PNRG 10-K & 10-Q changes, risk factors and insider trading

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and oil. Lower commodity prices may reduce the amount of natural gas and oil that we can produce economically. Natural gas prices, based on the twelve-month average of the first of the month Henry Hub index price, were $3.39 per MMBTU in 2025 as compared to $2.13 per MMBTU in 2024 as compared to $2.637 per MMBTU in 2023,2024, and have averaged $3.89$3.64 per MMBTU for the first threefour months of 2025.2026. Oil prices, based on West Texas Intermediate (WTI) Light Sweet Crude first-of-the-month prices, averaged $65.34 per barrel in 2025 as compared to $75.48 per barrel in 2024 as compared to $78.22 per barrel in 2023,2024, and in the first three months of 2025,2026, the first-of-the-month price has averaged $69.67$65.72 per barrel.

Our information technology systems may be vulnerable to security breaches, including those involving cyberattacks using viruses, worms or other destructive software, process breakdowns, phishing or other malicious activities, or any combination of the foregoing. Such breaches could result in unauthorized access to information, including customer, employee, or other confidential data. We do not carry insurance against these risks, although we do invest in security technology, perform penetration tests, and design our business processes to attempt to mitigate the risk of such breaches. However, there can be no assurance that security breaches will not occur. Moreover, cyber and other security threats are constantly evolving, thereby making it more difficult to successfully defend against them or to implement adequate preventative measures. The development and maintenance of these measures requiresrequire continuous monitoring as technologies change and security measures evolve. We have experienced, and expect to continue to experience, cyber threats and incidents, none of which has been material to us to date. However, a successful breach or attack could have a material negative impact on our operations or business reputation and subject us to consequences such as litigation and direct costs associated with incident response.

The CFTC has promulgated regulations to implement statutory requirements for swap transactions. These regulations are intended to implement a regulated market in which most swaps are executed on registered exchanges or swap execution facilities and cleared through central counterparties. While we believe that our use of swap transactions exemptexempts us from certain regulatory requirements, the changes to the swap market due to increased regulation could significantly increase the cost of entering into new swaps or maintaining existing swaps, materially alter the terms of new or existing swap transactions and/or reduce the availability of new or existing swaps. If we reduce our use of swaps as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, (i) establish construction and operating permit reviews for GHG emissions from certain large stationary sources, (ii) require the monitoring and annual reporting of GHG emissions from certain petroleum and gas system sources in the United States, (iii) implement CAA emission standards directing the reduction of methane from certain new, modified, or reconstructed facilities in the oil and gas sector, and (iv) together with the DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States. For example, in December 2023, the EPA finalized NSPS Subpart OOOOb, which seeks to reduce methane and volatile organic compound emissions from the oil and natural gas source category and NSPS Subpart OOOOc, which create, for the first-time, emission guidelines for existing oil and natural gas sources that would be included in individual states’ implementation plans. These standards expand upon previously issued NSPS Subparts OOOO and OOOOa published by the EPA in 2012 and 2016, respectively. Additionally, various states, groups of states, and other countries have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, there is a non-binding agreement, the United Nations sponsored “Paris Agreement,” for nations to limit their GHG emissions through individually-determined reduction goals every five years after 2020. In January 2025, Presidentthe TrumpU.S. signed an executive order to withdrawinitiated the Unitedprocess Statesof withdrawing from the Paris Agreement.Agreement in January 2025 and completed its withdrawal in January 2026, after previously reentering it in February 2021. While the current U.S. administration may diverge from the prior administration’s positions and could withdraw from or otherwise roll back existing GHG emissions regulations, it is not possible at this time to predict exactly which and to what extent such regulations will be modified, and how any such actions may impact our business. Further, such actions could prompt more activity from state and local legislative bodies and administrative agencies to pass stricter GHG emissions laws, regulations, and other binding commitments.

The IRAIRS includes a 1% tax on publicly traded corporations on the fair market value of stock repurchased during any taxable year. Such tax applies to the extent such buybacks exceed $1 million during such year, which buyback value may be offset by other stock issuances.

Net cash provided by operating activities for the year ended December 31, 2024, was $115.9 million compared to $109.0 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.

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 8,15, 2025,2026, the Company had $17.5 million inno outstanding borrowings and $97.5$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 2025.2026. 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, 2024,2025, the Company had $4 millionzero in outstanding borrowings and $111$115 million in availability. Accordingly, the Company had no swap agreements in place for oil and natural gas.

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 $425,700.$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 began participationparticipated 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 will in total investinvested approximately $40.5$36.3 million. In addition, in November of 2024, in Reagan County, we began participatingparticipated 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 will investinvested roughly $29$23 million through completion of production facilities. These 15 horizontals are expected to bewere on production in mid to late AprilMay 2025. By the end of the second quarter of 2025, therefore, the Company will havehas invested approximately $70$59.3 million in these additional 21 horizontal wells.

In early March 2025, Ovintiv Mid-Continent spud two “Jennifer 1407” wells in Canadian County, Oklahoma; in these, we willparticipated participate forwith approximately 3.125%3.14% interest and investinvested $408,000.$405,000, these wells were completed in May 2025. In the second and third quarters of 2025, we areparticipated anticipatingin the start of twentyfifteen 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 will participateparticipated with approximately 31%27% interest and investinvested $48.4approximately million,$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 fivethe well were put on production during the fourth quarter of 2025. The Company has an average of 8.2% interest in these eight wells operatedand byinvested ConocoPhillipsapproximately $5.4 million. We also participated with Devon Energy Production on ourtwo “Schenecker”"Evelyn" tractwells in Martin,Kingfisher CountyCounty, in whichOklahoma; we planparticipated towith participateapproximately for 20.83%9.95% interest and invest $11.3$1.4 million. These wells were drilled in July 2025 and completed November 2025. In total in these 2227 wells, we will investinvested approximately $60$37.3 million.

The Company has a stock repurchase program in place, spending under this program in 20242025 and 20232024 was $13.4$13.6 million and $7.5$13.4 million, respectively. The Company expects continued spending under the stock repurchase program in 2025.

Oil, NGL and gas sales increaseddecreased $115$45.5 million, or 107.01%20.4% to $223.1$177.5 million for the year ended December 31, 20242025 from $107.7$223 million for the year ended December 31, 2023.2024. 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 $1.04$12.48 per barrel, or 1.35%16.5% on crude oil, increaseddecreased an average of $0.61$4.93 per barrel, or 3.11%24.4% on NGL and decreasedincreased $1.49$0.33 per Mcf, or 77.6%77.3% on natural gas during 20242025 as compared to 2023.2024.

Our crude oil production increaseddecreased by 1,412,000270,000 barrels, or 123.43%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, 20242024. Our NGL production increased by 366,000 or 28.5% to 1,650,000 for the year ended December 31, 2025 from 1,144,0001,284,000 barrels for the year ended December 31, 2023.2024. Our NGLnatural gas production increased by 678,0002,059 MMcf, or 111.88%26.5% to 1,284,0009,825 MMcf for the year ended December 31, 20242025 from 606,000 barrels for the year ended December 31, 2023. Our natural gas production increased by 3,639 MMcf, or 88.18% 7,766 MMcf for the year ended December 31, 2024 from 4,127 MMcf for the year ended December 31, 2023.2024. 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.

FieldOil serviceand gas production expense decreased $2.6$2.7 million, or 22.4%5.7% to $9.1$45.0 million for the year ended December 31, 20242025 from $11.7$47.7 million for the year ended December 31, 2023. Field service expenses primarily consist of wages and vehicle operating expenses.2024. These changes reflect decreasesfewer workover related costs in equipment2025 utilizationoffset by increases in service rates related to therecurring salelease ofoperating Eastern Oil Well Service Company, effective August 31, 2024.expenses.

Depreciation,Field depletion,service andexpense amortizationdecreased increased $45.5$2.9 million, or 147.0%32.0% to $76.5$6.2 million for the year ended December 31, 20242025 from $31.0$9.1 million for the year ended December 31, 2023.2024. Field service expenses primarily consist of wages and vehicle operating expenses. These increaseschanges reflect thedecreases expensein equipment utilization related to the newsale wellsof placedEastern onOil productionWell duringService theCompany, twelveeffective months ended DecemberAugust 31, 2024.

TaxDepreciation, expense of $15.8 milliondepletion, and $6.1amortization decreased $0.8 million, or 1.0% to $75.7 million were recorded for the yearsyear ended December 31, 20242025 andfrom 2023,$76.5 respectively. The change in our income tax provision was primarily due to the increase in pre-tax incomemillion for the year ended December 31, 2024.

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.

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 hasmay 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.

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 afterin theearly first of the year2025 and all were brought online in May,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.

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.million during 2025.

InDuring 2026, we have plans to participateparticipated with Validus Energy II in the drilling of one 3-milethree-mile long horizontal well in Grady County, Oklahoma with 3.47%2.9% interest, investing roughly $351,000 through completion,completion. oneThis well withwas Ovintivput Mid-Continenton inproduction during the drillingfirst quarter of onethis 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.year. Additional activity during 2026 in West Texas includes continued development in Martin and Upton County. Martin County development includes investing approximately $140,000$120,000 across 1312 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 $50.6$34.1 million. During the second quarter of this year, drilling activity started with each of the developments in Martin and Upton County. First production for all 24 wells is estimated in the fourth quarter of this year.

While it may be reasonably anticipated that the prices received forfrom the sale of our production may be higher or lower than the prices used in this evaluation, as described above, and the operating costs relating to such production may also increase or decrease from existing levels, such possible changes in prices and costs were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation for the SEC case. Actual volumes produced, prices received and costs incurred may vary significantly from the SEC case.

Our production and development activities in the Gulf Coast region are concentrated in southeast and east Texas. This region is managed from our office in Houston, Texas. Principal producing intervals are in the Wilcox, Hackberry, and Yegua formations at depths ranging from 6,000 to 12,000 feet. We had 96 producing wells (19 net) in the Gulf Coast region as of MarchJune 31,30, 2026, of which, 26 wells are operated by us. Average net daily production in our Gulf Coast Region at year-end 2025 was 161Boe. At December 31, 2025, we had 429 MBoe of proved reserves in the Gulf Coast region, which represented 1,51%1.51% of our total proved reserves. We maintain an acreage position of over 7,003 gross (4,532 net) acres in this region, primarily in Colorado, Newton, and Polk counties.

TheIn February of 2026 the Gulf Coast region hasperformed plansa tosuccessful recompleterecompletion twoon producing wells: Sarah F.the Wing #80 and the Sarah F. Wing #85 wellswell in the Segno field of Polk County, Texas, at an expense of approximately $300,000$167,000, inadding total.roughly The45 Wing #16 was recompletedBOEPD to the WilcoxCompany’s Aproduction. We have plans to recomplete the Wing #85 well in 2025the Segno field of Polk County, Texas, at an approximate expense of $500,000.approximately Gas lift valves have been installed with testing currently under way.$150,000. Other than thesethe recompletions,previously mentioned recompletion, we currently have no operated wells in the process of being drilled, no waterfloods in the process of being installed and no other related activities of material importance.

Our Mid-Continent activities are concentrated in central Oklahoma. This region is managed from our office in Oklahoma City, Oklahoma. As of MarchJune 31,30, 2026, we had 677 producing wells (125 net) in the Mid-Continent area, of which 117 wells are operated by us. Principal producing intervals are in the Robberson, Avant, Skinner, Sycamore, Bromide, McLish, Hunton, Mississippian, Oswego, Red Fork, and Chester formations at depths ranging from 1,100 to 10,500 feet. The average net daily production in our Mid-Continent Region in 2025 was 962 Boe. On December 31, 2025, we had 1,401 MBoe of proved reserves in the Mid-Continent area, representing 4.94% of our total proved reserves. We maintain an acreage position of approximately 43,837 gross (10,062 net) acres in this region, primarily in Canadian, Kingfisher, Grant, Major, and Garvin counties.

Our Mid-Continent region is actively participating with third-party operators in the horizontal development of lands that include Company owned interest in several counties in the Scoop and Stack plays of Oklahoma where drilling is primarily targeting reservoirs of the Mississippian, and Woodford formations. In Canadian County, Oklahoma, we have participated with Ovintiv Mid-Continent in the drilling of two 2-mile-long horizontal wells that were spud in early March 2025 and completed in May 2025. Our share of these wells is approximately 3.14% and the total investment was approximately $405,000. We also participated with Devon in Kingfisher County, Oklahoma to drill two 2-mile-long horizontal wells that were spud July 2025 and completed in November 2025. Our share of these wells is approximately 9.95% and total investment of approximately $1,439,000. InDuring 2026, we have plans to participateparticipated with Validus Energy II in the drilling of one 3-mile long horizontal well in Grady County, Oklahoma with 3.47%2.9% 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$295,000 through completion. This well was put on production during the first quarter of this year.

Our West Texas activities are concentrated in the Permian Basin in Texas. The oil and gas in this basin are produced primarily from five intervals; the Upper and Lower Spraberry, the Wolfcamp, the Strawn, and the Atoka, at depths ranging from 6,700 feet to 11,300 feet. This region is managed from our office in Midland, Texas. As of MarchJune 31,30, 2026, we had 791wells (281 net) in the West Texas area, of which 317 wells are operated by us. Principal producing intervals are in the Spraberry, Wolfcamp, and San Andres formations at depths ranging from 4,200 to 12,500 feet. The average net daily production in our West Texas Region at year-end 2025 was 14,152 Boe. On December 31, 2025, we had 21,544 MBoe of proved reserves in the West Texas area, or 93.54% of our total proved reserves. We maintain an acreage position of approximately 16,83816,998 gross (9,4209,567 net)A acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin, and Midland counties and believe this acreage has significant resource potential for horizontal drilling in the Spraberry, Jo Mill, and Wolfcamp intervals. We operate a field service group in this region utilizing nine workover rigs, three hot oiler trucks, and one kill truck. Oil field support is provided for drilling and workover operations both to third-party operators as well as for our own operated wells and locations.

Activity during 2025 included participating 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 Anticipated activityActivity for 2026 includes continued development in Martin and Upton County. Martin County development includes investing approximately $140,000$120,000 across 1312 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 $50.6$34.1 million. During the second quarter of this year, drilling activity started with each of the developments in Martin and Upton County. First production for all 24 wells is estimated in the fourth quarter of this year.

Future drilling activity on our leasehold acreage in West Texas is expected in the next few years as well. In particular, based on activity west of our acreage in Reagan County, and a recent deep test by Double Eagle on our joint leasehold, we anticipate that proposalproposals could soon be put forward within the next two years for the drilling of between 36 and 45 new horizontals that will target the Wolfcamp “D” pay zone in Reagan CountyCounty, andif perhapsthe current drilling of offset wells is successful. Potentially an additional test well or two may be drilled in one or more of the other undeveloped pay horizons which now will include the Barnett due to upcoming activity in Martin County. In this future activity, we have the potential to invest in excess of $100 million. In addition, the Company has identified 37 horizontal locations across our acreage in Upton and Martin counties that could be drilled in this same time frame. These additional 37 wells will require an investment of approximately $87 million. In total, therefore, with the $100 million in Wolfcamp “D” development, and the $87 million in 37 other near-term wells expected in the 2026-2028 timeframe, we have the potential to invest approximately $187 million in horizontal drilling in West Texas over the next several years.

GeneralOil and administrativegas production expense decreased $0.06$1.0 millionmillion, or 2.2%10.4% fromto $2.9$9.1 million for the three months ended MarchJune 31,30, 20252026, tofrom $2.8$10.1 million for the three months ended MarchJune 31,30, 2026.2025, Theand decreased $0.9 million, or 4.4% to $18.8 million for the six months ended June 30, 2026, from $19.7 million for the six months ended June 30, 2025. These changes reflect costs are primarily related to employeenatural compensation,production benefitsdeclines and otherfewer corporatewells costs.that have been placed on production period over period.

Income tax expense for the MarchJune 31,30, 20262026, and 2025 quarters varied due to the change in net income.

Our realized oil and natural gas prices vary due to world political events, supply and demand for oil, natural gas and natural gas liquids, product storage levels, transportation constraints, weather patterns and other market conditions. We sell the majority of our production at spot market prices. Accordingly, commodity price volatility directly affects our cash flow from operations. During the first quarterhalf of 2026, oil prices remained favorable and continued to support our oil-weighted development program and operating cash flows. However, oil prices remain volatile and may fluctuate significantly based on geopolitical events, changes in global supply and demand, inventory levels and market expectations regarding future supply disruptions. Natural gas prices in the Permian Basin were negatively affected by regional pipeline takeaway constraints and limited transportation capacity, resulting in negative or significantly reduced realized prices for certain Permian natural gas production during the quarter and potentially continuing during the remainder of 2026. To mitigate commodity price volatility, we sometimes lock in prices for a portion of our production through the use of derivatives. As of MarchJune 31,30, 2026, the Company had open oil derivative contracts for a total of 518,000367,000 barrels at a weighted average price of $74.92$74.84 per barrel.

The Company maintains a Credit Agreement providing for a reserves-based line of credit totaling $300 million, with a current borrowing base of $115$105 million. As of MayAugust 14, 2026, the Company’s has no outstanding borrowings under this credit facility. The bank reviews the borrowing base semi-annually and, at their 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 redetermination will be completed pursuant to the requirements of the credit agreement. 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.