# PRIMEENERGY RESOURCES CORP (PNRG) Informational only - not investment advice. CIK: 0000056868 SIC: 1311 Crude Petroleum & Natural Gas SIC breadcrumb: [Mining](/division/B/) > [SIC Major Group 13](/major-group/13/) > [SIC 1311 Crude Petroleum & Natural Gas](/industry/1311/) Latest 10-K filed: 2026-04-16 SEC page: https://www.sec.gov/edgar/browse/?CIK=56868 Filing source: https://www.sec.gov/Archives/edgar/data/56868/000143774926012531/pnrg20251231_10k.htm ## At a glance FY2025 · period end 2025-12-31 · filed 2026-04-16 · accession 0001437749-26-012531 · source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000056868.json | Metric | Value | FY | Provenance | | --- | ---: | ---: | --- | | Revenue | 189,052,000 USD | 2025 | verified | | Net income | 26,312,000 USD | 2025 | verified | | Assets | 323,895,000 USD | 2025 | verified | | Free cash flow | 20,780,000 USD | 2025 | computed | | Net margin | 13.92% | 2025 | computed | | Revenue YoY | -20.50% | 2025 | computed | | ROE | 12.20% | 2025 | computed | Computed values are grepcent-computed from the verified facts above and may differ from ratios the company itself reports. Free cash flow = operating cash flow − capital expenditures. Net margin = net income ÷ revenue. Revenue YoY = FY2025 revenue ÷ FY2024 revenue − 1 (consecutive fiscal years only). ROE = net income ÷ period-end stockholders' equity. No market price, no rating, no forecast on this site. Not investment advice. ### Peer percentile fingerprint | Ratio | PNRG | Peer median | Percentile | N | | --- | ---: | ---: | ---: | ---: | | Net margin | 13.9% | 11.9% | 56 | 42 | | Revenue growth | -20.5% | 12.2% | 7 | 42 | | FCF margin | 11.0% | 15.0% | 41 | 18 | | ROE | 12.2% | 8.9% | 64 | 43 | | ROA | 8.1% | 4.9% | 81 | 44 | | Liabilities / equity | 0.50 | 0.90 | 7 | 43 | | Current ratio | 0.74 | 0.86 | 33 | 44 | Percentile = share of the N covered peers reporting that ratio whose value is lower (ties counted half); computed among grepcent-covered companies in SIC industry 1311 Crude Petroleum & Natural Gas, not the whole market. A higher percentile means a higher value of the ratio, not a better company. Ratios with fewer than 8 reporting peers are omitted. Latest reported values per company; fiscal periods may differ. Descriptive arithmetic - not a score, rating, or ranking. ## Selected Fundamentals | Metric | Value | Unit | FY | Filed | | --- | ---: | --- | ---: | --- | | Revenue | 189052000 | USD | 2025 | 2026-04-16 | | Net income | 26312000 | USD | 2025 | 2026-04-16 | | Assets | 323895000 | 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 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 | 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 | ## As-reported value updates 3 tracked differences above grepcent's stated thresholds were found between the earliest XBRL-filed value and the value currently on file for the same fiscal period. Ledger: /company/PNRG/revisions/ ## Quarterly Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-08-14. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000056868.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 | | --- | --- | ---: | ---: | ---: | --- | | 2022-Q3 | 2022-09-30 | | | 4.88 | reported discrete quarter | | 2023-Q1 | 2023-03-31 | | | 0.53 | reported discrete quarter | | 2023-Q2 | 2023-06-30 | | | 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 | 11,319,000 | 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 | 2025-06-30 | 41,983,000 | 3,228,000 | 1.33 | reported discrete quarter | | 2025-Q3 | 2025-09-30 | 45,970,000 | 10,563,000 | 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 | | 2026-Q2 | 2026-06-30 | 42,474,000 | 6,529,000 | 2.75 | reported discrete quarter | ## Filed narrative (10-K & 10-Q) ## Business Verbatim Item 1 Business section from PNRG's latest 10-K: [/company/PNRG/business/](/company/PNRG/business/). ## Risk Factors Verbatim Item 1A Risk Factors from PNRG's latest 10-K: [/company/PNRG/risk-factors/](/company/PNRG/risk-factors/). ## Latest quarter (10-Q) Latest 10-Q source: https://www.sec.gov/Archives/edgar/data/56868/000143774926027969/pnrg20260630_10q.htm Extracted structurally from real Item 2 body heading to real Item 3/4 boundary. Confidence: high Filing date: 2026-08-14 Report date: 2026-06-30 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. 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 may have 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 16,998 gross (9,567 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. 11 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:  [[GREPCENT_TABLE]] [["","","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"]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["(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."]] [[/GREPCENT_TABLE]] 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 in early 2025 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. 12 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 invested $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 during 2025. 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. During 2026, we participated with Validus Energy II in the drilling of one three-mile long horizontal well in Grady County, Oklahoma with 2.9% interest, investing roughly $351,000 through completion. This well was put on production during the first quarter of this year. Additional activity during 2026 in West Texas includes continued development in Martin and Upton County. Martin County development includes investing approximately $120,000 across 12 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 and production facility is $34.1 million. During the second quarter of this year, drilling activity [Excerpt truncated for page length; source filing is linked above.] ## Latest 10-K MD&A (excerpt) Latest 10-K Item 7 source: https://www.sec.gov/Archives/edgar/data/56868/000143774926012531/pnrg20251231_10k.htm Complete FY 2025 MD&A: /company/PNRG/mda/fy2025/ Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary. Confidence: high Filing date: 2026-04-16 Report date: 2025-12-31 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 forecas [Excerpt truncated for page length; the complete text is on the linked full-MD&A page.] Read the full FY 2025 MD&A: /company/PNRG/mda/fy2025/ All MD&A years: /company/PNRG/mda/ ## MD&A history Prior-year 10-K MD&A spans are extracted from SEC filings with the same bounded parser used for the latest filing. Each year's full verbatim text is on its own sub-page. - [FY 2024 MD&A](/company/PNRG/mda/fy2024/): filed 2025-04-15; accession 0001437749-25-012086 (https://www.sec.gov/Archives/edgar/data/56868/000143774925012086/pnrg20241231_10k.htm) - [FY 2023 MD&A](/company/PNRG/mda/fy2023/): filed 2024-04-15; accession 0001437749-24-011958 (https://www.sec.gov/Archives/edgar/data/56868/000143774924011958/pnrg20231231_10k.htm) - [FY 2022 MD&A](/company/PNRG/mda/fy2022/): filed 2023-04-17; accession 0001193125-23-103128 (https://www.sec.gov/Archives/edgar/data/56868/000119312523103128/d474265d10k.htm) - [FY 2021 MD&A](/company/PNRG/mda/fy2021/): filed 2022-04-21; accession 0001193125-22-113187 (https://www.sec.gov/Archives/edgar/data/56868/000119312522113187/d299823d10k.htm) ## Macro cross-references Indicators mapped to this company's SIC classification (industry 1311 Crude Petroleum & Natural Gas) by grepcent's deterministic macro-sector crosswalk. A navigational mapping, not a statistical or causal claim. - [INDPRO](/indicator/INDPRO/): Industrial Production: Total Index - [TCU](/indicator/TCU/): Capacity Utilization: Total Index - [PPIACO](/indicator/PPIACO/): Producer Price Index by Commodity: All Commodities - [DGS10](/indicator/DGS10/): Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity - [FEDFUNDS](/indicator/FEDFUNDS/): Federal Funds Effective Rate Macro-to-micro threads including this sector: [Inflation (CPI / PCE / PPI)](/thread/inflation-cpi-pce-ppi/). All macro indicators: /indicators/ ## For LLMs & downloads Markdown twin: /company/PNRG.md · JSON record: /company/PNRG.json · verified financials: /company/PNRG/financials.json / /company/PNRG/financials.csv · machine TOC for the whole site: /llms.txt