Primeenergy Resources Corp: Form 10-Q for the period ended Jun 30, 2026

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.

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:

(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 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.

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 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.

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, are summarized as follows (in thousands of dollars):

The PV10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income tax, discounted at 10%. Although this measure is not in accordance with U.S. generally accepted accounting principles (“GAAP”), we believe that the presentation of the PV10 Value is relevant and useful to investors because it presents the discounted future net cash flow attributable to proved reserves prior to taking into account corporate future income taxes and the current tax structure. We use this measure when assessing the potential return on investment related to oil and gas properties. The PV10 of future income taxes represents the sole reconciling item between this non-GAAP PV10 Value versus the GAAP measure presented in the standardized measure of discounted cash flow. A reconciliation of these values is presented in the last three columns of the table above. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to proved oil and natural gas reserves after income tax, discounted at 10%.

“Proved developed” oil and gas reserves are reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. “Proved undeveloped” oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

In accordance with U.S. generally accepted accounting principles, product prices are determined using the twelve-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month, adjusted for oilfield or gas gathering hub and wellhead price differentials (e.g. grade, transportation, gravity, sulfur, and basic sediment and water) as appropriate. Also, in accordance with SEC specifications and U.S. generally accepted accounting principles, changes in market prices subsequent to December 31 are not considered.

While it may be reasonably anticipated that the prices received from 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.

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 and $2.64 per MMBtu in 2023. Oil prices, based on the West Texas Intermediate (WTI) Light Sweet Crude first-of-the-month average spot price, were $65.34 per barrel in 2025 as compared to $75.48 per barrel in 2024, and $78.22 per barrel in 2023. Since January 1, 2024, we have not filed any estimates of our oil and gas reserves with, nor were any such estimates included in any reports to, any federal authority or agency, other than the Securities and Exchange Commission.

District Information and Recent Activity

The following table represents certain reserves and well information as of December 31, 2025.

In West Texas, we have a field service group to service our operated wells and locations as well as third-party operators in the area. These services consist of well service support, site preparation and construction services for drilling and workover operations. Our operations are performed utilizing workover or swab rigs, saltwater disposal facilities, and trucks we own that are operated by our field employees.

Gulf Coast Region

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 June 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% 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.

We are monitoring the production from a new well drilled by Ventex Operating, on acreage in the Segno field of Polk County, Texas where the Company farmed-out its 55% leasehold rights for cash and a 5.53% over-riding royalty interest (ORRI). The well was cased in February 2025 and placed on production in May 2025. Currently, the well is producing 550 Mcfd and 23 Bopd.

In February of 2026 the Gulf Coast region performed a successful recompletion on the Wing #80 well in the Segno field of Polk County, Texas, at an expense of approximately $167,000, adding roughly 45 BOEPD to the Company’s production. We have plans to recomplete the Wing #85 well in the Segno field of Polk County, Texas, at an expense of approximately $150,000. Other than the 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.

Mid-Continent Region

Our Mid-Continent activities are concentrated in central Oklahoma. This region is managed from our office in Oklahoma City, Oklahoma. As of June 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. During 2026, we have participated with Validus Energy II in the drilling of one 3-mile long horizontal well in Grady County, Oklahoma with 2.9% interest, investing roughly $295,000 through completion. This well was put on production during the first quarter of this year.

West Texas Region

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 June 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 16,998 gross (9,567 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

Activity for 2026 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 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 proposals could 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 County, if the 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.

RESULTS OF OPERATIONS

We reported net income of $10.9 million, or $6.72 basic earnings per share, and $6.5 million, or $4.06 basic earnings per share for the six and three months ended June 30, 2026, respectively, as compared to $12.4 million, or $7.37 basic earnings per share, and $3.2 million, or $1.94 basic earnings per share for the six and three months ended June 30, 2025, respectively. Current-year net income reflects lower oil and natural gas liquids production, partially offset by higher realized prices, as well as higher natural gas production, which was adversely affected by negative realized natural gas prices.

Oil, gas and NGLs sales decreased $1.6 million, or 3.9% to $38.3 million for the three months ended June 30, 2026, from $39.8 million for the three months ended June 30, 2025, and decreased $9.3 million, or 10.6% to $77.8 million for the six months ended June 30, 2026, from $87.1 million for the six months ended June 30, 2025. Sales vary due to changes in volumes of production sold and realized commodity prices. Natural gas prices in the Permian Basin were negatively affected by regional pipeline takeaway constraints and limited to 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.

The following tables summarize the primary components of production volumes and average sales prices realized for the three and six months ended June 30, 2026 and 2025 (excluding realized gains and losses from derivatives).

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Oil and gas production expense decreased $1.0 million, or 10.4% to $9.1 million for the three months ended June 30, 2026, from $10.1 million for the three months ended June 30, 2025, and 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 related to natural production declines and fewer wells that have been placed on production period over period.

Production and ad valorem taxes increased $2.6 million, or 147.9% to $4.4 million for the three months ended June 30, 2026 from $1.8 million for the three months ended June 30, 2025, and increased $2.6 million, or 51.0% to $7.7 million for the six months ended June 30, 2026, from $5.1 million for the six months ended June 30, 2025. These increases reflect the changes in oil, natural gas and natural gas liquids production in the related periods.

Field service income decreased $0.003 million or 0.15% to $1.972 million for the three months ended June 30, 2026, from $1.975 million for the three months ended June 30, 2025, and decreased $0.4 million, or 8.8% to $3.8 million for the six months ended June 30, 2026, from $4.1 million for the six months ended June 30, 2025. Workover rig services and hot oil treatments represent the bulk of our field service operations where we experienced lower activity in 2026 compared to the prior year comparable period.

Field service expense increased $0.2 million or 13.79% to $1.4 million for the three months ended June 30, 2026, from $1.2 million for the three months ended June 30, 2025, and decreased $0.5 million, or 16.4% to $2.6 million for the six months ended June 30, 2026, from $3.1 million for the six months ended June 30, 2025. Field service expenses primarily consist of wages and vehicle operating expenses which varied period over period.

Depreciation, depletion and amortization expense decreased $4.9 million or 23.4% to $15.9 million for the three months ended June 30, 2026, from $20.8 million for the three months ended June 30, 2025, and decreased $8.5 million, or 20.7% to $32.6 million for the six months ended June 30, 2026, from $41.1 million for the six months ended June 30, 2025. This decrease is due to fewer wells being placed in service and therefore, fewer production volumes on a BOE basis period over period.

General and administrative expense increased $0.05 million or 1.6% to $3.0 million for the three months ended June 30, 2026, from $2.9 million for the three months ended June 30, 2025, and decreased $0.02 million, or 0.3% to $5.86 million for the six months ended June 30, 2025, from $5.88 million for the six months ended June 30, 2025. These changes are nominal and reflect consistent business operations.

Interest expense decreased $0.4 million or 61.8% to $0.3 million for the three months ended June 30, 2026, from $0.7 million for the three months ended June 30, 2025, and decreased $0.8 million, or 58.4% to $0.5 million for the six months ended June 30, 2026, from $1.3 million for the six months ended June 30, 2025. This decrease reflects the lower borrowings during the six months of 2026 under our revolving credit agreement compared to the same period in 2025.

Income tax expense for the June 30, 2026, and 2025 quarters varied due to the change in net income.

LIQUIDITY AND CAPITAL RESOURCES

The Company’s goal is to responsibly develop its oil and gas reserves, predominantly through horizontal drilling. Our strategy includes targeting reservoirs with high initial production rates and cash flow as well as targeting reservoirs with lower initial production rates but with higher expected return on investment. We believe that with today’s technology, horizontal development of our reserves provides superior economic results as compared to vertical development, by delivering higher production rates through greater contact and stimulation of a larger volume of reservoir rock while minimizing the surface footprint required to develop those same reserves.

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 ample 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’s horizontal development activities in the last two years, along with our projected activity for 2026, can be summarized as follows: in 2024 we invested $113 million in 48 horizontals, in 2025 we invested $96 million in 48 horizontals, and in 2026, we expect to invest $52 million in 28 horizontals as discussed under district information and recent activity. Therefore, in total, since January 2024 and through 2026, the Company will have invested roughly $261 million in horizontal development, primarily in the Midland Basin of West Texas.

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 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 half 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 June 30, 2026, the Company had open oil derivative contracts for a total of 367,000 barrels at a weighted average price of $74.84 per barrel.

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. If the borrowing base utilization percentage is less than 15% of total available borrowings, the Company is not required to enter into any hedge agreements at this time. Additional drilling and future development plans will be established based on an expectation of available cash flows from operations and availability of funds under our revolving credit facility.

The Company maintains a Credit Agreement providing for a reserves-based line of credit totaling $300 million, with a current borrowing base of $105 million. As of August 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.

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.

As of the end of the current reported period covered by this report, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission’s rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.

There were no changes in the Company’s internal control over financial reporting that occurred during the last quarter of 2026 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.