Vitesse Energy, Inc.

Previous wording

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.

Current wording

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 September 30, 2026, we had a working interest in 7,427 gross (272.6 net) productive wells and 291 gross (6.5 net) wells that were being drilled or completed, and an additional 306 gross (13.0 net) wells that had been permitted for development by our operators. In addition, we had a royalty only interest in 1,305 gross (3.0 net) productive wells.

Previous wording

■Paid $20.6 million in dividends to our equity holders.

Current wording

■Paid $18.6 million in dividends to our equity holders.

Previous wording

■Production of 17,354 Boe/d with 60% of production from oil.

Current wording

■Production of 16,824 Boe/d with 60% of production from oil.

Previous wording

■Invested $20.7 million in capital development and acquisitions, net of divestitures.

Current wording

■Invested $53.0 million in capital development and acquisitions, net of divestitures.

Previous wording

■Total debt of $158.5 million at June 30, 2026.

Current wording

■Total debt of $190.5 million at September 30, 2026.

Previous wording

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.

Current wording

As a result of such commodity price volatility, which we expect to continue throughout the remainder of 2026 and into early 2027, 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.

Previous wording

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.

Current wording

Commodity derivative (loss) gain, 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.

Previous wording

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.

Current wording

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 nine months ended September 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.

Previous wording

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.

Current wording

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 nine months ended September 30, 2026 and 2025.

Previous wording

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.

Current wording

The average third quarter 2026 NYMEX oil price was $85.42 per barrel, or 32% higher than the average NYMEX oil price per barrel in the third quarter of 2025. Our settled derivatives decreased our third quarter 2026 realized oil price per barrel by $14.23 and increased our third quarter 2025 realized oil price per barrel by $2.98. Our average third quarter 2026 realized oil price per barrel after reflecting settled derivatives was $68.33 compared to $62.71 during the same period in 2025.

Previous wording

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.

Current wording

The average third quarter 2026 NYMEX natural gas price was $2.87 per MMBtu, or 5% lower than the average NYMEX price per MMBtu in the third quarter of 2025. Our settled derivatives increased our third quarter 2026 and 2025 realized natural gas price per Mcf by $0.33 and $0.29, respectively. Our average third quarter 2026 realized natural gas price per Mcf after reflecting settled derivatives was $2.06 compared to $1.14 during the same period in 2025.

Previous wording

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 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.

Current wording

The average year-to-date 2026 NYMEX oil price was $83.43 per barrel, or 25% 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 $13.45 and increased our average year-to-date 2025 realized oil price per barrel by $2.94. Our average year-to-date 2026 realized oil price per barrel after reflecting settled derivatives was $67.18 compared to $63.90 during the same period in 2025.

Previous wording

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.

Current wording

The average year-to-date 2026 NYMEX natural gas price was $3.49 per MMBtu, or 1% higher than the 2025 average year-to-date price per MMBtu. Our settled derivatives increased our average year-to-date 2026 and 2025 realized natural gas price per Mcf by $0.02 and $0.11, respectively. Our average year-to-date 2026 realized natural gas price per Mcf after reflecting settled derivatives was $1.72 compared to $2.71 during the same period in 2025.

Previous wording

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.

Current wording

Oil and Natural Gas Revenue and Volumes. Oil and natural gas revenue increased to $83.0 million for the three months ended September 30, 2026 from $67.4 million for the three months ended September 30, 2025. The increase in oil and natural gas revenue was due to a 33% increase in the average realized prices per Boe before hedging, partially offset by a 7% decrease in production volumes for the three months ended September 30, 2026. The increase in average realized prices per Boe before hedging increased oil and natural gas revenue by $22.1 million, while the decrease in production volumes decreased oil and natural gas revenue by $6.6 million.

Previous wording

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.

Current wording

Our oil price differential to the weighted average benchmark price during the three months ended September 30, 2026 was negative $3.50 per barrel, as compared to a negative $5.35 per barrel during the three months ended September 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 September 30, 2026 was $1.73 per Mcf, representing a 60% realization relative to the weighted average NYMEX natural gas price, compared to a net realized natural gas price of $0.85 per Mcf during the three months ended September 30, 2025, representing a 28% realization relative to the weighted average NYMEX natural gas price. 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.

Previous wording

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.

Current wording

Lease Operating Expense. Lease operating expense increased to $19.2 million for the three months ended September 30, 2026 from $18.5 million for the three months ended September 30, 2025. The increase is attributable to a 12% increase in lease operating expense on a per Boe basis, partially offset by a 7% decrease in production between periods.

Previous wording

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.

Current wording

Production Tax Expense. Total production taxes increased to $7.5 million for the three months ended September 30, 2026 from $6.2 million for the three months ended September 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 9.0% and 9.2% for the three months ended September 30, 2026 and 2025, respectively.

Previous wording

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.

Current wording

General and Administrative Expense. General and administrative expense decreased to $4.9 million for the three months ended September 30, 2026 from $5.7 million for the three months ended September 30, 2025. Excluding Lucero Acquisition transaction costs of $0.3 million, general and administrative expense on a per Boe basis was $3.27 for the three months ended September 30, 2025 compared to $3.19 for the three months ended September 30, 2026.

Previous wording

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.

Current wording

DD&A. DD&A decreased to $32.8 million for the three months ended September 30, 2026 compared with $34.2 million for the three months ended September 30, 2025. The decrease was the result of a 7% decrease in production, partially offset by a 3% increase in the DD&A rate for the three months ended September 30, 2026 compared with the three months ended September 30, 2025. The decrease in production accounted for a $2.6 million decrease in DD&A expense while the increase in the DD&A rate accounted for a $1.2 million increase in DD&A expense.

Previous wording

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.

Current wording

For the three months ended September 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 $20.98 per Boe compared with $20.32 per Boe for the three months ended September 30, 2025.

Previous wording

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.

Current wording

Equity-Based Compensation. During the three months ended September 30, 2026, equity-based compensation expense decreased to $2.2 million from $2.7 million during the three months ended September 30, 2025. Equity-based compensation expense was lower in 2026, primarily driven by a lower number of unvested LTIP RSUs, as awards granted in prior periods completed their vesting.

Previous wording

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.

Current wording

Interest Expense. Interest expense increased to $3.3 million for the three months ended September 30, 2026 from $2.4 million for the three months ended September 30, 2025. The increase for the three months ended September 30, 2026 was primarily due to a higher average debt balance during the period.

Previous wording

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.

Current wording

Commodity Derivative (Loss) Gain, Net. The commodity derivative loss was $58.6 million for the three months ended September 30, 2026 compared with a gain of $0.7 million for the three months ended September 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.

Previous wording

(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.

Current wording

(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 (loss) gain 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.

Previous wording

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.

Current wording

In the three months ended September 30, 2026, 76% of our oil volumes were covered by financial hedges, which resulted in a realized loss on oil derivatives of $13.2 million. In the three months ended September 30, 2026, approximately 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 $1.2 million. In the three months ended September 30, 2025, 63% of our oil volumes were covered by financial hedges, which resulted in a realized gain on oil derivatives of $3.2 million. In the three months ended September 30, 2025, a portion of our natural gas volumes was covered by residue gas and NGL financial hedges, which resulted in a realized gain on gas and NGL derivatives of $1.0 million.

Previous wording

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.

Current wording

At September 30, 2026, all of our derivative contracts were recorded at their fair value, which was a net liability of $40.2 million, a decrease in value of $46.6 million from the $6.4 million net asset recorded as of June 30, 2026. Derivative contract fair value is recorded in part based on published forward commodity prices. This decrease in fair value was largely driven by the NYMEX WTI price increasing from $69.50/Bbl at June 30, 2026 to $90.42/Bbl at September 30, 2026 and the corresponding change in forward commodity prices.

Previous wording

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.

Current wording

Income Tax Expense. During the three months ended September 30, 2026, we recorded an income tax benefit of $9.1 million related to federal and state income taxes compared to an income tax benefit of $0.3 million for the three months ended September 30, 2025.

Previous wording

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.

Current wording

Oil and Natural Gas Revenue and Volumes. Oil and natural gas revenue increased to $241.4 million for the nine months ended September 30, 2026 from $215.4 million for the nine months ended September 30, 2025. The increase in oil and natural gas revenue was due to a 16% increase in the average realized prices per Boe before hedging, which was partially offset by a 4% decrease in production volumes for the nine months ended September 30, 2026. The increase in average realized prices per Boe before hedging increased oil and natural gas revenue by $35.5 million, while the decrease in production volumes decreased oil and natural gas revenue by $9.5 million.

Previous wording

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.

Current wording

During the nine months ended September 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.

Previous wording

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.

Current wording

Our oil price differential to the weighted average benchmark price during the nine months ended September 30, 2026 was negative $3.24 per barrel, as compared to a negative $5.33 per barrel during the nine months ended September 30, 2025, primarily due to more favorable local market pricing as compared to the benchmark price. Our net realized natural gas price during the nine months ended September 30, 2026 was $1.70 per Mcf, representing a 49% realization relative to the weighted average NYMEX natural gas price, compared to a net realized natural gas price of $2.60 per Mcf during the nine months ended September 30, 2025, representing a 77% 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.

Previous wording

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.

Current wording

Lease Operating Expense. Lease operating expense increased to $52.5 million for the nine months ended September 30, 2026 from $51.9 million for the nine months ended September 30, 2025. The increase is attributable to a 5% increase in lease operating expense on a per Boe basis, partially offset by a 4% decrease in production between periods.

Previous wording

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.

Current wording

Production Tax Expense. Total production taxes increased to $21.6 million for the nine months ended September 30, 2026 from $18.2 million for the nine months ended September 30, 2025. Production taxes are primarily based on oil revenue and natural gas revenue, excluding gains and losses associated with hedging activities. Production taxes as a percentage of oil and natural gas sales before hedging adjustments were 9.0% and 8.4% for the nine months ended September 30, 2026 and 2025, respectively. The production tax rate was lower for the nine months ended September 30, 2025 due to the legal settlement increasing revenue in the period.

Previous wording

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.

Current wording

General and Administrative Expense. General and administrative expense increased to $19.7 million for the nine months ended September 30, 2026 from $18.2 million for the nine months ended September 30, 2025. During the nine months ended September 30, 2026, $2.4 million in separation benefits related to our leadership transition were incurred. During the nine months ended September 30, 2025, $7.1 million of litigation costs were reimbursed as a result of a legal settlement and Lucero Acquisition transaction costs of $5.2 million were incurred. Excluding these one-time costs, general and administrative expense on a per Boe basis increased to $3.79 for the nine months ended September 30, 2026 from $3.64 for the nine months ended September 30, 2025.

Previous wording

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.

Current wording

DD&A. DD&A increased to $98.8 million for the nine months ended September 30, 2026 from $95.4 million for the nine months ended September 30, 2025. The increase was the result of a $1.54 per Boe increase in the DD&A rate, partially offset by a 4% decrease in production for the nine months ended September 30, 2026 compared with the nine months ended September 30, 2025. The increase in the DD&A rate accounted for a $7.3 million increase in DD&A expense while the decrease in production accounted for a $3.9 million decrease in DD&A expense.

Previous wording

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.

Current wording

For the nine months ended September 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 $21.44 per Boe compared with $19.95 per Boe for the nine months ended September 30, 2025.

Previous wording

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.

Current wording

Equity-Based Compensation. During the nine months ended September 30, 2026, equity-based compensation expense decreased to $5.6 million from $7.6 million during the nine months ended September 30, 2025. Equity-based compensation expense was lower in 2026 due to a $1.4 million reversal of expense for forfeited awards during the period and a lower number of unvested LTIP RSUs, as awards granted in prior periods completed their vesting.

Previous wording

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.

Current wording

Interest Expense. Interest expense increased to $8.9 million for the nine months ended September 30, 2026 from $7.8 million for the nine months ended September 30, 2025. The increase for the nine months ended September 30, 2026 was due to a higher average debt balance during the nine months ended September 30, 2026 compared to the nine months ended September 30, 2025.

Previous wording

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.

Current wording

Commodity Derivative (Loss) Gain, Net. The commodity derivative loss was $91.6 million for the nine months ended September 30, 2026 compared with a gain of $19.0 million for the nine months ended September 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.

Previous wording

(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.

Current wording

(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 (loss) gain 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.

Previous wording

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.

Current wording

In the nine months ended September 30, 2026, 74% of our oil volumes were subject to financial hedges, which resulted in a realized loss on oil derivatives of $37.2 million. In the nine months ended September 30, 2026, approximately 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 $0.3 million. In the nine months ended September 30, 2025, 62% of our oil volumes were subject to financial hedges, which resulted in a realized gain on oil derivatives of $9.2 million. In the nine months ended September 30, 2025, a portion of our natural gas volumes was covered by residue gas and NGL financial hedges, which resulted in a realized gain on gas and NGL derivatives of $1.0 million.