 million for the six months ended June 30, 2026, compared to $70.5 million for the six months ended June 30, 2025, and primarily consisted of the following: Six Months Ended June 30, 2026 2025 (In thousands) Additions to oil and natural gas properties $ (96,864) $ (40,938) Additions to midstream property and equipment(1) $ (1,410) $ (6,294) Acquisitions of oil and natural gas properties $ (4,824) $ (2,138) Proceeds from divestitures $ 8,206 $ — Contributions to equity method investment $ (6,500) $ (6,250) Funds held in escrow $ — $ (14,201) _____________________ (1)These additions and corresponding assets were sold as part of the sale of our midstream assets to Targa in 2025. Capital expenditures for oil and natural gas properties increased by $55.9 million due to an increase in drilling and completion activity and an increase in infrastructure investments. Funds held in escrow relate to the Silverback Acquisition, which closed on July 1, 2025. Financing Activities Net cash flows used in financing activities were $6.2 million for the six months ended June 30, 2026, compared to $12.7 million for the six months ended June 30, 2025, and primarily consisted of the following: Six Months Ended June 30, 2026 2025 (In thousands) Proceeds from Credit Facility, net $ 28,000 $ 14,000 Repayments of Senior Notes $ (10,000) $ (10,000) Payment of cash dividends $ (17,038) $ (16,121) Repurchase of common shares $ (4,902) $ — Repurchase of common shares for tax withholding and other $ (1,871) $ (377) Net borrowings increased by $14 million, partially offset by the repurchase of common shares of $5 million and an increase in repurchases of common shares for tax withholding of 1.5 million. Credit Facility and Senior Notes On April 30, 2026, the Company entered into the eighteenth amendment to the Credit Facility, which increased the Company’s borrowing base from $400 million to $425 million and documented the Company's election to maintain commitments thereunder at $400 million. In addition, the eighteenth amendment shortens the springing maturity of the Credit Facility in advance of the Senior Notes from 181 days to 91 days, effectively extending the maturity date for the Credit Facility to January 2028, given the April 2028 stated maturity of the Senior Notes. The Credit Facility and Senior Notes had a principal balance of $138 million and $135 million, respectively, as of June 30, 2026. See further discussion in Note 10 - Long-Term Debt for additional information. 40 Dividends For the six months ended June 30, 2026, the Company recognized quarterly dividends totaling approximately $17.3 million, with $17.0 million paid in cash and $0.3 million accrued for the holders of unvested restricted stock awards. Contractual Obligations As of June 30, 2026, the Company had a remaining volume commitment that expires the earlier of achieving a specified quantity of cumulative volumes delivered or by the contract expiration date in 2031 with Targa, formerly Stakeholder Midstream, LLC, in Texas. The Company also had natural gas delivery commitments under the A&R Tolling Agreement and a remaining equity commitment under the Second Amendment to the A&R LLC Agreement to fund our portion of the capital budget for the RPC Power joint venture. The Company also entered into the A&R Gas Purchase Agreement that required an acreage dedication and a minimum volume commitment to Targa for a significant portion of our natural gas production in New Mexico. This agreement is expected to commence in the fourth quarter of 2026. In addition, the Company entered into the Waterbridge Agreement, which includes minimum produced water volume commitments for a portion of our New Mexico operations and is expected to be in service in the fourth quarter of 2026. See Note 15 - Commitments and Contingencies for additional information. Critical Accounting Estimates The Company's critical accounting estimates are described in "Critical Accounting Estimates" within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 1 of the Notes to the Consolidated Financial Statements in the 2025 Annual Report. The accounting estimates used in preparing our interim condensed consolidated financial statements for the six months ended June 30, 2026, are the same as those described in the 2025 Annual Report. See Note 3 - Summary of Significant Accounting Policies in the Company's consolidated financial statements in "Item 15. Exhibits and Financial Statement Schedules" in the 2025 Annual Report for a full discussion of our significant accounting policies.