PRIMEENERGY RESOURCES CORP (PNRG)
SIC breadcrumb: Mining > SIC Major Group 13 > SIC 1311 Crude Petroleum & Natural Gas
SEC company page: https://www.sec.gov/edgar/browse/?CIK=56868. Latest filing source: 0001437749-26-012531.
Selected Fundamentals
| Metric | Value | Unit | FY | Filed |
|---|---|---|---|---|
| Revenue | 189,052,000 | USD | 2025 | 2026-04-16 |
| Net income | 26,312,000 | USD | 2025 | 2026-04-16 |
| Assets | 323,895,000 | USD | 2025 | 2026-04-16 |
Financials
Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-04-16. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000056868.json. Derived margins, ratios, and free cash flow are computed from the extracted annual SEC facts.
| Metric | 2013 | 2016 | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 |
|---|---|---|---|---|---|---|---|---|---|---|---|
| Revenue | 56,766,000 | 89,310,000 | 118,100,000 | 104,824,000 | 58,421,000 | 72,458,000 | 157,113,000 | 132,810,000 | 237,796,000 | 189,052,000 | |
| Net income | 5,422,000 | 47,434,000 | 14,665,000 | 3,659,000 | -2,363,000 | 2,126,000 | 48,664,000 | 28,103,000 | 55,404,000 | 26,312,000 | |
| Diluted EPS | 1.13 | 14.18 | 5.11 | 1.25 | -1.16 | 0.76 | 17.95 | 10.77 | 21.95 | 10.86 | |
| Operating cash flow | 35,700,000 | 40,107,000 | 39,066,000 | 27,211,000 | 16,379,000 | 28,617,000 | 33,127,000 | 109,015,000 | 115,909,000 | 96,734,000 | |
| Capital expenditures | 119,239,000 | 75,954,000 | |||||||||
| Share buybacks | 1,093,000 | 5,650,000 | 7,956,000 | 5,488,000 | 710,000 | 145,000 | 7,402,000 | 7,506,000 | 13,429,000 | 13,552,000 | |
| Assets | 214,654,000 | 246,765,000 | 255,052,000 | 229,365,000 | 200,484,000 | 210,914,000 | 247,137,000 | 288,568,000 | 324,622,000 | 323,895,000 | |
| Liabilities | 148,774,000 | 144,326,000 | 149,049,000 | 126,002,000 | 102,486,000 | 111,823,000 | 106,784,000 | 127,618,000 | 121,697,000 | 108,210,000 | |
| Stockholders' equity | 58,545,000 | 95,309,000 | 102,009,000 | 100,114,000 | 97,124,000 | 99,091,000 | 140,353,000 | 160,950,000 | 202,925,000 | 215,685,000 | |
| Cash and cash equivalents | 10,111,000 | 8,438,000 | 6,315,000 | 1,015,000 | 996,000 | 10,347,000 | 26,543,000 | 11,061,000 | 2,549,000 | 7,425,000 | |
| Free cash flow | -3,330,000 | 20,780,000 |
Ratios
| Metric | 2013 | 2016 | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 |
|---|---|---|---|---|---|---|---|---|---|---|---|
| Net margin | 9.55% | 53.11% | 12.42% | 3.49% | -4.04% | 2.93% | 30.97% | 21.16% | 23.30% | 13.92% | |
| Return on equity | 9.26% | 49.77% | 14.38% | 3.65% | -2.43% | 2.15% | 34.67% | 17.46% | 27.30% | 12.20% | |
| Return on assets | 2.53% | 19.22% | 5.75% | 1.60% | -1.18% | 1.01% | 19.69% | 9.74% | 17.07% | 8.12% | |
| Liabilities / equity | 2.54 | 1.51 | 1.46 | 1.26 | 1.06 | 1.13 | 0.76 | 0.79 | 0.60 | 0.50 | |
| Current ratio | 0.66 | 0.56 | 0.78 | 1.05 | 0.63 | 1.17 | 1.76 | 0.49 | 0.57 | 0.74 |
Financial Charts
Quarterly
Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-05-20. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000056868.json.
| Quarter | End Date | Revenue | Net Income | Diluted EPS | Method |
|---|---|---|---|---|---|
| 2022-Q2 | 2022-06-30 | 4.02 | reported discrete quarter | ||
| 2022-Q3 | 2022-09-30 | 4.88 | reported discrete quarter | ||
| 2023-Q1 | 2023-03-31 | 1,410,000 | 0.53 | reported discrete quarter | |
| 2023-Q2 | 2023-06-30 | 29,607,000 | 10,090,000 | 3.82 | reported discrete quarter |
| 2023-Q3 | 2023-09-30 | 35,360,000 | 10,720,000 | 4.13 | reported discrete quarter |
| 2023-Q4 | 2023-12-31 | 45,193,000 | 5,883,000 | derived Q4 = FY annual - nine-month YTD | |
| 2024-Q1 | 2024-03-31 | 42,990,000 | 4.41 | reported discrete quarter | |
| 2024-Q2 | 2024-06-30 | 64,825,000 | 19,732,000 | 7.77 | reported discrete quarter |
| 2024-Q3 | 2024-09-30 | 69,455,000 | 22,076,000 | 8.80 | reported discrete quarter |
| 2024-Q4 | 2024-12-31 | 60,526,000 | 2,277,000 | derived Q4 = FY annual - nine-month YTD | |
| 2025-Q1 | 2025-03-31 | 50,056,000 | 9,134,000 | 3.72 | reported discrete quarter |
| 2025-Q2 | 2025-03-31 | 9,134,000 | reported discrete quarter | ||
| 2025-Q2 | 2025-06-30 | 41,983,000 | 1.33 | reported discrete quarter | |
| 2025-Q3 | 2025-06-30 | 3,228,000 | reported discrete quarter | ||
| 2025-Q3 | 2025-09-30 | 45,970,000 | 4.38 | reported discrete quarter | |
| 2025-Q4 | 2025-12-31 | 51,042,000 | 3,387,000 | derived Q4 = FY annual - nine-month YTD | |
| 2026-Q1 | 2026-03-31 | 39,404,000 | 4,339,000 | 1.82 | 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: 0001437749-26-017864.
Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion is intended to assist you in understanding our results of operations and our present financial condition. Our Condensed Consolidated Financial Statements and the accompanying Notes to the Condensed Consolidated Financial Statements included elsewhere in this Report contain additional information that should be referred to when reviewing this material. Our subsidiaries are listed in Note 1 to the Consolidated Financial Statements. OVERVIEW We are an independent oil and natural gas company engaged in acquiring, developing, and producing oil and natural gas. We presently own producing and non-producing properties located primarily in Texas, and Oklahoma. All of our oil and gas properties and interests are located in the United States. Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential. We also own a 12.5% overriding royalty interest in over 30,000 acres in the state of West Virginia, although we are currently not receiving revenue from this asset as development has not begun. In Texas, we own well-servicing equipment that is used to service our operated properties as well as to provide oil field services to third-party operators. In addition, we own a 60-mile-long pipeline offshore on the shallow shelf of Texas that is currently idle but that we believe has future value for producers in the area. We believe our balanced portfolio of assets positions us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities. Our primary sources of liquidity are cash generated from operations, our credit facility, and existing cash on our balance sheet. In addition to developing our oil and natural gas reserves, we continue to actively pursue the acquisition of producing properties. We attempt to assume the position of operator in all acquisitions of producing properties and will continue to evaluate properties for leasehold acquisition and for exploration and development in areas in which we operate. To diversify and broaden our asset base, we will consider acquiring the assets or stock in other entities in the oil and gas business. Our main objective in making any such acquisitions will be to acquire income-producing assets or developable leasehold acreage to build stockholder value. We derive our revenue and cash flow principally from the sale of oil, natural gas, and NGLs. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil, natural gas, and NGLs. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. Because some of our operations are located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI, or other major market pricing. The market price for oil, natural gas, and NGLs is dictated by supply and demand; consequently, we cannot accurately predict or control the price we may receive for our oil, natural gas, and NGLs. Index prices for oil, natural gas, and NGLs may be volatile and, consequently, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital program, production volumes or revenue. On occasion, we will use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of increases in oil and gas prices above the maximum fixed amount specified in the derivative agreements and subjects us to the credit risk of the counterparties to such agreements. When used our derivative contracts are accounted for under mark-to-market accounting and we can expect volatility in gains and losses on contracts in our consolidated statement of operations as changes occur in the NYMEX price indices. The Company is actively developing additional reserves of its leasehold acreage positions in Texas and Oklahoma. In the Permian Basin of West Texas, the Company maintains an acreage position of approximately 16,838 gross (9,420 net) acres, 97.6% of which is located in Reagan, Upton, Martin, and Midland counties of Texas where our current horizontal drilling activity is focused. In addition to the wells currently being drilled or completed, we believe this acreage has the resource potential to support the drilling of as many as 100 future horizontal wells. In Oklahoma, we are focused on the development of our reserves in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 4,015 net leasehold acres in the Scoop/Stack Play. 10 Future development plans are established based on various factors, including the expectation of available cash flows from operations and the availability of funds under our revolving credit facility. Reserves: All of our interests in proved developed and undeveloped oil and gas properties have been evaluated by Ryder Scott Company, L.P. for each of the three years ended December 31, 2025. The professional qualifications of the technical persons primarily responsible for overseeing the preparation of the reserve estimates can be found in Exhibit 99.1, the Ryder Scott Company, L.P. Report on Registrant’s Reserves Estimates. In matters related to the preparation of our reserve estimates, our district managers report to the Engineering Data manager, who maintains oversight and compliance responsibility for the internal reserve estimate process and provides oversight for the annual preparation of reserve estimates of 100% of our year-end reserves by our independent third-party engineers, Ryder Scott Company, L.P. The members of our districts consist of degreed engineers with over twenty-five years of industry experience and between ten and twenty-five years of experience managing our reserves. Our Engineering manager, the technical person primarily responsible for overseeing the preparation of reserves estimates, holds a Bachelor degree in Petroleum Engineering and has over thirty years of experience in the oil and gas industry. See Part II, Item 8 “Financial Statements and Supplementary Data”, for additional discussions regarding proved reserves and their related cash flows. All of our reserves are located within the continental United States. The following table summarizes our oil and gas reserves at each of the respective dates: Reserve Category Proved Developed Proved Undeveloped Total As of December 31, Oil (MBbls) NGLs (MBbls) Gas (MMcf) Total (MBoe) Oil (MBbls) NGLs (MBbls) Gas (MMcf) Total (MBoe) Oil (MBbls) NGLs (MBbls) Gas (MMcf) Total (MBoe) 2023 5,757 3,676 24,749 13,558 6,254 5,156 24,470 15,488 12,011 8,832 49,219 29,046 2024 7,444 6,597 37,489 20,288 3,166 1,670 8,326 6,224 10,610 8,267 45,815 26,512 2025 7,432 6,981 53,786 23,377 2,822 1,063 6,756 5,011 10,254 8,044 60,542 28,388 (a) In computing total reserves on a barrels of oil equivalent (Boe) basis, gas is converted to oil based on its relative energy content at the rate of six Mcf of gas to one barrel of oil and NGLs are converted based upon volume; one barrel of natural gas liquids equals one barrel of oil. In 2024, the Company invested $113 million in drilling and completion of 48 new horizontals in West Texas: 47 of these are located in Reagan County, and one is located in Upton County. In Reagan County, the Company joined Double Eagle in 33 new horizontals with an average 28.2% interest and invested approximately $66 million. Also in Reagan County, we participated with Civitas in 14 horizontals on the “Christi” tract, carrying an average of 39% interest and investing roughly $46.7 million. Also in 2024, in Upton County, we participated with Pioneer Natural Resources in one 2-mile-long horizontal with 3.94% interest, investing approximately $425,700. At year-end 2024, the Company participated in 21 horizontals in West Texas. Of these 21 wells, six are located in Upton County, operated by Apache Corporation; three of the six were completed by year-end and three were completed after the first of the year and all were brought online in May, 2025. The remaining 15 of the 21 wells, located on our “OG” tracts and operated by Double Eagle, were on production by September 2025. At year-end 2024, the Company had 6,224 MBOE of proved undeveloped reserves attributable to 33 undeveloped wells. 11 In early March 2025, Ovintiv Mid-Continent spud two “Jennifer 1407” wells in Canadian County, Oklahoma; we participated for approximately 3.14% interest and invested $405,000, these wells were completed in May 2025. In the second and third quarters of 2025, we participated in fifteen new horizontals in the Midland Basin of West Texas: these 15 wells are operated by Double Eagle on our “Full House” tract in Reagan County in which the Company participated with approximately 27% interest and invested approximately $30.1 million. In addition to the Reagan County activity, the company participated in eight “Horseshoe” wells in Midland County with Vital Energy. Drilling activity with these wells began in the second quarter and the wells were put on production during the fourth quarter of 2025. The company has an average of 8.2% interest in these eight wells and invested approximately $5.4 million. We also participated with Devon Energy Production on two "Evelyn" wells in Kingfisher County, Oklahoma; we participated with approximately 9.95% interest and $1.4 million. These wells were drilled in July 2025 and completed November 2025. In total in these 27 wells, we invested approximately $37.3 million. At year-end 2025, the Company participated in 27 horizontals in West Texas and Oklahoma. Of these 27 wells, twenty three of the wells are located in West Texas and the remaining four in Oklahoma. The West Texas wells consisted of eight wells located in Midland County and 15 wells located in Reagan County. The four wells in Oklahoma were located in Canadian and Kingfisher Counties with each county having two wells. At year-end 2025, the Company had 5,011 MBOE of proved undeveloped reserves attributable to 37 undeveloped wells. In 2026, we have plans to participate with Validus Energy II in the drilling of one 3-mile long horizontal well in Grady County, Oklahoma with 3.47% interest, investing roughly $351,000 through completion, one well with Ovintiv Mid-Continent in the drilling of one 2.5-mile long horizontal in Garvin County, Oklahoma with 3.36% interest, investing roughly $291,000 through completion, and one 3-mile long horizontal in Garvin County, Oklahoma with a 2.27% interest, investing roughly $194,000 through completion. Additional activity during 2026 in West Texas includes continued development in Martin and Upton County. Martin County development includes investing approximately $140,000 across 13 wells to be drilled by Oxyrock in Jo Mill and Middle Spraberry formations as well as the Barnett formation. Development in Upton County will be with Apache at an average of 41.8% ownership across 12 wells in Jo Mill, Lower Spraberry and Wolfcamp A formations. The estimated company investment for these wells is $50.6 million. The estimated future net revenue (using current prices and costs as of those dates) and the present value of future net revenue (at a 10% discount for estimated timing of cash flow) for our proved developed and proved undeveloped oil and gas reserves at the end of each of the three years ended December 31, 2025 [Excerpt truncated for page length; source filing is linked above.]
Latest 10-K MD&A
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion is intended to assist you in understanding our results of operations and our present financial condition. Our Consolidated Financial Statements and the accompanying Notes to the Consolidated Financial Statements included elsewhere in this Report contains additional information that should be referred to when reviewing this material. Our subsidiaries are listed in Note 1 to the Consolidated Financial Statements. Overview: We are an independent oil and natural gas company engaged in acquiring, developing, and producing oil and natural gas. We presently own producing and non-producing properties located primarily in Texas, and Oklahoma. In addition, we own a substantial amount of well servicing equipment. All of our oil and gas properties and interests are located in the United States. Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential. We believe our balanced portfolio of assets and our ongoing hedging program position us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities. Our primary sources of liquidity are cash generated from our operations and our credit facility. We attempt to assume the position of operator in all acquisitions of producing properties and will continue to evaluate prospects for leasehold acquisitions and for exploration and development operations in areas in which we own interests. We continue to actively pursue the acquisition of producing properties. To diversify and broaden our asset base, we will consider acquiring the assets or stock in other entities and companies in the oil and gas business. Our main objective in making any such acquisitions will be to acquire income producing assets to build stockholder value through consistent growth in our oil and gas reserve base on a cost-efficient basis. Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisition and drilling activities and the operational performance of our producing properties. We use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of any increases in oil and gas prices above the maximum fixed amount specified in the derivative agreements and subjects us to the credit risk of the counterparties to such agreements. Since all our derivative contracts are accounted for under mark-to-market accounting, we expect continued volatility in gains and losses on mark-to-market derivative contracts in our consolidated statement of operations as changes occur in the NYMEX price indices. Market Conditions and Commodity Prices: Our financial results depend on many factors, particularly the price of natural gas and crude oil and our ability to market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. In addition, our realized prices are further impacted by our derivative and hedging activities. We derive our revenue and cash flow principally from the sale of oil, natural gas and NGLs. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil, natural gas and NGLs. We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. Because some of our operations are located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing. The market price for oil, natural gas and NGLs is dictated by supply and demand; consequently, we cannot accurately predict or control the price we may receive for our oil, natural gas and NGLs. Index prices for oil, natural gas, and NGLs have been volatile in recent years and consequently cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital program, production volumes or revenues. 37 Critical Accounting Estimates: Proved Oil and Gas Reserves Proved oil and gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization. Proved reserves represent estimated quantities of natural gas, crude oil, condensate, and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. The process of estimating quantities of proved oil and gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. Depreciation, Depletion and Amortization for Oil and Gas Properties The quantities of estimated proved oil and gas reserves are a significant component of our calculation of depletion expense and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserves were revised upward or downward, earnings would increase or decrease respectively. Depreciation, depletion and amortization of the cost of proved oil and gas properties are calculated using the unit-of-production method. The reserve base used to calculate depletion, depreciation or amortization is the sum of proved developed reserves and proved undeveloped reserves for leasehold acquisition costs and the cost to acquire proved properties. The reserve base includes only proved developed reserves for lease and well equipment costs, which include development costs and successful exploration drilling costs. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account. Asset Retirement Obligation (ARO): The Company has significant obligations to remove tangible equipment and restore land at the end of oil and gas production operations. The Company’s removal and restoration obligations are primarily associated with plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations. ARO associated with retiring tangible long-lived assets is recognized as a liability in the period in which the legal obligation is incurred and becomes determinable. The liability is offset by a corresponding increase in the underlying asset. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company’s oil and gas properties. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value Liquidity and Capital Resources: Our primary sources of liquidity are cash generated from our operations, through our producing oil and gas properties, field services business and sales of acreage, and available capacity under our revolving credit facility. Net cash provided by operating activities for the year ended December 31, 2025, was $96.7 million compared to $115.9 million in the prior year. Excluding the effects of significant unforeseen expenses or other income, our cash flow from operations fluctuates primarily because of variations in oil and gas production and prices or changes in working capital accounts. Our oil and gas production will vary based on actual well performance but may be curtailed due to factors beyond our control. Our realized oil and gas prices vary due to world political events, supply and demand of products, product storage levels, and weather patterns. We sell the majority of our production at spot market prices. Accordingly, product price volatility will affect our cash flow from operations. To mitigate price volatility, we sometimes lock in prices for some portion of our production through the use of derivatives. If our exploratory drilling results in significant new discoveries, we will have to expend additional capital to finance the completion, development, and potential additional opportunities generated by our success. We believe that, because of the additional reserves resulting from the successful wells and our record of reserve growth in recent years, we will be able to access sufficient additional capital through bank financing. 38 Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For 2026, we will continue our focus on preserving financial flexibility and liquidity as we manage the risks facing our industry. Our 2026 capital budget is reflective of commodity prices and has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility. As we have done historically to preserve or enhance liquidity, we may adjust our capital program throughout the year, divest assets, or enter into strategic joint ventures. The Company maintains a Credit Agreement with a maturity date of December 20, 2028, providing for a credit facility totaling $300 million, with a borrowing base of $115 million. As of April 15, 2026, the Company had no outstanding borrowings and $115 million in availability under this facility. The bank reviews the borrowing base semi-annually and, at its discretion, may decrease or propose an increase to the borrowing base relative to a re-determined estimate of proved oil and gas reserves. The next borrowing base review is scheduled for June 2026. Our oil and gas properties are pledged as collateral for the line of credit and we are subject to certain financial and operational covenants defined in the agreement. We are currently in compliance with these covenants and expect to be in compliance over the next twelve months. If we do not comply with these covenants on a continuing basis, the lenders have the right to refuse to advance additional funds under the facility and/or declare all principal and interest immediately due and payable. Our borrowing base may decrease as a result of lower natural gas or oil prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for other reasons set forth in our revolving credit agreement. In the event of a decrease in our borrowing base due to declines in commodity prices or otherwise, our ability to borrow under our revolving credit facility may be limited and we could be required to repay any indebtedness in excess of the re-determined borrowing base. Our credit agreement requires us to hedge a portion of our production as forecasted for the PDP reserves included in our borrowing base review engineering reports. The credit agreement requires that as of the last day of any fiscal quarter, if the borrowing base utilization percentage on such a date is less than 15%, then the borrower shall not be required to enter into any swap agreements. As of the quarter ended December 31, 2025, the Company had zero in outstanding borrowings and $115 million in availability. Accordingly, the Company had no swap agreements in place for oil and natural gas. Development and Other Activities The Company’s activities include development and exploratory drilling. Our strategy is to develop a balanced portfolio of drilling prospects that includes lower-risk wells with a high probability of success and higher-risk wells with greater economic potential. Horizontal development of our resource base provides superior returns relative to vertical development due to the ability of each horizontal wellbore to come in contact with a greater volume of reservoir rock across a greater distance, more efficiently draining the reserves with less infrastructure and thus at a lower cost per acre. In 2024, the Company invested $113 million in 48 horizontals in West Texas: 47 of these are located in Reagan County and one is located in Upton County. In Reagan County, the Company joined Double Eagle in drilling and completing 33 new horizontal wells: on the “Honey RF” tract we completed 12 horizontals each being two-mile-long laterals, and participated with 50% interest investing $37 million; on the “Prime West” tract we have 50% interest in six wells and invested $20.5 million; on both the “Kramer” and “O’Bannion” tracts we participated in six horizontals, each with an average 8.3% interest and we invested approximately $7.8 million; and on the “Pink Floyd” tract we have less than 1% interest in two wells in which we invested approximately $174,900; and on our “Studley AV” tract we participated with Double eagle in testing the Wolfcamp “D” interval; in this well we have about 6.3% interest and invested approximately $600,000. Also in Reagan County, we participated with Civitas in 14 horizontal wells on the “Christi” tract, carrying an average of 39% interest and investing roughly $46.7 million. Also in 2024, in Upton County, we participated with Pioneer Natural Resources in one 2-mile-long horizontal with 3.94% interest, investing approximately $425,800. Of these 48 wells, 32 are 2-mile-long laterals, 14 are 2.5-mile-long laterals, and two are 3-mile-long laterals. In addition to this activity, in June of 2024, we participated with Apache in the drilling of six additional 3-mile-long laterals in Upton County on our “Mt. Moran” tract. Three of these wells were completed in late December 2024 and three were completed in January of 2025. All six new “Mt. Moran” wells are producing as of April 1, 2025. In these six Mt. Moran wells, the Company has an average of 51.16% interest and in total invested approximately $36.3 million. In addition, in November of 2024, in Reagan County, we participated with Double Eagle in 15 “OG” horizontal wells: eight are 2.5-mile-long laterals, and seven are 2-mile-long laterals. In each of these 15 “OG” wells the Company has approximately 23% interest and in total invested roughly $23 million through completion of production facilities. These 15 horizontals were on production in May 2025. By the end of 2025, therefore, the Company has invested approximately $59.3 million in these additional 21 horizontal wells. 39 In early March 2025, Ovintiv Mid-Continent spud two “Jennifer 1407” wells in Canadian County, Oklahoma; in these, we participated with approximately 3.14% interest and invested $405,000, these wells were completed in May 2025. In the second and third quarters of 2025, we participated in fifteen new horizontals in the Midland Basin of West Texas: these 15 wells are on production as of September 2025 and are operated by Double Eagle on our “Full House” tract in Reagan County in which the Company participated with approximately 27% interest and invested approximately $30.1 million. In addition to the Reagan County activity, the company participated in eight “Horseshoe” wells in Midland County with Vital Energy. Drilling activity with these wells began in the second quarter and the well were put on production during the fourth quarter of 2025. The Company has an average of 8.2% interest in these eight wells and invested approximately $5.4 million. We also participated with Devon Energy Production on two "Evelyn" wells in Kingfisher County, Oklahoma; we participated with approximately 9.95% interest and $1.4 million. These wells were drilled in July 2025 and completed November 2025. In total in these 27 wells, we invested approximately $37.3 million. In 2026, we have plans to participate with Validus Energy II in the drilling of one 3-mile long horizontal well in Grady County, Oklahoma with 3.47% interest, investing roughly $351,000 through completion, one well with Ovintiv Mid-Continent in the drilling of one 2.5-mile long horizontal in Garvin County, Oklahoma with 3.36% interest, investing roughly $291,000 through completion, and one 3-mile long horizontal in Garvin County, Oklahoma with a 2.27% interest, investing roughly $194,000 through completion. During 2025, to supplement cash flow and finance our future drilling programs, the Company sold 76 net mineral acres in Glasscock County, Texas. For these mineral acres, we received $950,000 in gross proceeds. A limited partnership, in which the company has interest, sold a retail shopping center located in Prattville, Alabama, distributing $1.2 million to the Company from the proceeds of the sale. The majority of our capital spending is discretionary, and the ultimate level of expenditures will be dependent on our assessment of the oil and gas business environment, the number and quality of oil and gas prospects available, the market for oilfield services, and oil and gas business opportunities in general. The Company has a stock repurchase program in place, spending under this program in 2025 and 2024 was $13.6 million and $13.4 million, respectively. Since 1990, including pursuant to the stock repurchase program authorized by the Board of Directors in December 1993, the Company has repurchased 6,071,995 shares at an average price of $20.16 per share. The Company has also repurchased 769,500 options at an average price of $0.79 per option. Under the current stock repurchase program authorized by the Board of Directors in December 1993, 86,044 shares remain available for repurchase. Over time, these repurchases have meaningfully reduced the Company’s shares outstanding from approximately 7.6 million shares in 1987 to approximately 1.6 million shares currently. The Company believes that this sustained reduction in share count has contributed significantly to long-term per-share value creation for all shareholders. As a result of the reduction in shares outstanding over time, the ownership percentage of certain long-term stockholders, including the Chairman and Chief Executive Officer, Charles Drimal, has increased. Mr. Drimal has not materially increased his ownership through open market purchases; rather, his ownership percentage has increased primarily as a result of the decrease in the number of shares outstanding. As of December 31, 2025, Mr. Drimal beneficially owns, including the effect of stock options and voting arrangements, approximately 55.4% of the Company’s fully diluted shares. The Board of Directors regularly reviews and evaluates the Company’s capital allocation priorities. In doing so, the Board considers a variety of factors, including market conditions, the Company’s financial position, liquidity, and the impact of repurchases on the Company’s stockholder base. The Company expects continued spending under the stock repurchase program in 2026. Results of Operations 2025 and 2024 Compared We reported a net income of $26.3 million for 2025, or $15.85 per share, compared to $55.4 million for 2024, or $31.43 per share for 2024. Oil, NGL and gas sales decreased $45.5 million, or 20.4% to $177.5 million for the year ended December 31, 2025 from $223 million for the year ended December 31, 2024. Crude oil, NGL and natural gas sales vary due to changes in volumes of production sold and realized commodity prices. Our realized prices at the well head decreased an average of $12.48 per barrel, or 16.5% on crude oil, decreased an average of $4.93 per barrel, or 24.4% on NGL and increased $0.33 per Mcf, or 77.3% on natural gas during 2025 as compared to 2024. Our crude oil production decreased by 270,000 barrels, or 10.6% to 2,286,000 barrels for the year ended December 31, 2025 from 2,556,000 barrels for the year ended December 31, 2024. Our NGL production increased by 366,000 or 28.5% to 1,650,000 for the year ended December 31, 2025 from 1,284,000 barrels for the year ended December 31, 2024. Our natural gas production increased by 2,059 MMcf, or 26.5% to 9,825 MMcf for the year ended December 31, 2025 from 7,766 MMcf for the year ended December 31, 2024. The changes in crude oil, NGL and natural gas production volumes are a result of new wells placed in production offset by the natural decline of existing properties. 40 The following table summarizes the primary components of production volumes and average sales prices realized for the years ended December 31, 2025 and 2024 (excluding realized gains and losses from derivatives). Years ended December 31, Increase / Increase / 2025 2024 (Decrease) (Decrease) Barrels of Oil Produced 2,286,000 2,556,000 (270,000 ) (10.6 )% Average Price Received $ 63.32 $ 75.80 $ (12.48 ) (16.5 )% Oil Revenue (In 000’s) $ 144,749 $ 193,737 $ (48,988 ) (25.3 )% Mcf of Gas Sold 9,825,000 7,766,000 2,059,000 26.5 % Average Price Received $ 0.76 $ 0.43 $ 0.33 77.3 % Gas Revenue (In 000’s) $ 7,490 $ 3,309 $ 4,181 126.4 % Barrels of Natural Gas Liquids Sold 1,650,000 1,284,000 366,000 28.5 % Average Price Received $ 15.32 $ 20.25 $ (4.93 ) (24.4 )% Natural Gas Liquids Revenue (In 000’s) $ 25,274 $ 25,996 $ (722 ) (2.8 )% Total Oil & Gas Revenue (In 000’s) $ 177,513 $ 223,042 $ (45,529 ) (20.4 )% Oil and gas production expense decreased $2.7 million, or 5.7% to $45.0 million for the year ended December 31, 2025 from $47.7 million for the year ended December 31, 2024. These changes reflect fewer workover related costs in 2025 offset by increases in service rates related to recurring lease operating expenses. Production and ad valorem taxes decreased $2.1 million, or 17.7% to $10.0 million for the year ended December 31, 2025 from $12.1 million for the year ended December 31, 2024. This decrease reflect the lower oil and natural gas liquid revenues partially offset by higher gas revenues during the year. Field service income decreased $2.5 million or 25.3% to $8.4 million for the year ended December 31, 2025 from $10.9 million for the year ended December 31, 2024. Workover rig services, hot oil treatments, water hauling and salt water disposal represent the bulk of our field service operations. These changes reflect decreases in equipment utilization related to the sale of Eastern Oil Well Service Company, effective August 31, 2024. Field service expense decreased $2.9 million, or 32.0% to $6.2 million for the year ended December 31, 2025 from $9.1 million for the year ended December 31, 2024. Field service expenses primarily consist of wages and vehicle operating expenses. These changes reflect decreases in equipment utilization related to the sale of Eastern Oil Well Service Company, effective August 31, 2024. Depreciation, depletion, and amortization decreased $0.8 million, or 1.0% to $75.7 million for the year ended December 31, 2025 from $76.5 million for the year ended December 31, 2024. General and administrative expense decreased $0.5 million, or 2.7% to $18.4 million for the year ended December 31, 2025 from $18.9 million for the year ended December 31, 2024. This decrease is primarily related lower to employee compensation, benefits and other corporate costs. Interest and other income of $1.54 million for the ended December 31, 2025 includes distributions from Alabama Shopping Center Associates limited partnership, generated by the partnership's sale of the Prattville, Alabama center. Interest expense increased $0.7 million, or 44.3% to $2.2 million for the year ended December 31, 2025 from $1.5 million for the year ended December 31, 2024. This increase reflects the higher interest and fee rates combined with borrowings throughout the twelve months of 2025 under our revolving credit agreement. Tax expense of $4.2 million and $15.8 million were recorded for the years ended December 31, 2025 and 2024, respectively. The change in our income tax provision was primarily due to the decrease in pre-tax income for the year ended December 31, 2025.