You should read the following discussion of our results of operations and financial condition together with our Condensed Consolidated Financial Statements and the notes thereto included under Part I – Financial Information. This discussion contains forward-looking statements that involve risks and uncertainties. The forward-looking statements are not historical facts, but rather are based on current expectations, estimates, assumptions and projections about the oil and natural gas industry and our business and financial results. Our actual results could differ materially from the results contemplated by these forward-looking statements due to a number of factors, including those discussed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2025 in the section entitled Part I, Item 1A Risk Factors and in this Quarterly Report on Form 10-Q in the sections entitled Part II, Item 1A Risk Factors and “Cautionary Statement Concerning Forward-Looking Statements.” As further described in Note 3 (“Oil and Gas Properties”) to the Condensed Consolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q, we completed the Lucero Acquisition on March 7, 2025. The financial information presented herein (i) excludes the results of Lucero and its subsidiaries for periods prior to March 7, 2025 and (ii) includes the results of Lucero and its subsidiaries for periods on or after March 7, 2025. Executive Overview Our business strategy is focused on creating long-term stockholder value through the profitable acquisition, development and production of oil and natural gas assets that provide an attractive return on invested capital, while maintaining a strong balance sheet and distributing a meaningful dividend to our stockholders. We invest in working and mineral interests in oil and natural gas properties with our core area of focus currently in the Bakken and Three Forks formations of the Williston Basin of North Dakota and Montana. We also have interests in wells in the Denver-Julesburg Basin located in Colorado and Wyoming and the Powder River Basin located in Wyoming. As of June 30, 2026, we had a working interest in 6,579 gross (237.4 net) productive wells and 278 gross (6.4 net) wells that were being drilled or completed, and an additional 320 gross (13.0 net) wells that had been permitted for development by our operators. In addition, we had a royalty only interest in 1,289 gross (3.1 net) productive wells. As previously announced, on May 1, 2026, Mr. Jamie Benard joined our team as President and Chief Executive Officer. On the same date, Mr. Brian Cree transitioned from President and Interim Chief Executive Officer to Senior Advisor, a role he will hold until his retirement on December 31, 2026. Our financial and operating performance for the three months ended June 30, 2026 included the following: ■Paid $20.6 million in dividends to our equity holders. ■Production of 17,354 Boe/d with 60% of production from oil. ■Total revenue of $91.0 million. ■Net income of $33.1 million. ■Cash flows from operations of $25.4 million. ■Invested $20.7 million in capital development and acquisitions, net of divestitures. ■Total debt of $158.5 million at June 30, 2026. Industry Trends Impacting Our Business Commodity prices are a significant factor impacting our earnings, operating cash flows and our acquisition and divestiture strategy, as well as the decisions of us and our operators in conducting operations. During the last several years, prices for oil and natural gas have experienced sustained volatility, impacted by general economic and political conditions, the conflict between Russia and Ukraine, conflict in the Middle East, including Iran, the situation in Venezuela, U.S. international trade and tariff policies and responses thereto, supply chain constraints, elevated interest rates and costs of capital, and changes in production by OPEC and its key member, Saudi Arabia, and certain other non-OPEC oil-producing countries. Most recently, the conflict in Iran and disruption of maritime traffic through the Strait of Hormuz has caused significant volatility in commodity prices. As a result of such commodity price volatility, which we expect to continue throughout 2026, our earnings and operating cash flows can vary substantially. While we do hedge a substantial portion of our production, we are still significantly subject to movements in commodity prices. Such volatility can make it difficult to predict future effects on our financial results and the decisions of our operators. Factors that we expect will continue to impact commodity prices include product demand connected with global economic conditions, inflationary factors, industry production and inventory levels, the United States Department of Energy’s sales and purchases related to the U.S. strategic petroleum reserve, technology advancements, production quotas or other actions imposed by OPEC and other oil-producing countries, the imposition of and changes in tariffs and other controls on imports and exports and resulting consequences of such, actions of regulators, and regional supply interruptions or fears thereof that may be caused by military conflicts, civil unrest or political uncertainty, including as a result of the conflict in Iran and disruption of maritime traffic through the Strait of Hormuz. Any of the foregoing can have a substantial impact on the prices of oil and natural gas, which in turn impacts our decisions and the decision of our operators to drill and extract resources. Source of Our Revenues 28 Table of Contents We derive our revenues from the sale of oil and natural gas produced from our properties. Revenues are a function of the volume produced, the prevailing market price at the time of sale, oil quality, Btu content and transportation costs to market. We use derivative instruments to hedge future sales prices on a substantial, but varying, portion of our oil and natural gas production. We expect our derivative activities will help us achieve more predictable cash flows and reduce our exposure to downward price fluctuations. The use of derivative instruments has in the past, and may in the future, prevent us from realizing the full benefit of upward price movements but also mitigates the effects of declining price movements. Principal Components of Our Cost Structure Commodity price differentials. The price differential between our wellhead price for oil and the WTI benchmark price is primarily driven by the cost to transport oil via pipeline, train or truck to refineries. The price differential between our wellhead price for natural gas and the NYMEX benchmark price is primarily driven by Btu content along with gathering, processing and transportation costs. Commodity derivative gain (loss), net. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the prices of oil and gas. Gain (loss) on commodity derivatives, net is comprised of (1) cash gains and losses we recognize on settled commodity derivatives during the period, and (2) non-cash mark-to-market gains and losses we incur on commodity derivative instruments outstanding at period-end. Lease operating expenses. Lease operating expenses are costs incurred to bring oil and natural gas out of the ground and to market, together with the costs incurred to maintain our producing properties. Such costs include field personnel compensation, saltwater disposal, utilities, maintenance, repairs and servicing expenses related to our oil and natural gas properties. Production taxes. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at market prices (not hedged prices) or at fixed rates established by federal, state or local taxing authorities. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues. DD&A. DD&A includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas properties. As a successful efforts company, costs associated with the acquisition, drilling, and equipping of successful exploratory wells and costs of successful and unsuccessful development wells are capitalized. Accretion expense relates to the passage of time of our asset retirement obligations. General and administrative expenses. General and administrative expenses include overhead, including payroll and benefits for our staff, costs of maintaining our headquarters, costs of managing our acquisition and development operations, franchise taxes, audit and other professional fees and legal compliance. During the six months ended June 30, 2025, general and administrative expenses included non-recurring costs related to the Lucero Acquisition and an offset for reimbursement of past legal expenses as a result of a settlement discussed in Note 9 (“Commitments and Contingencies”) to the Condensed Consolidated Financial Statements. Interest expense. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our Revolving Credit Facility. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We do not capitalize any portion of the interest paid on applicable borrowings. We include the amortization of deferred financing costs, commitment fees and annual agency fees as interest expense. Impairment expense. Under the successful efforts method of accounting, we review our oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Whenever we conclude the carrying value may not be recoverable, we estimate the expected undiscounted future net cash flows of our oil and natural gas properties using proved and risked probable and possible reserves based on our development plans and best estimate of future production, commodity pricing, reserve risking, gathering, processing and transportation deductions, production tax rates, lease operating expenses and future development costs. We compare such undiscounted future net cash flows to the carrying amount of the oil and natural gas properties in each depletion pool to determine if the carrying amount is recoverable. If the undiscounted future net cash flows exceed the carrying amount of the aggregated oil and natural gas properties, no impairment is recorded. If the carrying amount of the oil and natural gas properties exceeds the undiscounted future net cash flows, we will record an impairment expense to reduce the carrying value to fair value as of the balance sheet date. The factors used to determine fair value may include, but are not limited to, recent sales prices of comparable properties, indications from marketing activities, the present value of future revenues, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the projected cash flows. There were no proved oil and gas property impairments during the three and six months ended June 30, 2026 and 2025. Income tax expense. Our provision for taxes includes both federal and state taxes. We record our federal income taxes in accordance with accounting for income taxes under GAAP, which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the 29 Table of Contents years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. Selected Factors That Affect Our Operating Results Our revenues, cash flows from operations and future growth depend substantially upon: ■the timing and success of our drilling and production activities and those of our operating partners; ■the prices and the supply and demand for oil, natural gas and NGLs; ■the quantity of oil and natural gas production from the wells in which we participate; ■the realized gains and losses on our derivative instruments; ■our ability to continue to identify and acquire producing properties, high-quality acreage and drilling opportunities; and ■the level of our operating expenses. In addition to the factors that affect companies in our industry generally, the location of substantially all of our acreage and wells in the Williston, Denver-Julesburg and Powder River Basins subjects our operating results to factors specific to these regions. These factors include the potential adverse impact of weather on drilling, production and transportation activities, particularly during the winter and spring months, as well as infrastructure limitations, transportation capacity, regulatory matters and other factors that may specifically affect one or more of these regions. Market Conditions The price of oil can vary depending on the market in which it is sold and the means of transportation used to transport the oil to market, particularly in the Williston Basin where a substantial majority of our revenues are derived. Additional pipeline infrastructure has increased takeaway capacity in the Williston Basin which has improved wellhead values in the region. The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Because our oil and gas revenues are heavily weighted toward oil, we are more significantly impacted by changes in oil prices than by changes in the price of natural gas. Worldwide supply in terms of output, especially production from properties within the United States, the production quotas set by OPEC and certain other oil-producing countries, the conflicts in Ukraine and in the Middle East, including Iran, the situation in Venezuela and the strength or weakness of the U.S. dollar can impact oil prices. Historically, commodity prices have been volatile and we expect the volatility to continue in the future. Future oil prices will be impacted by varying oil supply and demand both regionally and worldwide. Prices for various quantities of oil, natural gas and NGLs significantly impact our revenues and cash flows. The following table lists average NYMEX prices for oil and natural gas for the periods presented. THREE MONTHS ENDED JUNE 30, Average Daily Prices (1) 2026 2025 WTI Oil (per Bbl) $ 92.38 $ 63.55 Natural Gas (per MMBtu) 2.95 3.19 SIX MONTHS ENDED JUNE 30, Average Daily Prices (1) 2026 2025 WTI Oil (per Bbl) $ 82.40 $ 67.36 Natural Gas (per MMBtu) 3.81 3.63 (1)Based on average daily NYMEX WTI and Henry Hub Spot closing prices reported by FactSet and the EIA, respectively. The average second quarter 2026 NYMEX oil price was $92.38 per barrel, or 45% higher than the average NYMEX oil price per barrel in the second quarter of 2025. Our settled derivatives decreased our second quarter 2026 realized oil price per barrel by $20.84 and increased our second quarter 2025 realized oil price per barrel by $4.71. Our average second quarter 2026 realized oil price per barrel after reflecting settled derivatives was $71.14 compared to $64.21 during the same period in 2025. The average second quarter 2026 NYMEX natural gas price was $2.95 per MMBtu, or 8% lower than the average NYMEX price per MMBtu in the second quarter of 2025. In the second quarter of 2026, our settled derivatives increased our realized natural gas price by $0.38 per Mcf, bringing our realized natural gas price after reflecting settled derivatives to $1.55 per Mcf. In the second quarter of 2025, we had no material natural gas price derivatives in place and our realized natural gas price was $4.17 per Mcf. The average year-to-date 2026 NYMEX oil price was $82.40 per barrel, or 22% higher than the 2025 average year-to-date oil price per barrel. Our settled derivatives decreased our average year-to-date 2026 realized oil price per barrel by $13.06 and 30 Table of Contents increased our average year-to-date 2025 realized oil price per barrel by $2.92. Our average year-to-date 2026 realized oil price per barrel after reflecting settled derivatives was $66.60 compared to $64.53 during the same period in 2025. The average year-to-date 2026 NYMEX natural gas price was $3.81 per MMBtu, or 5% higher than the 2025 average year-to-date price per MMBtu. During the six months ended June 30, 2026, our settled derivatives decreased our realized natural gas price by $0.13 per Mcf, bringing our realized natural gas price after reflecting settled derivatives to $1.55 per Mcf. During the six months ended June 30, 2025, we had no material natural gas price derivatives in place and our realized natural gas price was $3.61 per Mcf. We employ a hedging program that partially mitigates the risk associated with fluctuations in commodity prices. For detailed information on our commodity hedging program, see Part I, Item 3 Quantitative and Qualitative Disclosures about Market Risk and Note 6 (“Commodity Derivative Instruments”) to the Condensed Consolidated Financial Statements. Another significant factor affecting our operating results is drilling costs. The cost of drilling wells can vary significantly, driven in part by volatility in commodity prices that can substantially impact the level of drilling activity. Generally, higher oil prices have led to increased drilling activity, with the increased demand for drilling and completion services driving these costs higher. Lower oil prices have generally had the opposite effect. In addition, individual components of the cost can vary depending on numerous factors such as the length of the horizontal lateral, the number of fracture stimulation stages, and the type and amount of proppant. 31 Table of Contents Results of Operations Three Months Ended June 30, 2026 Compared with Three Months Ended June 30, 2025 The following table sets forth selected financial and operating data for the periods indicated. THREE MONTHS ENDED JUNE 30, INCREASE (DECREASE) ($ in thousands, except production and per unit data) 2026 2025 AMOUNT PERCENT Financial and Operating Results: Revenue Oil $ 86,507 $ 66,611 $ 19,896 30 % Natural gas 4,497 15,144 (10,647) (70 %) Total revenue $ 91,004 $ 81,755 $ 9,249 11 % Operating Expenses Lease operating expense $ 17,975 $ 19,629 $ (1,654) (8 %) Production taxes 8,459 6,180 2,279 37 % General and administrative 6,150 311 5,839 1877 % Depletion, depreciation, amortization, and accretion 34,809 34,576 233 1 % Equity-based compensation 2,735 2,403 332 14 % Interest Expense $ 3,022 $ 2,539 $ 483 19 % Commodity Derivative Gain, Net $ 22,043 $ 18,451 $ 3,592 19 % Income Tax (Benefit) Expense $ 6,776 $ 9,871 $ (3,095) (31 %) Production Data: Oil (MBbls) 940 1,119 (179) (16 %) Natural gas (MMcf) 3,832 3,630 202 6 % Combined volumes (MBoe) 1,579 1,724 (145) (8 %) Daily combined volumes (Boe/d) 17,354 18,950 (1,596) (8 %) Average Realized Prices before Hedging: Oil (per Bbl) $ 91.98 $ 59.50 $ 32.48 55 % Natural gas (per Mcf) 1.17 4.17 (3.00) (72 %) Combined (per Boe) 57.63 47.41 10.22 22 % Average Realized Prices with Hedging: Oil (per Bbl) $ 71.14 $ 64.21 $ 6.93 11 % Natural gas (per Mcf) 1.55 4.17 (2.62) (63 %) Combined (per Boe) 46.12 50.47 (4.35) (9 %) Average Costs (per Boe): Lease operating $ 11.38 $ 11.38 $ — — % Production taxes 5.36 3.58 1.78 50 % General and administrative 3.89 0.18 3.71 2061 % Depletion, depreciation, amortization, and accretion 22.04 20.05 1.99 10 % Oil and Natural Gas Revenue and Volumes. Oil and natural gas revenue increased to $91.0 million for the three months ended June 30, 2026 from $81.8 million for the three months ended June 30, 2025. The increase in oil and natural gas revenue was due to a 22% increase in the average realized prices per Boe before hedging, partially offset by an 8% decrease in production volumes for the three months ended June 30, 2026. The increase in average realized prices per Boe before hedging increased oil and natural gas revenue by $17.6 million, while the decrease in production volumes decreased oil and natural gas revenue by $8.4 million. 32 Table of Contents During the three months ended June 30, 2025, $3.3 million and $13.6 million of recoupments of oil and natural gas revenue, respectively, were recognized as part of the settlement discussed in Note 9 (“Commitments and Contingencies”) to the Condensed Consolidated Financial Statements. Our oil price differential to the weighted average benchmark price during the three months ended June 30, 2026 was negative $0.88 per barrel, as compared to a negative $4.17 per barrel during the three months ended June 30, 2025, primarily due to more favorable local market pricing as compared to the benchmark price. Our net realized natural gas price during the three months ended June 30, 2026 was $1.17 per Mcf, representing a 40% realization relative to the weighted average NYMEX natural gas price, compared to a net realized natural gas price of $4.17 per Mcf during the three months ended June 30, 2025, representing a 130% realization relative to the weighted average NYMEX natural gas price. The lower realized price was primarily due to the legal settlement increasing the realized price per Mcf in the prior period. Fluctuations in our natural gas price differentials and realizations are due to several factors such as NGL value net of processing costs, gathering and transportation fees, takeaway capacity relative to production levels, regional storage capacity, seasonal demand for heating fuel and seasonal refinery maintenance temporarily depressing demand. The exact impact of each of these items is difficult to quantify as each of our operators passes through these costs in a different manner. Lease Operating Expense. Lease operating expense decreased to $18.0 million for the three months ended June 30, 2026 from $19.6 million for the three months ended June 30, 2025. The decrease is primarily attributable to an 8% decrease in production volumes between periods. Production Tax Expense. Total production taxes increased to $8.5 million for the three months ended June 30, 2026 from $6.2 million for the three months ended June 30, 2025. Production taxes are primarily based on oil revenue and natural gas production, excluding gains and losses associated with hedging activities. Production taxes as a percentage of oil and natural gas sales before hedging adjustments were 9.3% and 7.6% for the three months ended June 30, 2026 and 2025, respectively. The production tax rate was lower for the three months ended June 30, 2025 due to a legal settlement increasing revenue in the period. General and Administrative Expense. General and administrative expense increased to $6.2 million for the three months ended June 30, 2026 from $0.3 million for the three months ended June 30, 2025. During the three months ended June 30, 2025, $7.1 million of litigation costs were reimbursed as a result of a legal settlement. Excluding net litigation costs and Lucero Acquisition transaction costs of $0.3 million, general and administrative expense on a per Boe basis was $3.47 for the three months ended June 30, 2025 compared to $3.89 for the three months ended June 30, 2026. DD&A. DD&A increased to $34.8 million for the three months ended June 30, 2026 compared with $34.6 million for the three months ended June 30, 2025. The increase was the result of a $1.99 per Boe increase in the DD&A rate for the three months ended June 30, 2026, partially offset by an 8% decrease in production compared with the three months ended June 30, 2025. The increase in the DD&A rate accounted for a $3.4 million increase in DD&A expense while the decrease in production accounted for a $3.2 million decrease in DD&A expense. For the three months ended June 30, 2026, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate (excluding depreciation, amortization and accretion) of $21.85 per Boe compared with $19.88 per Boe for the three months ended June 30, 2025. Equity-Based Compensation. During the three months ended June 30, 2026, equity-based compensation expense increased to $2.7 million from $2.4 million during the three months ended June 30, 2025. Equity-based compensation expense was higher in 2026 due to additional LTIP RSUs and PSUs awarded to employees and directors. Interest Expense. Interest expense increased to $3.0 million for the three months ended June 30, 2026 from $2.5 million for the three months ended June 30, 2025. The increase for the three months ended June 30, 2026 was primarily due to a higher average debt balance during the period. Commodity Derivative Gain, Net. The commodity derivative gain was $22.0 million for the three months ended June 30, 2026 compared with a gain of $18.5 million for the three months ended June 30, 2025. Gain (Loss) on Commodity Derivatives is comprised of (1) cash gains and losses we recognize on settled commodity derivative instruments during the period, and (2) unsettled gains and losses we incur on commodity derivative instruments outstanding at period-end. The mark-to-market fair value of the unsettled commodity derivative instruments will generally be inversely related to the price movement of the underlying commodity. If commodity price trends reverse from period to period, prior unrealized gains may become unrealized losses and vice versa. These unrealized gains and losses will impact our net income in the period reported. The mark-to-market fair value can create non-cash volatility in our reported earnings during periods of commodity price volatility. We have experienced such volatility in the past and are likely to experience it in the future. Gains on our derivatives generally indicate lower oil revenues in the future while losses indicate higher future oil revenues. The table below summarizes our commodity derivative gains and losses that were recorded in the periods presented. 33 Table of Contents THREE MONTHS ENDED JUNE 30, (in thousands) 2026 2025 Realized (loss) gain on commodity derivatives (1) $ (18,170) $ 5,271 Unrealized gain on commodity derivatives (1) 40,213 13,180 Total commodity derivative gain $ 22,043 $ 18,451 (1)Realized and unrealized gains and losses on commodity derivatives are presented herein as separate line items but are combined for a total commodity derivative gain (loss) in the statements of operations included in this Form 10-Q. Management believes the separate presentation of the realized and unrealized commodity derivative gains and losses is useful because the realized cash settlement portion provides a better understanding of our hedge position. In the three months ended June 30, 2026, 84% of our oil volumes were covered by financial hedges, which resulted in a realized loss on oil derivatives of $19.6 million. In the three months ended June 30, 2026, half of our natural gas volumes were covered by residue gas and NGL financial hedges, which resulted in a realized gain on gas and NGL derivatives of $1.4 million. In the three months ended June 30, 2025, 58% of our oil volumes and no material natural gas volumes were covered by financial hedges, which resulted in a realized gain on oil derivatives of $5.3 million. At June 30, 2026, all of our derivative contracts were recorded at their fair value, which was a net asset of $6.4 million, an increase in value of $40.2 million from the $33.8 million net liability recorded as of March 31, 2026. Derivative contract fair value is recorded in part based on published forward commodity prices. This increase in fair value was largely driven by the NYMEX WTI price decreasing from $101.38/Bbl at March 31, 2026 to $69.50/Bbl at June 30, 2026 and the corresponding change in forward commodity prices. Income Tax Expense. During the three months ended June 30, 2026, we recorded an income tax expense of $6.8 million related to federal and state income taxes compared to an income tax expense of $9.9 million for the three months ended June 30, 2025. The provision for income taxes for the three months ended June 30, 2026 and 2025 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax income primarily due to §162(m) limitations on certain covered employee compensation, other discrete permanent differences related to vesting of RSUs for non-covered employees and state income taxes. 34 Table of Contents Six Months Ended June 30, 2026 Compared with Six Months Ended June 30, 2025 The following table sets forth selected financial and operating data for the periods indicated. SIX MONTHS ENDED JUNE 30, INCREASE (DECREASE) ($ in thousands, except production and per unit data) 2026 2025 AMOUNT PERCENT Financial and Operating Results: Revenue Oil $ 146,524 $ 125,535 $ 20,989 17 % Natural gas 11,891 22,390 (10,499) (47 %) Total revenue $ 158,415 $ 147,925 $ 10,490 7 % Operating Expenses Lease operating expense $ 33,310 $ 33,484 $ (174) (1 %) Production taxes 14,124 11,953 2,171 18 % General and administrative 14,736 12,442 2,294 18 % Depletion, depreciation, amortization, and accretion 65,996 61,139 4,857 8 % Equity-based compensation 3,460 4,873 (1,413) (29 %) Interest Expense $ 5,637 $ 5,443 $ 194 4 % Commodity Derivative (Loss) Gain, Net $ (32,963) $ 18,279 $ (51,242) (280 %) Income Tax (Benefit) Expense $ (2,689) $ 9,669 $ (12,358) (128 %) Production Data: Oil (MBbls) 1,839 2,038 (199) (10 %) Natural gas (MMcf) 7,058 6,206 852 14 % Combined volumes (MBoe) 3,016 3,072 (56) (2 %) Daily combined volumes (Boe/d) 16,662 16,971 (309) (2 %) Average Realized Prices before Hedging: Oil (per Bbl) $ 79.66 $ 61.61 $ 18.05 29 % Natural gas (per Mcf) 1.68 3.61 (1.93) (53 %) Combined (per Boe) 52.53 48.16 4.37 9 % Average Realized Prices with Hedging: Oil (per Bbl) $ 66.60 $ 64.53 $ 2.07 3 % Natural gas (per Mcf) 1.55 3.61 (2.06) (57 %) Combined (per Boe) 44.24 50.09 (5.85) (12 %) Average Costs (per Boe): Lease operating $ 11.05 $ 10.90 $ 0.15 1 % Production taxes 4.68 3.89 0.79 20 % General and administrative 4.89 4.05 0.84 21 % Depletion, depreciation, amortization, and accretion 21.88 19.90 1.98 10 % Oil and Natural Gas Revenue and Volumes. Oil and natural gas revenue increased to $158.4 million for the six months ended June 30, 2026 from $147.9 million for the six months ended June 30, 2025. The increase in oil and natural gas revenue was due to a 9% increase in the average realized prices per Boe before hedging, which was partially offset by a 2% decrease in production volumes for the six months ended June 30, 2026. The increase in average realized prices per Boe before hedging increased oil and natural gas revenue by $13.4 million, while the decrease in production volumes decreased oil and natural gas revenue by $2.9 million. 35 Table of Contents During the six months ended June 30, 2025, $3.3 million and $13.6 million of recoupments of oil and natural gas revenue, respectively, were recognized as part of the settlement discussed in Note 9 (“Commitments and Contingencies”) to the Condensed Consolidated Financial Statements. Our oil price differential to the weighted average benchmark price during the six months ended June 30, 2026 was negative $3.11 per barrel, as compared to a negative $5.32 per barrel during the six months ended June 30, 2025, primarily due to more favorable local market pricing as compared to the benchmark price. Our net realized natural gas price during the six months ended June 30, 2026 was $1.68 per Mcf, representing a 44% realization relative to the weighted average NYMEX natural gas price, compared to a net realized natural gas price of $3.61 per Mcf during the six months ended June 30, 2025, representing a 101% realization relative to the weighted average NYMEX natural gas price. The lower realized price was primarily due to a legal settlement increasing the realized price per Mcf in the prior period. Fluctuations in our natural gas price differentials and realizations are due to several factors such as NGL value net of processing costs, gathering and transportation fees, takeaway capacity relative to production levels, regional storage capacity, seasonal demand for heating fuel and seasonal refinery maintenance temporarily depressing demand. The exact impact of each of these items is difficult to quantify as each of our operators passes through these costs in a different manner. Lease Operating Expense. Lease operating expense decreased to $33.3 million for the six months ended June 30, 2026 from $33.5 million for the six months ended June 30, 2025. The decrease is primarily attributable to a 2% decrease in production between periods. Production Tax Expense. Total production taxes increased to $14.1 million for the six months ended June 30, 2026 from $12.0 million for the six months ended June 30, 2025. Production taxes are primarily based on oil revenue and natural gas production, excluding gains and losses associated with hedging activities. Production taxes as a percentage of oil and natural gas sales before hedging adjustments were 8.9% and 8.1% for the six months ended June 30, 2026 and 2025, respectively. The production tax rate was lower for the six months ended June 30, 2025 due to the legal settlement increasing revenue in the period. General and Administrative Expense. General and administrative expense increased to $14.7 million for the six months ended June 30, 2026 from $12.4 million for the six months ended June 30, 2025. During the six months ended June 30, 2026, $2.4 million in separation benefits related to our leadership transition were incurred. During the six months ended June 30, 2025, $7.1 million of litigation costs were reimbursed as a result of a legal settlement and Lucero Acquisition transaction costs of $4.9 million were incurred. Excluding these one-time costs, general and administrative expense on a per Boe basis increased to $4.09 for the six months ended June 30, 2026 from $3.87 for the six months ended June 30, 2025. DD&A. DD&A increased to $66.0 million for the six months ended June 30, 2026 from $61.1 million for the six months ended June 30, 2025. The increase was the result of a $1.98 per Boe increase in the DD&A rate, partially offset by a 2% decrease in production for the six months ended June 30, 2026 compared with the six months ended June 30, 2025. The increase in the DD&A rate accounted for a $6.1 million increase in DD&A expense while the decrease in production accounted for a $1.2 million decrease in DD&A expense. For the six months ended June 30, 2026, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate (excluding depreciation, amortization and accretion) of $21.69 per Boe compared with $19.74 per Boe for the six months ended June 30, 2025. Equity-Based Compensation. During the six months ended June 30, 2026, equity-based compensation expense decreased to $3.5 million from $4.9 million during the six months ended June 30, 2025. Equity-based compensation expense was primarily lower in 2026 due to a $1.4 million reversal of expense for forfeited awards during the period. Interest Expense. Interest expense increased to $5.6 million for the six months ended June 30, 2026 from $5.4 million for the six months ended June 30, 2025. The increase for the six months ended June 30, 2026 was due to a higher average debt balance during the six months ended June 30, 2026 compared to the six months ended June 30, 2025. Commodity Derivative (Loss) Gain, Net. The commodity derivative loss was $33.0 million for the six months ended June 30, 2026 compared with a gain of $18.3 million for the six months ended June 30, 2025. Gain (Loss) on Commodity Derivatives is comprised of (1) cash gains and losses we recognize on settled commodity derivative instruments during the period, and (2) unsettled gains and losses we incur on commodity derivative instruments outstanding at period-end. The mark-to-market fair value of the unsettled commodity derivative instruments will generally be inversely related to the price movement of the underlying commodity. If commodity price trends reverse from period to period, prior unrealized gains may become unrealized losses and vice versa. These unrealized gains and losses will impact our net income in the period reported. The mark-to-market fair value can create non-cash volatility in our reported earnings during periods of commodity price volatility. We have experienced such volatility in the past and are likely to experience it in the future. Gains on our derivatives generally indicate lower oil revenues in the future while losses indicate higher future oil revenues. The table below summarizes our commodity derivative gains and losses that were recorded in the periods presented. 36 Table of Contents SIX MONTHS ENDED JUNE 30, (in thousands) 2026 2025 Realized (loss) gain on commodity derivatives (1) $ (24,999) $ 5,954 Unrealized (loss) gain on commodity derivatives (1) (7,964) 12,325 Total commodity derivative (loss) gain $ (32,963) $ 18,279 (1)Realized and unrealized gains and losses on commodity derivatives are presented herein as separate line items but are combined for a total commodity derivative gain (loss) in the statements of operations included in this Form 10-Q. Management believes the separate presentation of the realized and unrealized commodity derivative gains and losses is useful because the realized cash settlement portion provides a better understanding of our hedge position. In the six months ended June 30, 2026, 72% of our oil volumes were subject to financial hedges, which resulted in a realized loss on oil derivatives of $24.0 million. In the six months ended June 30, 2026, approximately half of our natural gas volumes were covered by residue gas and NGL financial hedges, which resulted in a realized loss on gas and NGL derivatives of $1.0 million. In the six months ended June 30, 2025, 52% of our oil volumes and no material natural gas volumes were subject to financial hedges, which resulted in a realized gain on oil derivatives of $6.0 million. At June 30, 2026, all of our derivative contracts were recorded at their fair value, which was a net asset of $6.4 million, a decrease in value of $8.0 million from the $14.4 million net asset recorded as of December 31, 2025. Derivative contract fair value is recorded in part based on published forward commodity prices. This decline in fair value was largely driven by the NYMEX WTI price increasing from $57.42/Bbl at December 31, 2025 to $69.50/Bbl at June 30, 2026 and the corresponding change in forward commodity prices. Income Tax Expense. During the six months ended June 30, 2026, we recorded an income tax benefit of $2.7 million related to federal and state income taxes compared to an income tax expense of $9.7 million for the six months ended June 30, 2025. The provision for income taxes for the six months ended June 30, 2026 and 2025 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax income (loss) primarily due to §162(m) limitations on certain covered employee compensation, other discrete permanent differences related to vesting of RSUs for non-covered employees and state income taxes. Liquidity and Capital Resources Overview. At June 30, 2026, we had $0.9 million of unrestricted cash on hand and $116.5 million available under the elected commitments in our Revolving Credit Facility. At December 31, 2025, we had $1.3 million of unrestricted cash on hand and $125.5 million available under the elected commitments in our Revolving Credit Facility. We expect that our liquidity going forward will be primarily derived from cash flows from our operations, cash on hand, availability under the Revolving Credit Facility and proceeds from equity or debt offerings and that these sources of liquidity will be sufficient to provide us the ability to fund our material cash requirements for the next twelve months, as described below, including our planned capital expenditures program, as well as dividends and our share repurchase program. We may need to fund acquisitions or other business opportunities that support our strategy through additional borrowings under our Revolving Credit Facility or the issuance of equity or debt. Our primary uses of capital have been for the acquisition and development of our oil and natural gas properties and dividend payments. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position. Working Capital. Our working capital balance fluctuates as a result of changes in commodity pricing and production volumes, the collection of accrued revenue, expenditures related to our acquisition and development, and production operations and the impact of our outstanding commodity derivative instruments. At June 30, 2026 and December 31, 2025, we had a working capital surplus of $3.1 million and $0.9 million, respectively. Current assets increased by $6.2 million and current liabilities increased by $4.0 million at June 30, 2026, compared to December 31, 2025. The increase in current assets during the six months ended June 30, 2026 was primarily due to an increase of $21.8 million in accrued revenue, partially offset by a decrease of $12.5 million in current derivative instrument assets due to forward oil price increases as compared to hedged oil prices. The increase in current liabilities during the six months ended June 30, 2026 was primarily due to an increase of $4.3 million in current derivative instrument liabilities due to forward oil price increases as compared to hedged oil prices. 37 Table of Contents Cash Flows. Our cash flows for the six months ended June 30, 2026 and 2025 are presented below: SIX MONTHS ENDED JUNE 30, (in thousands) 2026 2025 Cash flows provided by operating activities $ 49,468 $ 83,505 Cash flows used in investing activities (39,388) (66,118) Cash flows used in financing activities (10,524) (18,392) Net change in cash $ (444) $ (1,005) During the six months ended June 30, 2026, we generated $49.5 million of cash from operations, a $34.0 million decrease from the six months ended June 30, 2025. Cash flows from operating activities are primarily affected by production volumes, commodity prices, net of the effects of settlements of our derivative contracts, and by changes in working capital. During 2025, we received a one-time $24.0 million legal settlement that impacted cash flows from operating activities. Any interim cash needs are funded by cash on hand, cash flows from operations or borrowings under our Revolving Credit Facility. A minimum level of derivative coverage is required by certain debt covenants. See Part I, Item 3 Quantitative and Qualitative Disclosures about Market Risk. One of the primary sources of variability in our cash provided by operating activities is commodity price volatility, which we partially mitigate through the use of commodity derivative contracts. For more information on our outstanding derivatives, see Note 6 (“Commodity Derivative Instruments”) to the Condensed Consolidated Financial Statements. Cash used in investing activities during the six months ended June 30, 2026 was $39.4 million compared to $66.1 million during the six months ended June 30, 2025. The $26.7 million decrease was primarily related to lower development activity between periods. Cash used in investing activities primarily relates to capital expenditures for acquisition and development costs. Our cash used in investing activities reflects actual cash spending, which can lag several months from when the related costs were accrued. As a result, our actual cash spending is not always reflective of current levels of development activity. Acquisition and development activities are discretionary. We monitor our capital expenditures on a regular basis, adjusting the amount up or down, and between projects, depending on projected commodity prices, cash flows and financial returns. We supplement development activity on our asset base with opportunistic acquisitions of near-term drilling opportunities when development activity by our operators on our existing properties does not meet our development objectives. Our net cash proceeds and spending for divestiture and acquisition activities was $0.7 million and $(1.6) million, during the six months ended June 30, 2026 and 2025, respectively. Cash used in financing activities was $10.5 million and $18.4 million during the six months ended June 30, 2026 and 2025, respectively. The cash used in financing activities during the six months ended June 30, 2026 was related to $44.1 million in dividends paid, partially offset by $34.0 million of net borrowings under our Revolving Credit Facility. The cash used in financing activities during the six months ended June 30, 2025 was related to $47.8 million in dividends paid, $11.0 million of net repayments under our Revolving Credit Facility and the $9.2 million value of retained shares paid to fund employee tax withholding in connection with the vesting of restricted stock units, which was partially offset by $49.8 million in cash acquired in the Lucero Acquisition. Revolving Credit Facility. In January 2023, we entered into the secured Revolving Credit Facility with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of banks, as lenders. The Revolving Credit Facility matures on October 22, 2028. Under the Revolving Credit Facility, we are permitted to make cash distributions without limit to our equity holders if (i) no event of default or borrowing base deficiency (i.e., outstanding debt (including loans and letters of credit) exceeds the borrowing base) then exists or would result from such distribution and (ii) after giving effect to such distribution, (a) our total outstanding credit usage does not exceed 80% of the least of (the following collectively referred to as “Commitments”): (1) $500 million, (2) our then-effective borrowing base, and (3) the then-effective aggregate amount of the aggregate elected commitments and (b) as of the date of such distribution, the EBITDAX Ratio does not exceed 1.50 to 1.00. If our EBITDAX Ratio does not exceed 2.25 to 1.00, and if our total outstanding credit usage does not exceed 80% of the Commitments, we may also make distributions if our free cash flow (as defined under the Revolving Credit Facility) is greater than $0 and we have delivered a certificate to our lenders attesting to the foregoing. The borrowing base under the Revolving Credit Facility is subject to regular, semi-annual redeterminations on or about April 1 and October 1 of each year based on, among other things, the value of our proved oil and natural gas reserves, as determined by the lenders in their discretion. As of June 30, 2026, our borrowing base and aggregate elected commitment was $275.0 million of which $158.5 million was outstanding. See Note 5 (“Credit Facility”) to the Condensed Consolidated Financial Statements for further details regarding the Revolving Credit Facility. 38 Table of Contents As previously disclosed, in conjunction with the semi-annual borrowing base redetermination, the Revolving Credit Facility was amended in April 2026 to decrease the borrowing base to $275 million and increase the elected commitments to $275 million. In addition, the derivative compliance requirement was amended to the less restrictive requirement described above. Material Cash Requirements. Our material short-term cash requirements include recurring payroll and benefits obligations for our employees, capital and operating expenditures and other working capital needs. If commodity prices improve, our working capital requirements may increase as we spend additional capital, increase production and pay larger settlements on our outstanding commodity derivative contracts. Conversely, working capital requirements would be expected to decrease if commodity prices decline. Our long-term material cash requirements from currently known obligations include settlements on our outstanding commodity derivative contracts, future obligations to plug, abandon and remediate our oil and gas properties at the end of their productive lives, and operating lease obligations. We cannot provide specific timing for repayments of outstanding borrowings on our Revolving Credit Facility, or the associated interest payments, as the timing and amount of borrowings and repayments cannot be forecasted with certainty and are based on working capital requirements, commodity prices and acquisition and divestiture activity, among other factors. We cannot provide specific timing for other current and long-term liability obligations where we cannot forecast with certainty the amount and timing of such payments, including asset retirement obligations, as the plugging and abandonment of wells is primarily at the discretion of the operators and any amounts we may be obligated to pay under our derivative contracts, as such payments are dependent on commodity prices in effect at the time of settlement. See Note 4 (“Fair Value Measurements”) to the Condensed Consolidated Financial Statements for further information on these contracts and their fair values as of June 30, 2026, which fair values represent the estimated cash settlement amount required to terminate such instruments based on forward price curves for commodities as of that date. Dividends. We paid cash dividends to our equity holders of $44.1 million during the six months ended June 30, 2026. While we believe that our future cash flows from operations will be able to sustain future dividends, future dividends may change based on a variety of factors, including contractual restrictions, legal limitations (the most common of which are limitations set forth in a company’s organizational documents and insolvency), business developments and the judgment of our Board. Future cash dividends to equity holders are subject to the terms of the Revolving Credit Facility, as previously described. There can be no guarantee that we will be able to pay dividends at current levels or at all or otherwise return capital to our investors in the future. Capital Expenditures. For the six months ended June 30, 2026, total capital expenditures was $39.4 million, including development expenditures and our acquisition and divestiture activity. We expect to fund future capital expenditures with cash generated from operations and, if required, borrowings under our Revolving Credit Facility. The foregoing excludes larger acquisitions, which are typically not included in our annual capital expenditures budget and which may be financed through equity consideration, like the Lucero Acquisition. With our cash on hand, cash flow from operations, and borrowing capacity under our Revolving Credit Facility, we believe that we will have sufficient cash flow and liquidity to fund our budgeted capital expenditures and operating expenses for at least the next twelve months. However, we may seek additional access to capital and liquidity including issuing equity or debt securities and extending maturities. We cannot assure you, however, that any additional capital will be available to us on favorable terms or at all. Our capital expenditures could be curtailed if our cash flows decline or we are otherwise unable to access capital or liquidity. Reductions of capital expenditures used to drill and complete new oil and natural gas wells would likely result in lower levels of oil and natural gas production in the future. Our future success in growing proved reserves and production may be dependent on our ability to access outside sources of capital. The amount, timing and allocation of capital expenditures are largely discretionary and subject to change based on a variety of factors. If oil and natural gas prices decline below our acceptable levels, or costs increase, we may choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected financial returns and potential to generate near-term cash flow. We may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We will carefully monitor and may adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing and joint venture opportunities, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, change in service costs, contractual obligations, internally generated cash flow and other factors both within and outside our control. For additional information on the impact of changing prices and market conditions on our financial position, see Part I. Item 3 Quantitative and Qualitative Disclosures About Market Risk. Effects of Inflation and Pricing. The oil and natural gas industry is cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put pressure on the economic stability and pricing structure within the industry. Higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel. Typically, as prices for oil and natural gas increase, so do all associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion. Material changes in prices also impact our revenue stream, estimates of future reserves, borrowing base calculations of bank loans, impairment assessments of oil and 39 Table of Contents natural gas properties, and values of properties in purchase and sale transactions. Such changes can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. Critical Accounting Policies and Estimates The critical accounting policies and estimates used in preparing our interim condensed consolidated financial statements for the three and six months ended June 30, 2026 are the same as those described in our Annual Report on Form 10-K for the year ended December 31, 2025. Recently Issued or Adopted Accounting Pronouncements For discussion of recently issued or adopted accounting pronouncements, see Note 2 (“Significant Accounting Policies”) to the Condensed Consolidated Financial Statements set forth in Part I, Item 1. Off Balance Sheet Arrangements We currently do not have any off-balance sheet arrangements that have or are reasonably likely to have a material current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources. 40 Table of Contents