Vitesse Energy, Inc. (VTS)

CIK: 0001944558. SIC: 1311 Crude Petroleum & Natural Gas. Latest 10-K as of: 2026-03-02.

SIC breadcrumb: Mining > SIC Major Group 13 > SIC 1311 Crude Petroleum & Natural Gas

SEC company page: https://www.sec.gov/edgar/browse/?CIK=1944558. Latest filing source: 0001944558-26-000009.

Selected Fundamentals

Metric	Value	Unit	FY	Filed
Revenue	273,989,000	USD	2025	2026-03-02
Net income	25,277,000	USD	2025	2026-03-02
Assets	893,350,000	USD	2025	2026-03-02

Financials

Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-03-02. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001944558.json. Derived margins, ratios, and free cash flow are computed from the extracted annual SEC facts.

Flow metrics use full-year FY periods from 10-K/10-K/A filings; balance-sheet metrics use FY-end instants. Free cash flow = operating cash flow - capital expenditures. Missing metrics are omitted rather than fabricated.

Metric	2020	2021	2022	2023	2024	2025
Revenue	97,230,000	167,835,000	281,890,000	233,905,000	241,998,000	273,989,000
Net income	-8,857,000	18,114,000	118,903,000	-19,744,000	21,060,000	25,277,000
Operating income	-33,833,000	53,897,000	153,866,000	34,854,000	40,971,000	17,129,000
Diluted EPS	-0.02	0.04	0.26	-0.73	0.64	0.64
Operating cash flow	76,309,000	86,971,000	147,041,000	141,942,000	155,003,000	170,349,000
Dividends paid		12,000,000	36,000,000	57,999,000	63,560,000	92,133,000
Share buybacks		0.00	0.00	248,000	0.00	0.00
Assets		611,526,000	660,484,000	765,970,000	810,893,000	893,350,000
Liabilities		125,662,000	91,502,000	219,564,000	310,559,000	264,033,000
Stockholders' equity		480,074,000	564,423,000	546,406,000	500,334,000	629,317,000

Ratios

ROE and ROA use period-end equity/assets. Liabilities / equity uses total liabilities divided by stockholders' equity. Current ratio uses current assets divided by current liabilities when both are reported.

Metric	2020	2021	2022	2023	2024	2025
Net margin	-9.11%	10.79%	42.18%	-8.44%	8.70%	9.23%
Operating margin	-34.80%	32.11%	54.58%	14.90%	16.93%	6.25%
Return on equity		3.77%	21.07%	-3.61%	4.21%	4.02%
Return on assets		2.96%	18.00%	-2.58%	2.60%	2.83%
Liabilities / equity		0.26	0.16	0.40	0.62	0.42
Current ratio		0.90	1.48	0.97	0.51	1.02

Financial Charts

Quarterly

Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-05-04. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001944558.json.

Flow metrics use discrete quarter-length periods from 10-Q/10-Q/A filings. Q4 revenue and net income are derived only when annual FY and nine-month YTD facts exist for the same fiscal year; derived Q4 values are labeled. EPS Q4 is not derived.

Quarter	End Date	Revenue	Net Income	Diluted EPS	Method
2023-Q1	2023-03-31			-1.67	reported discrete quarter
2023-Q2	2023-03-31		-47,815,000		reported discrete quarter
2023-Q2	2023-06-30	51,588,000		0.29	reported discrete quarter
2023-Q3	2023-06-30		9,620,000		reported discrete quarter
2023-Q3	2023-09-30	55,054,000		-0.05	reported discrete quarter
2023-Q4	2023-12-31	69,303,000	19,917,000		derived Q4 = FY annual - nine-month YTD
2024-Q1	2024-03-31	61,193,000	-2,186,000	-0.07	reported discrete quarter
2024-Q2	2024-03-31		-2,186,000		reported discrete quarter
2024-Q2	2024-06-30	66,598,000		0.33	reported discrete quarter
2024-Q3	2024-06-30		10,928,000		reported discrete quarter
2024-Q3	2024-09-30	58,280,000		0.53	reported discrete quarter
2024-Q4	2024-12-31	55,926,000	-5,125,000		derived Q4 = FY annual - nine-month YTD
2025-Q1	2025-03-31	66,171,000	2,668,000	0.08	reported discrete quarter
2025-Q2	2025-03-31		2,668,000		reported discrete quarter
2025-Q2	2025-06-30	81,755,000		0.60	reported discrete quarter
2025-Q3	2025-06-30		24,659,000		reported discrete quarter
2025-Q3	2025-09-30	67,443,000		-0.03	reported discrete quarter
2025-Q4	2025-12-31	58,620,000	-739,000		derived Q4 = FY annual - nine-month YTD
2026-Q1	2026-03-31	67,410,000	-42,280,000	-1.05	reported discrete quarter

Quarterly Charts

Macro Cross-References

CPIAUCSL - Consumer Price Index for All Urban Consumers: All Items in U.S. City Average
UNRATE - Unemployment Rate
FEDFUNDS - Federal Funds Effective Rate
CES0500000003 - Average Hourly Earnings of All Employees, Total Private
DFEDTARU - Federal Funds Target Range - Upper Limit
DFEDTARL - Federal Funds Target Range - Lower Limit
DGS3MO - Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity
DGS2 - Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity
DGS10 - Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity
DGS30 - Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity
T10Y2Y - 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity
CPILFESL - Consumer Price Index for All Urban Consumers: All Items Less Food and Energy
CPIUFDSL - Consumer Price Index for All Urban Consumers: Food
CPIENGSL - Consumer Price Index for All Urban Consumers: Energy
CUSR0000SAH1 - Consumer Price Index for All Urban Consumers: Shelter
PCEPI - Personal Consumption Expenditures: Chain-type Price Index
PCEPILFE - Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index
PPIACO - Producer Price Index by Commodity: All Commodities
T10YIE - 10-Year Breakeven Inflation Rate
U6RATE - Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons
PAYEMS - All Employees, Total Nonfarm
CIVPART - Labor Force Participation Rate
EMRATIO - Employment-Population Ratio
UNEMPLOY - Unemployed
CE16OV - Employment Level
ICSA - Initial Claims
JTSJOL - Job Openings: Total Nonfarm
JTSQUR - Quits: Total Nonfarm
GDPC1 - Real Gross Domestic Product
A191RL1Q225SBEA - Real Gross Domestic Product: Percent Change from Preceding Period
INDPRO - Industrial Production: Total Index
TCU - Capacity Utilization: Total Index
HOUST - New Privately-Owned Housing Units Started: Total Units
PERMIT - New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units
RSAFS - Advance Retail Sales: Retail Trade
PCE - Personal Consumption Expenditures
DSPIC96 - Real Disposable Personal Income
PSAVERT - Personal Saving Rate
M2SL - M2
BOPGSTB - U.S. International Trade in Goods and Services: Balance
MSPUS - Median Sales Price of Houses Sold for the United States
HSN1F - New One Family Houses Sold: United States
RHORUSQ156N - Homeownership Rate in the United States
TTLCONS - Total Construction Spending: Total Construction in the United States
RRVRUSQ156N - Rental Vacancy Rate in the United States
TOTALSL - Total Consumer Credit Owned and Securitized
REVOLSL - Revolving Consumer Credit Owned and Securitized
DRCCLACBS - Delinquency Rate on Credit Card Loans, All Commercial Banks
GDP - Gross Domestic Product
GPDI - Gross Private Domestic Investment
GCE - Government Consumption Expenditures and Gross Investment
PCEC - Personal Consumption Expenditures
NETEXP - Net Exports of Goods and Services
GFDEBTN - Federal Debt: Total Public Debt
GFDEGDQ188S - Federal Debt: Total Public Debt as Percent of Gross Domestic Product
FYFSD - Federal Surplus or Deficit
FGRECPT - Federal Government Current Receipts
FGEXPND - Federal Government: Current Expenditures
MANEMP - All Employees, Manufacturing
USCONS - All Employees, Construction
USTRADE - All Employees, Retail Trade
USFIRE - All Employees, Financial Activities
USGOVT - All Employees, Government
AWHAETP - Average Weekly Hours of All Employees, Total Private
DGORDER - Manufacturers' New Orders: Durable Goods
NEWORDER - Manufacturers' New Orders: Nondefense Capital Goods Excluding Aircraft
BUSINV - Total Business Inventories
EXPGS - Exports of Goods and Services
IMPGS - Imports of Goods and Services
IR - Import Price Index (End Use): All Commodities
PPIFIS - Producer Price Index by Commodity: Final Demand

Latest quarter (10-Q)

Latest 10-Q source: 0001944558-26-000024.

Extracted structurally from real Item 2 body heading to real Item 3/4 boundary. Confidence: high. Filing date: 2026-05-04. Report date: 2026-03-31.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

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 March 31, 2026, we had a working interest in 6,427 gross (226.0 net) productive wells and 303 gross (6.2 net) wells that were being drilled or completed, and an additional 282 gross (13.7 net) wells that had been permitted for development by our operators. In addition, we had a royalty only interest in 1,299 gross (3.1 net) productive wells.

On March 26, 2026 we announced a leadership transition with Jamie Benard set to join our team as President and Chief Executive Officer effective May 1, 2026, the resignation of Robert Gerrity as our Chief Executive Officer and Chairman and the transition on May 1, 2026 of Brian Cree our existing President and Interim Chief Executive Officer transitioning to Senior Advisor and his retirement on December 31, 2026. This leadership transition does not change our overall business strategy.

Our financial and operating performance for the three months ended March 31, 2026 included the following:

■Paid $23.5 million in dividends to our equity holders.

■Production of 15,962 Boe/d with 63% of production from oil.

■Total revenue of $67.4 million.

■Net loss of $42.3 million, including an unrealized loss on commodity derivatives of $48.2 million.

■Cash flows from operations of $24.0 million.

■Invested $18.7 million in capital development and acquisitions, net of divestitures.

■Total debt of $144.5 million at March 31, 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, 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.

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Source of Our Revenues

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 three months ended March 31, 2025, general and administrative expenses included non-recurring costs related to the Lucero Acquisition.

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 months ended March 31, 2026 and 2025.

[Excerpt truncated for page length; source filing is linked above.]

Latest 10-K MD&A

Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary. Confidence: high. Filing date: 2026-03-02. Report date: 2025-12-31.

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

You should read the following discussion of our results of operations and financial condition together with our Audited Consolidated Financial Statements and the notes thereto included under the section entitled “Index to Financial Statements,” as well as the discussion in Part I. Items 1 and 2. Business and Properties. 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 Part I. Item 1A. Risk Factors and “Cautionary Statement Concerning Forward-Looking Statements.”

This section generally discusses certain 2025 and 2024 items and certain year-to-year comparisons between 2025 and 2024. Discussions of 2023 items and year-to-year comparisons between 2024 and 2023 that are not included in this Form 10-K can be found in Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2024, filed on March 12, 2025 which is incorporated herein by reference.

Unless otherwise indicated, the financial, reserve and operational information presented does not reflect the Lucero Acquisition for periods prior to 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 December 31, 2025, we had a working interest in 6,402 gross (226.1 net) productive wells and 283 gross (6.1 net) wells that were being drilled or completed, and an additional 336 gross (15.9 net) wells that had been permitted for development by us or our operators. In addition, we had a royalty only interest in 1,301 gross (3.2 net) productive wells.

Our financial and operating performance for the year ended December 31, 2025 included the following:

■Paid $92.1 million in dividends to our equity holders.

■Production of 17,444 Boe/d with 65% of production from oil.

■Total revenue of $274.0 million.

■Net income of $25.3 million.

■Cash flows from operations of $170.3 million.

■Invested $127.7 million in capital development and acquisitions.

■Proved reserves of 47.8 MMBoe and $473 million PV-10 value at December 31, 2025, as estimated by our third-party reserve engineers using SEC guidelines.

■Total debt of $124.5 million at December 31, 2025.

See Non-GAAP Financial Information for additional information about PV-10.

On March 7, 2025, we closed the Lucero Acquisition pursuant to which we acquired Lucero in an all-stock transaction. Lucero shareholders received 8,169,368 shares of Vitesse common stock. Lucero is an oil and natural gas operator with assets in the Bakken and Three Forks formations in the Williston Basin area of North Dakota.

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 periodic downturns and sustained volatility, impacted by general economic and political conditions, the conflict between Russia and Ukraine, hostilities in the Middle East, the evolving situation in Venezuela, 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.

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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 a prolonged U.S. government shutdown. 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

Principal Components of Our Cost Structure

Commodity derivatives gain (loss), net. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the prices of oil and natural 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.

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. For fiscal 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 the settlement discussed in Note 11 (“Commitments and Contingencies”) to the 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 include the amortization of deferred financing costs, commitment fees and annual agency fees as interest expense.

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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 years ended December 31, 2025, 2024 and 2023.

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 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 conflict in Ukraine, hostilities in the Middle East, the evolving situation in Venezuela and the strength of the U.S. dollar can adversely 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.

YEAR ENDED DECEMBER 31,

Average Daily Prices (1)

2025

2024

2023

WTI Oil (per Bbl)

64.60

75.69

77.58

Natural Gas (per MMBtu)

3.52

2.19

2.53

(1)Based on average daily NYMEX WTI and Henry Hub Spot closing prices reported by FactSet and the EIA, respectively.

The average calendar 2025 WTI oil price was $64.60 per Bbl or 15% lower than the average WTI price per Bbl in calendar 2024. Our settled derivatives increased our realized oil price per Bbl by $3.81 in calendar 2025 and increased our realized oil price per Bbl by $1.54 in calendar 2024. Our average 2025 realized oil price per Bbl after reflecting settled derivatives was $62.95 compared to $71.48 in 2024. The average calendar 2025 NYMEX natural gas price was $3.52 per MMBtu, or 61% higher than the average NYMEX price per MMBtu in calendar 2024. Our settled derivatives increased our realized gas price per Mcf by $0.10 in calendar 2025. We had no gas price derivatives in place in calendar 2024. Our 2025 realized natural gas price per Mcf after reflecting settled derivatives was $2.31 compared to $1.34 in 2024.

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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 II. Item 7A. Quantitative and Qualitative Disclosures about Market Risk and Note 6 (“Derivative Instruments”) to 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.

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Results of Operations

Year Ended December 31, 2025 Compared with Year Ended December 31, 2024

The following table sets forth selected operating data for the periods indicated.

YEAR ENDED

DECEMBER 31,

INCREASE

(DECREASE)

($ in thousands, except per unit data)

2025

2024

AMOUNT

PERCENT

Operating Results:

Revenue

Oil

244,414

230,164

14,250

Natural gas

29,575

11,834

17,741

150

Total revenue

273,989

241,998

31,991

Operating Expenses

Lease operating expense

69,535

47,599

21,936

Production taxes

23,354

21,500

1,854

General and administrative

24,314

23,510

804

Depletion, depreciation, amortization, and accretion

129,411

100,308

29,103

Equity-based compensation

10,246

8,110

2,136

Interest Expense

10,205

9,980

225

Income Tax Expense

9,798

7,672

2,126

Commodity Derivative Gain (Loss)

27,930

(2,348)

30,278

Production Data:

Oil (MBbls)

4,133

3,291

842

Natural gas (MMcf)

13,403

8,809

4,594

Combined volumes (MBoe)

6,367

4,759

1,608

Daily combined volumes (Boe/d)

17,444

13,003

4,441

Average Realized Prices before Hedging:

Oil (per Bbl)

59.14

69.94

(10.80)

(15

Natural gas (per Mcf)

2.21

1.34

0.87

Combined (per Boe)

43.03

50.85

(7.82)

(15

Average Realized Prices with Hedging:

Oil (per Bbl)

62.95

71.48

(8.53)

(12

Natural gas (per Mcf)

2.31

1.34

0.97

Combined (per Boe)

45.72

51.91

(6.19)

(12

Average Costs (per Boe):

Lease operating expense

10.92

10.00

0.92

Production taxes

3.67

4.52

(0.85)

(19

General and administrative

3.82

4.94

(1.12)

(23

Depletion, depreciation, amortization, and accretion

20.33

21.08

(0.75)

*Not meaningful

Oil and Natural Gas Revenue and Volumes. Oil and natural gas revenue increased to $274.0 million for the year ended December 31, 2025 from $242.0 million for the year ended December 31, 2024. The increase in oil and natural gas revenue was due to a 34% increase in production volumes, and was partially offset by a 15% decrease in the average realized prices per Boe before hedging for the year ended December 31, 2025. The increase in production volumes increased oil and natural gas revenue by approximately $69.2 million, while the decrease in average realized prices per Boe before hedging decreased oil and natural gas revenue by approximately $37.2 million. The increase in production volumes was in part due to the Lucero Acquisition.

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During the year ended December 31, 2025, $3.3 million and $13.6 million of recoupments of oil and gas revenue, respectively, were recognized as part of the settlement discussed in Note 11 (“Commitments and Contingencies”) to the Consolidated Financial Statements. Our oil price differential to the weighted average benchmark price during the year ended December 31, 2025 was negative $5.40 per Bbl, as compared to a negative $5.90 per Bbl during the year ended December 31, 2024, primarily due to the legal settlement increasing the realized price per Bbl in the period, partially offset by less favorable local market pricing as compared to the benchmark price. Our net realized natural gas price during the year ended December 31, 2025 was $2.21 per Mcf, representing a 64% realization relative to the weighted average NYMEX natural gas price, compared to a net realized natural gas price of $1.34 per Mcf during the year ended December 31, 2024, representing a 62% realization relative to the weighted average NYMEX natural gas price. The higher realized price was primarily due to the legal settlement increasing the realized price per Mcf in the 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 increased to $10.92 per Boe for the year ended December 31, 2025 from $10.00 per Boe for the year ended December 31, 2024. The increase per Boe for the year ended December 31, 2025 compared with the year ended December 31, 2024 was due in part to a $1.10 per Boe increase in workover costs between periods, driven by the properties from the Lucero Acquisition.

Production Tax Expense. Total production taxes increased to $23.4 million for the year ended December 31, 2025 from $21.5 million for the year ended December 31, 2024. 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 8.5% and 8.9% for the years ended December 31, 2025 and 2024, respectively. The lower production tax rate was driven by the production mix and the relative tax rates on oil and natural gas revenue.

General and Administrative Expense. General and administrative expense increased to $24.3 million for the year ended December 31, 2025 from $23.5 million for the year ended December 31, 2024. During the year ended December 31, 2025, $7.1 million of litigation costs were reimbursed as a result of the settlement discussed in Note 11 (“Commitments and Contingencies”) to the Consolidated Financial Statements. Excluding net litigation costs and Lucero Acquisition transaction costs of $0.9 million and $2.2 million for the years ended December 31, 2025 and 2024, respectively, general and administrative expense on a per Boe basis decreased to $3.68 for the year ended December 31, 2025 from $4.47 for the year ended December 31, 2024. The decrease in per Boe cost is associated with economies of scale on a 34% increase in production between periods and impacts from the Lucero Acquisition.

DD&A. DD&A increased to $129.4 million for the year ended December 31, 2025 compared with $100.3 million for the year ended December 31, 2024. The increase of $29.1 million or 29% was the result of a 34% increase in production and a 4% decrease in the DD&A rate for the year ended December 31, 2025 compared with the year ended December 31, 2024. The increase in production accounted for a $32.7 million increase in DD&A expense while the decrease in the DD&A rate accounted for a $3.6 million decrease in DD&A expense.

For the year ended December 31, 2025, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate (excluding depreciation, amortization and accretion) of $20.16 per Boe compared with $20.92 per Boe for the year ended December 31, 2024. The lower DD&A rate was driven by the properties acquired in the Lucero Acquisition in 2025 and was partially offset by decreased oil and natural gas reserves related to the lower oil and natural gas prices combined with higher operating expenses.

Equity-based Compensation. During the year ended December 31, 2025, equity-based compensation expense increased to $10.2 million from $8.1 million during the year ended December 31, 2024. Equity-based compensation expense was higher in 2025 due to additional LTIP RSUs and PSUs awarded to employees and directors at a higher grant date price.

Interest Expense. Interest expense increased to $10.2 million for the year ended December 31, 2025 from $10.0 million for the year ended December 31, 2024. The increase for the year ended December 31, 2025 was due to a higher average debt balance during the year ended December 31, 2025 compared to 2024 partially offset by a lower interest rate.

Commodity Derivative Gain (Loss). The net commodity derivative gain was $27.9 million for the year ended December 31, 2025 compared with a loss of $2.3 million for the year ended December 31, 2024. 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

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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.

YEAR ENDED DECEMBER 31,

(in thousands)

2025

2024

Realized gain on commodity derivatives (1)

17,116

5,065

Unrealized gain (loss) on commodity derivatives (1)

10,814

(7,413)

Total commodity derivative gain (loss)

27,930

(2,348)

(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 consolidated statements of operations included in this Annual Report on Form 10-K. 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 2025, approximately 61% of our oil volumes were covered by financial hedges, which resulted in a realized gain on oil derivatives of $15.8 million. In 2025, approximately half of our natural gas volume was covered by residue gas and NGL financial hedges, which resulted in a realized gain on gas and NGL derivatives of $1.4 million. In 2024, approximately 59% of our oil volumes and none of our natural gas volumes were covered by financial hedges, which resulted in a realized gain on oil derivatives of $5.1 million.

At December 31, 2025, all of our derivative contracts were recorded at their fair value, which was a net asset of $14.4 million, an increase of $10.7 million from the $3.7 million net asset recorded as of December 31, 2024. The increase was primarily due to decreases in forward commodity prices since December 31, 2024 relative to prices on our open commodity derivative contracts.

Income Tax Expense. We recorded income tax expense of $9.8 million and $7.7 million for the years ended December 31, 2025 and 2024, respectively, related to federal and state income taxes. The effective tax rates of 27.9% and 26.7% for the years ended December 31, 2025 and 2024, respectively, 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, state income taxes and non-amortizable transaction costs.

Liquidity and Capital Resources

Overview. At December 31, 2025 and 2024, we had $1.3 million and $3.0 million of unrestricted cash on hand and $125.5 million and $118.0 million available under the elected commitments in our Revolving Credit Facility, respectively. 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 December 31, 2025, we had a working capital surplus of $0.9 million, compared to a deficit of $49.4 million at December 31, 2024. Current assets increased by $1.3 million while current liabilities decreased by $49.1 million at December 31, 2025, compared to December 31, 2024. The increase in current assets in 2025 as compared to 2024 was primarily due to an increase of $10.4 million in our commodity derivative instruments due to forward oil price decreases as compared to hedged oil prices, partially offset by a decrease of $9.2 million in accrued revenue driven by improved collections. The decrease in current liabilities in 2025 as compared to 2024 was primarily due to an decrease of $49.1 million in accounts payable and accrued liabilities as a result of decreased development activity.

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Cash Flows. Our cash flows for the years ended December 31, 2025 and 2024 are presented below:

FOR THE YEARS ENDED DECEMBER 31,

(in thousands)

2025

2024

Cash flows provided by operating activities

170,349

155,003

Cash flows used in investing activities

(127,662)

(115,321)

Cash flows used in financing activities

(44,326)

(37,267)

Net change in cash

(1,639)

2,415

During the year ended December 31, 2025, we generated $170.3 million of cash from operations, an increase of 10% from the year ended December 31, 2024 driven by a 13% increase in total revenue. Cash flows from operating activities are primarily affected by production volumes, which increased with the Lucero Acquisition, and commodity prices, net of the effects of settlements of our derivative contracts, and by changes in working capital. Any interim cash needs are funded by cash on hand, cash flows from operations or borrowings under our Revolving Credit Facility. We typically enter into commodity derivative transactions covering a substantial, but varying, portion of our anticipated future oil and gas production for the next 12 to 24 months. A minimum level of derivative coverage is required by certain debt covenants. See Part II. Item 7A. 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. As of December 31, 2025, for calendar 2026 we had oil swaps covering 1,608,134 Bbls at a weighted average price of $64.52 per Bbl, oil collars covering 66,000 Bbls with a weighted average floor and ceiling of $50.00 per Bbl and $68.80 per Bbl, respectively, natural gas collars covering 4,638,900 MMBtu with a weighted average floor and ceiling of $3.73 per MMBtu and $4.99 per MMBtu, respectively, natural gas basis swaps (Chicago City Gate to Henry Hub) covering the same MMBtu at a weighted average price of ($0.121) per MMBtu, and various natural gas liquid swaps covering 6,410,000 gallons at a weighted average price of $0.67 per gallon. For calendar 2027, we had natural gas collars covering 795,000 MMBtu with a weighted average floor and ceiling of $4.00 per MMBtu and $5.68 per MMBtu, respectively, and basis swaps (Chicago City Gate to Henry Hub) covering the same MMBtu at a weighted average price of $0.300 per MMBtu. For more information on our outstanding derivatives, see Note 6 (“Derivative Instruments”) to the Consolidated Financial Statements.

Cash used in investing activities during the years ended December 31, 2025 and 2024 was $127.7 million and $115.3 million, respectively. Cash used in investing activities primarily relates to capital expenditures for acquisition and development costs. Development costs for the year ended December 31, 2025 included $11.0 million for completion costs on two wells from the Lucero Acquisition. 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 cash spending for acquisition activities was $6.6 million and $21.1 million during the years ended December 31, 2025 and 2024, respectively.

Cash used in financing activities was $44.3 million and $37.3 million during the years ended December 31, 2025 and 2024, respectively. The cash used in financing activities during the year ended December 31, 2025 was primarily related to $92.1 million in dividends paid and $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 associated with the Lucero Acquisition and $7.5 million of net borrowings under our Revolving Credit Facility. The cash used in financing activities during the year ended December 31, 2024 was primarily related to $63.6 million in dividends paid and $7.5 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 $36.0 million of net borrowings under our Revolving Credit Facility.

Revolving Credit Facility. In connection with the Spin-Off, 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 will mature 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

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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 the Company’s proved oil and natural gas reserves, as determined by the lenders in their discretion. As of December 31, 2025, the Company’s borrowing base was $295.0 million with an aggregate elected commitment of $250.0 million of which $124.5 million was outstanding. See Note 5 (“Credit Facility”) to the Consolidated Financial Statements for further details regarding the Revolving Credit Facility.

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 Consolidated Financial Statements for further information on these contracts and their fair values as of December 31, 2025, 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 $92.1 million during the year ended December 31, 2025. 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 year ended December 31, 2025 total capital expenditures was $127.7 million, including development expenditures and our acquisition 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 II. Item 7A Quantitative and Qualitative Disclosures About Market Risk.

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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 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.

Non-GAAP Financial Information

Reconciliation of PV-10 to Standardized Measure

PV-10 is derived from the Standardized Measure, which is the most directly comparable GAAP financial measure for proved reserves. PV-10 is a computation of the Standardized Measure on a pre-tax basis. PV-10 is equal to the Standardized Measure at the applicable date, before deducting future income taxes, discounted at ten percent. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated proved reserves prior to taking into account future income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure. PV-10 and the Standardized Measure do not purport to represent the fair value of our oil and natural gas reserves.

The table below reconciles the pre-tax PV-10 value of our proved reserves at SEC prices as of December 31, 2025 to the Standardized Measure.

FOR THE YEAR ENDED DECEMBER 31,

(in thousands)

2025

Pre-Tax Present Value of Estimated Future Net Revenues (Pre-Tax PV10%)

472,685

Future Income Taxes, Discounted at 10%

(33,709)

Standardized Measure of Discounted Future Net Cash Flows

438,976

Uncertainties are inherent in estimating quantities of proved reserves, including many risk factors beyond our control. Reserve engineering is a subjective process of estimating subsurface accumulations of oil and natural gas that cannot be measured in an exact manner. As a result, estimates of proved reserves may vary depending upon the engineer estimating the reserves. Further, our actual realized price for our oil and natural gas is not likely to equal the pricing parameters used to calculate our proved reserves. As such, the oil and natural gas quantities and the value of those commodities ultimately recovered from our properties will vary from reserve estimates.

Additional discussion of our proved reserves is set forth under Notes to Consolidated Financial Statements—Supplemental Oil and Gas Information (Unaudited).

Critical Accounting Policies and Estimates

We prepare our financial statements and the accompanying notes in conformity with accounting principles generally accepted in the United States, which require management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes. We identify certain accounting policies and estimates as critical based on, among other things, their impact on our financial condition, results of operations, and the degree of difficulty, subjectivity and complexity in their application. Critical accounting policies and estimates cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management routinely discusses the development, selection and disclosure of each of the critical accounting policies and estimates. The following is a discussion of our most critical accounting policies and estimates.

Proved Oil and Natural Gas Reserves

The determination of depreciation, depletion and amortization expense as well as impairments that may be recognized on our oil and natural gas properties are highly dependent on the estimates of the proved oil and natural gas reserves attributable to our properties. Our estimate of proved reserves is based on the quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in the future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, we must estimate the amount and timing of future operating costs, production taxes and development costs, all of which may in fact vary considerably from actual results. In addition, as the prices of oil and natural gas and cost levels change from year to year, the economics of producing our

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reserves may change and therefore the estimate of proved reserves may also change. Approximately 29% of our proved oil and gas reserve volumes are categorized as proved undeveloped reserves. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves, future cash flows from our reserves, and future development of our proved undeveloped reserves. Our proved oil and gas reserve information was computed by applying the average first-day-of-the- month oil and gas price during the 12-month period ended on the balance sheet date.

External petroleum engineers independently estimated all of the proved reserve quantities included in our financial statements for the year ended December 31, 2025, which were prepared in accordance with the rules promulgated by the SEC. In connection with our external petroleum engineers performing their independent reserve estimations, we furnish them with the following information: (1) technical support data, (2) technical analysis of geologic and engineering support information, (3) economic and production data and (4) our well ownership interests.

Oil and Natural Gas Properties

We follow the successful efforts method of accounting for oil and gas activities. Under this method of accounting, costs associated with the acquisition, drilling, and equipping of successful exploratory wells and costs of successful and unsuccessful development wells are capitalized and depleted, net of estimated salvage values, using the units-of-production method on the basis of a reasonable aggregation of properties within a common geological structural feature or stratigraphic condition, such as a reservoir or field.

We review our oil and natural gas properties for impairment whenever events and circumstances indicate a decline in the recoverability of their carrying value. If we determined an evaluation for impairment is required, we estimate the expected future cash flows of our oil and natural gas properties and compare such cash flows to the carrying amount of the proved oil and natural gas properties to determine if the amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying value of proved oil and natural gas properties to estimated fair value. The factors used to estimate fair value include estimates of reserves, future commodity prices adjusted for basis differentials, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the projected cash flows. The discount rate is a rate that management believes is representative of current market conditions and includes estimates for a risk premium and other operational risks.

For the years ended December 31, 2025 and 2024 we did not record any impairment expense.

Business Combinations

We account for business combinations using the acquisition method of accounting. Under this method, we recognize the identifiable assets acquired and liabilities assumed at their estimated acquisition-date fair values. Transaction and integration costs related to business combinations are expensed as incurred.

In valuing the assets acquired and liabilities assumed, we make various assumptions to estimate fair values. Fair value is a market-based measurement that reflects the assumptions market participants would use in pricing an asset or liability. For the Lucero Acquisition, the most significant assumptions related to the estimated fair value of the proved oil and gas properties. The fair value of these properties was determined using the income approach, which is based on discounted future net cash flows derived from the properties' reserve reports. The valuation relied primarily on unobservable inputs, which are classified as Level 3 within the fair value hierarchy under ASC 820. Key inputs included estimates of future production volumes from the proved reserves, future commodity prices based on forward strip price curves (adjusted for basis differentials), estimates of lease operating, development and abandonment costs, and the application of a discount rate.

Any excess of the acquisition price over the estimated fair value of net assets acquired is recorded as goodwill and is subject to ongoing impairment evaluation as described. Any excess of the estimated fair value of net assets acquired over the acquisition price is recorded in current earnings as a gain on bargain purchase. Deferred taxes are recorded for any differences between the assigned values and the tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.

A description of our significant accounting policies and fair value measurements is included in Note 2 (“Significant Accounting Policies”) and Note 4 (“Fair Value Measurements”), respectively, to the Consolidated Financial Statements.

Recently Issued or Adopted Accounting Pronouncements

For discussion of recently issued or adopted accounting pronouncements, see Note 2 (“Significant Accounting Policies”) to the Consolidated Financial Statements.

Off Balance Sheet Arrangements

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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.