REI 10-K & 10-Q changes, risk factors and insider trading
Ring Energy, Inc. · NYSE · Crude Petroleum & Natural Gas · CIK 1384195 · All filings on SEC.gov
At a glance
What changed in the latest 10-K
Risk Factors
Removed heading “We have registered shares of our common stock for possible resale by certain of our stockholders, resulting in significant "market overhang" of our common stock.”
Largest changes
“In addition, on March 6, 2024, the SEC adopted a rule requiring registrants to include certain climate-related disclosures, including Scope 1 and 2 GHG emissions, climate-related targets and goals, and certain climate-related financial statement metrics, in registration statements and annual reports, though the implementation of this rules is currently paused pending the outcome of legal challenges against the rule. Currently, the ultimate impact of these laws on our business is uncertain. …”see in full comparison
“We have registered shares of our common stock for possible resale by certain of our stockholders, resulting in significant "market overhang" of our common stock.”see in full comparison
In the United States, no comprehensive climate change legislation has been implemented at the federal level, though recently passed laws such as the IRA advance numerous climate-related objectives. The IRA contains hundreds of billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles, and supporting infrastructure and carbon capture and sequestration, among other provisions.see in full comparisonMoreover,The OBBBA rescinds or eliminates funding for multiple programs under the IRA aimed at reducing or monitoring GHG emissions and other air pollutants, such as the Greenhouse Gas Reduction Fund and methane monitoring initiatives. While the OBBBA will potentially affect federalregulators,effortsstateto address climate change andlocalemissionsgovernments,reductions, various federal agencies have, from time to time, adopted climate change considerations into their rulemaking andprivatedecision-makingpartiesprocesses and havetakenpromulgated(or announcedregulations thatthey planseek totake)restrict,actions that havemonitor, ormayotherwisehavelimitaGHGsignificant influence on our operations.emissions. International climate commitments made by political, industrial, and financial and other stakeholders may also impact commercial, regulatory, and consumer trends related to climate change.
“In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations pursuant to the CAA that, among other things, require PSD preconstruction and Title V operating permits for GHG emissions from certain large stationary sources, mandate monitoring and annual reporting of GHG emissions, and impose new standards for reducing methane emissions from oil and gas operations by limiting venting and flaring and implementing leak detection and repair programs. …”see in full comparison
“In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations pursuant to the CAA that, among other things, require PSD preconstruction and Title V operating permits for GHG emissions from certain large stationary sources, mandate monitoring and annual reporting of GHG emissions, and impose new standards for reducing methane emissions from oil and gas operations by limiting venting and flaring and implementing leak detection and repair programs. …”see in full comparison
see in full comparisonInternationally,At the international level, the United Nations-sponsored“Paris Agreement”encouragesmember statesnations toindividuallylimitdetermine and submit non-binding emissions reduction targets. The United States’ most recent goal was to reduce its economy-nettheir GHG emissionsbythrough61nationally-determined,tothough66non-binding,percentreductionfrom 2005 levels by 2035.goals. Recent Conferences of the Parties have resulted in reaffirmations of the objectives of the Paris Agreement, calls for parties to eliminate certain fossil fuel subsidies and pursue reductions in non-carbon dioxide GHG emissions, agreements to transition away from fossil fuels in energy systems and increase renewable energy capacity, financial commitments to fund energy transition efforts in developing countries, and similar initiatives, though none legally binding. However, in January 2025,President Trump initiatedtheUnitedcurrentStates’ withdrawal from the Paris Agreement andadministration ordered the revocation of anyrelatedUnited States financialcommitments.commitments on emission goals associated with international climate agreements. Then, in January 2026, the United States finalized its withdrawal from the Paris Agreement. The impacts of the United States’ withdrawal and other existing or future climate-related orders, pledges, agreements or any legislation or regulation promulgated in connection with the Paris Agreement, the Global Methane Pledge, or other international conventions cannot be predicted at this time. Further, state and local governments, financial institutions, and industry groups may elect to continue participating in international climate-related initiatives.
Full comparison: every changed paragraph (28)
We are subject to various risks and uncertainties in the ordinary course of our business. The following summarizes significant risks and uncertainties that may adversely affect our business, financial condition, or results of operations. We cannot assure you that any of the events discussed in the risk factors below will not occur. Further, the risks and uncertainties described below are not the only ones we face. Additional risks not presently known to us or that we currently deem immaterial may also materially affect our business. Readers should carefully consider the risk factors included below as well as those matters referenced in this Annual Report under “Forward-Looking Statements” and other information included and incorporated by reference into this Annual Report.
Because a substantial percentage of our proved properties are proved undeveloped (approximately 31%32%), we will require significant additional capital to develop suchthese properties before they may become productive. Further, because of the inherent uncertainties associated with drilling for oil and gas, some of these properties may never be developed to the extent that they result in commercial quantities of oil and natural gas.
While our current business plan is to generally fund the development costs with cash flow from our other producing properties, if such cash flow is not sufficient, we may be forced to seek alternative sources for cash, through the issuance of additional equity or debt securities, increased borrowingsborrowings, or other means.
To reduce our exposure to commodity price uncertainty and increase cash flow predictability, we have entered into crude oil and natural gas price hedging arrangements with respect to a significant portion of our expected production in order to economically hedge a portion of our forecasted oil and natural gas production. Additionally, our credit facility requires us to hedge a significant portion of our production. These derivative contracts typically limit the benefit we would otherwise receive from increases in the prices for oil and natural gas.
Natural disasters, adverse weather conditions (particularly abnormally cold weather in the winter, and hurricanes and thunderstorms in the summer), floods, pandemics, acts of terrorismterrorism, and other catastrophic or geo-political events may cause damage or disruption to our operations and the global economy, or could result in market disruptions, any of which could have an adverse effect on our business, operating results, and financial condition.
The recent coronavirus outbreak impacted various businesses throughout the world, including an impact on the global demand for oil and natural gas, travel restrictions and the extended shutdown of certain businesses in impacted geographic regions. If other pandemics occur, they could have a material adverse impact on our business operations, operating results and financial condition.
Our success depends on our ability to attract, retain and motivate a highly-skilled management team and workforce. Failure to ensure that we have the depth and breadth of management and personnel with the necessary skill sets and experience could impede our ability to achieve growth objectives and execute our operational strategy. As we continue to expand, we will need to promote or hire additional staff, and, as a result of increased compensation and benefit packages in our industry, as well as inflationary pressures, it may be difficult to attract or retain suchthese individuals without incurring significant additional costs.
Our decisions to purchase, explore, develop, or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data, and engineering studies, the results of which may be inconclusive or subject to varying interpretations. Please read “—Reserve estimates depend on many assumptions that may turn out to be inaccurate.” (below) for a discussion of the uncertaintyuncertainties involved in these processes. Our cost of drilling, completing, and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular well or project uneconomical. Further, many factors may curtail, delay, or cancel drilling, including delays imposed by or resulting from compliance with regulatory requirements; pressure or irregularities in geological formations; shortages of or delays in obtaining equipment and qualified personnel; equipment failures or accidents; adverse weather conditions; reductions in oil and natural gas prices; title problems; and limitations in the market for oil and natural gas.
We follow the full cost method of accounting for our oil and natural gas properties. Under the full cost method, the net book value of properties, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling is the estimated after tax future net revenues from proved oil and natural gas properties, discounted at 10% per year. Discounted future net revenues are estimated using oil and natural gas spot prices based on the average price during the preceding 12-month period determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, except for changes which are fixed and determinable by existing contracts. The net book value is compared to the ceiling on a quarterly basis. The excess, if any, of the net book value above the ceiling is required to be written off as an impairment expense. During the yearsyear ended December 31, 2024,2025, 2023,we recorded a non-cash write down of $108.8 million. During the years ended 2024 and 20222023 we did not incur any write-downs. Under SEC full cost accounting rules, any write-off recorded may not be reversed even if higher oil and natural gas prices increase the ceiling applicable to future periods. Future price decreases could result in reductions in the financial carrying value of such assets and an equivalent charge on our financial statements.
We operate in a highly competitive environment for acquiring properties and marketing oil and natural gas. Our competitors include multinational oil and natural gas companies, major oil and natural gas companies, independent oil and natural gas companies, individual producers, financial buyers, as well as participants in other industries that supply energy and fuel to consumers. Many of our competitors have greater and more diverse resources than we do. Additionally, competition for acquisitions may significantly increase the cost of available properties. We compete for the personnel and equipment required to explore, develop, and operate oil and gas properties. Our competitors also may have established long-term strategic positions and relationships in areas in which we may seek to enter. Consequently, our competitors may be able to address these competitive factors more effectively than we can. If we are not successful in our competition for oil and natural gas properties or in our marketing of production, then our financial condition and operation results would be adversely affected.
We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production from a given pad, which may cause volatility in our operating results. In addition, problems affecting one pad could adversely affect production from all wells on suchthe pad. As a result, multi-well pad drilling can cause delays in the scheduled commencement of production or interruptions into ongoing production.
Our operations are substantially dependent on the availability, use and disposal of water. New legislation and regulatory initiatives or restrictions relating to water disposal wells could have a material adverse effect on our future business, financial condition, operating resultsresults, and prospects.
Water is an essential component of our drilling and hydraulic fracturing processes. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil, natural gas and NGLs, which could have an adverse effect on our business, financial condition, and results of operations. Waste water from our operations typically areis disposed of via underground injection. Some studies have linked earth tremors in certain areas to underground injection, which has led to greater public scrutiny of disposal wells. Any new environmental initiatives or regulations that restrict injection of fluids, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of oil and gas, or that limit the withdrawal, storagestorage, or use of surface waterwater, ground water, or groundproduced water necessary for hydraulic fracturing of our wells, could increase our operating costs and cause delays, interruptionsinterruptions, or cessation of our operations, the extent of which cannot be predicted, and all of which would have an adverse effect on our business, financial condition, results of operations, and cash flows.
Exploration, development, production, and sale of oil and natural gas are subject to extensive federal, statestate, and local regulation. It is not possible to predict how or when regulations affecting our operations might change. There is ongoing controversy regarding the leasing of federal lands. We may be required to make large expenditures to comply with governmental regulations. Other matters subject to regulation include: discharge permits for drilling operations; drilling bonds; reports concerning operations; the spacing of wells; unitization and pooling of properties; and taxation.
In the United States, no comprehensive climate change legislation has been implemented at the federal level, though recently passed laws such as the IRA advance numerous climate-related objectives. The IRA contains hundreds of billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles, and supporting infrastructure and carbon capture and sequestration, among other provisions. Moreover,The OBBBA rescinds or eliminates funding for multiple programs under the IRA aimed at reducing or monitoring GHG emissions and other air pollutants, such as the Greenhouse Gas Reduction Fund and methane monitoring initiatives. While the OBBBA will potentially affect federal regulators,efforts stateto address climate change and localemissions governments,reductions, various federal agencies have, from time to time, adopted climate change considerations into their rulemaking and privatedecision-making partiesprocesses and have takenpromulgated (or announcedregulations that they planseek to take)restrict, actions that havemonitor, or mayotherwise havelimit aGHG significant influence on our operations.emissions. International climate commitments made by political, industrial, and financial and other stakeholders may also impact commercial, regulatory, and consumer trends related to climate change.
In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations pursuant to the CAA that, among other things, require PSD preconstruction and Title V operating permits for GHG emissions from certain large stationary sources, mandate monitoring and annual reporting of GHG emissions, and impose new standards for reducing methane emissions from oil and gas operations by limiting venting and flaring and implementing leak detection and repair programs. Federal policy towards GHG emissions, and regulation thereunder, has varied significantly between the past several Presidential administrations. The current administration has expressed a policy preference of limiting or rescinding regulations concerning GHG emissions and, in February 2026, promulgated a final rule repealing the EPA’s 2009 “Endangerment Finding” and its motor vehicle GHG emission performance standards. This rescission of the “Endangerment Finding” eliminates the basis for EPA’s authority under the CAA for most of its regulations concerning GHGs. However, whether or how such policies and the EPA’s rescission of its “Endangerment Finding” will be implemented and if they will survive any potential legal challenges, or whether future administrations or Congress may pursue new GHG emissions regulation, cannot be predicted at this time.
In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations pursuant to the CAA that, among other things, require PSD preconstruction and Title V operating permits for GHG emissions from certain large stationary sources, mandate monitoring and annual reporting of GHG emissions, and impose new standards for reducing methane emissions from oil and gas operations by limiting venting and flaring and implementing leak detection and repair programs. The IRA also imposes the first-ever fee on GHG emissions through a WEC, which the EPA has finalized regulations to implement. In May 2024, the EPA published a final rule expanding GHG emissions reporting obligations for certain oil and natural gas sector sources. While the first Trump administration took a number of actions to revise federal regulation of methane from the oil and natural gas sector, these actions were subsequently reversed by both the Biden administration and Congress. Moreover, in December 2023, the EPA published a final rule that established more stringent performance standards for new sources and first-time standards for existing sources under applicable agency regulations at 40 C.F.R. Part 60 for methane and VOC emissions for the crude oil and natural gas sources. The requirements imposed by this rule include enhanced leak detection and repair obligations, zero-emission requirements for certain processes and practices, “green well” completion standards, limitations on routine flaring, and a “Super Emitter Response Program” which triggers additional requirements following certain large emissions events. Compliance with these rules and legislation will likely require enhanced record-keeping practices, the purchase of new equipment, such as optical gas imaging instruments to detect leaks, increased frequency of maintenance and repair activities to address emissions leakage and additional personnel time to support these activities or the engagement of third-party contractors to assist with and verify compliance. While legal challenges to many of the above discussed regulations are ongoing and, either the current Trump administration or Congress may also pursue rulemakings or legislation, respectively, that could repeal, revise, or otherwise limit the enforcement of these regulations and certain of the IRA’s provisions, like the WEC, we cannot predict whether and when such action will be taken and the outcome and timeline for such actions may continue to be uncertain and subject to further legal challenges.
Internationally,At the international level, the United Nations-sponsored “Paris Agreement” encourages member statesnations to individuallylimit determine and submit non-binding emissions reduction targets. The United States’ most recent goal was to reduce its economy-nettheir GHG emissions bythrough 61nationally-determined, tothough 66non-binding, percentreduction from 2005 levels by 2035.goals. Recent Conferences of the Parties have resulted in reaffirmations of the objectives of the Paris Agreement, calls for parties to eliminate certain fossil fuel subsidies and pursue reductions in non-carbon dioxide GHG emissions, agreements to transition away from fossil fuels in energy systems and increase renewable energy capacity, financial commitments to fund energy transition efforts in developing countries, and similar initiatives, though none legally binding. However, in January 2025, President Trump initiated the Unitedcurrent States’ withdrawal from the Paris Agreement andadministration ordered the revocation of any relatedUnited States financial commitments.commitments on emission goals associated with international climate agreements. Then, in January 2026, the United States finalized its withdrawal from the Paris Agreement. The impacts of the United States’ withdrawal and other existing or future climate-related orders, pledges, agreements or any legislation or regulation promulgated in connection with the Paris Agreement, the Global Methane Pledge, or other international conventions cannot be predicted at this time. Further, state and local governments, financial institutions, and industry groups may elect to continue participating in international climate-related initiatives.
In addition, on March 6, 2024, the SEC adopted a rule requiring registrants to include certain climate-related disclosures, including Scope 1 and 2 GHG emissions, climate-related targets and goals, and certain climate-related financial statement metrics, in registration statements and annual reports, though the implementation of this rules is currently paused pending the outcome of legal challenges against the rule. Currently, the ultimate impact of these laws on our business is uncertain. Separately, enhanced climate related disclosure requirements could lead to reputational or other harm with customers, regulators, investors, or other stakeholders and could also increase our litigation risks relating to statements alleged to have been made by us or others in our industry regarding climate change risks, or in connection with any future disclosures we may make regarding reported emissions, particularly given the inherent uncertainties and estimations with respect to calculating and reporting GHG emissions. Additionally, the SEC has also from time to time applied additional scrutiny to existing climate-change related disclosures in public filings, increasing the potential for enforcement if the SEC were to allege an issuer’s existing climate disclosures misleading or deficient.
Additionally, in response to concerns related to climate change, companies in the oil and natural gas industry may be exposed to increasing financial risks. Financial institutions, including investment advisors and certain sovereign wealth, pension, and endowment funds, may elect in the future to shift some or all of their investments into non-oil and natural gas related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices, and some of them may elect in the future not to provide funding for oil and natural gas companies. Many of the largest U.S. banks have made net zero commitments and have announced that they will be assessing financed emissions across their portfolios and taking steps quantify and reduce those emissions. A material reduction in the capital available to the oil and natural gas industry could make it more difficult to secure funding for exploration, development, production, transportation, and processing activities, which could result in decreased demand for our products or otherwise adversely impact our financial performance.
From time to time, federal and state level legislation has been proposed that would, if enacted into law, make significant changes to tax laws, including to certain key federal and state income tax provisions currently applicable to oil and natural gas exploration and development companies. Such legislative changes have included, but have not been limited to, (i) the elimination of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) an extension of the amortization period for certain geological and geophysical expenditures, (iv) the elimination of certain other tax deductions and relief previously available to oil and natural gas companies, and (v) an increase in the federal income tax rate applicable to corporations such as us. It is unclear whether theseany or similarsuch changes will be enacted and, if enacted, how soon any such changes could take effect. Additionally, states in which we operate or own assets may impose new or increased taxes or fees on oil and natural gas extraction. The passage of any such legislation as a result of these proposals andor other changes in federal income tax laws or the imposition of new or increased taxes or fees on oil and natural gas extraction could adversely affect our operating results and cash flows.
In addition, the IRA, which includes, among other things, a corporate alternative minimum tax (the "CAMT"), provides for an investment tax credit for qualified biomass property and introduces a one percent excise tax on corporate stock repurchases. Under the CAMT, a 15 percent minimum tax will be imposed on certain adjusted financial statement income of "applicable corporations," which was effective beginning January 1, 2023. The CAMT generally treats a corporation as an applicable corporation in any taxable year in which the "average annual adjusted financial statement income" of the corporation and certain of its subsidiaries and affiliates for a three-taxable-year period ending prior to such taxable year exceeds $1 billion. Based on our current interpretation of the IRA and the CAMT and a number of operational, economic, accounting and regulatory assumptions, we do not anticipate the CAMT materially increasing our U.S. federal income tax liability in the near term. The foregoing analysis is based upon our current interpretation of the provisions contained in the IRA and the CAMT. In the future, theThe U.S. Department of the Treasury and the Internal Revenue Service arehave expectedreleased to releaseproposed regulations and other interpretive guidance relating to the CAMT,CAMT. and anyAny significant variance from our current interpretation could result in a change in the expected application of the CAMT to us and adversely affect our operating results and cash flows.
We have a Credit Facility in place with $600$585 million in commitments from borrowings and letters of credit under our SecondThird Amended and Restated Credit Agreement dated AugustJune 31,18, 20222025 with TruistBank Bankof America, N.A. as Administrative Agent (the "Second Credit Agreement"). As of December 31, 2024,2025, $385$420 million was outstanding on our Credit Facility. If we further utilize this facility, the level of our indebtedness could affect our operations in several ways, including the following:
We rely on computer and telecommunications systems, and failures in our systems or cyber securitycybersecurity attacks or breaches could result in information theft, data corruption, disruption in operations, and/or financial loss.
The oil and natural gas industry is highly dependent upon digital technologies to conduct day-to-day operations including certain exploration, development, and production activities. We depend on digital technology to process and record financial and operating data, estimate quantities of oil and natural gas reserves, analyze seismic and drilling information, process and store personally identifiable information on our employees and royalty owners, and communicate with our employees and other third parties. Our business partners, including vendors, service providers, purchasers of our production, and financial institutions, are also dependent on digital technology. It is possible that we could incur interruptions from cybersecurity attacks or breaches, computer viruses or malware that could result in disruption of our business operations and/or financial loss. Although we utilize various procedures and controls to monitor and protect against these threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing and causing us to suffer losses in the future. In addition, weaknesses in the cyber securitycybersecurity of our vendors, suppliers, and other business partners could facilitate an attack on our technologies, systems, and networks. Even so, any cyber incidents or interruptions to our computing and communications infrastructure or our information systems could lead to data corruption, communication interruption, unauthorized release, gathering, monitoring, misuse, or destruction of proprietary or other information, or otherwise significantly disrupt our business operations.
We have registered shares of our common stock for possible resale by certain of our stockholders, resulting in significant "market overhang" of our common stock.
In connection with the Stronghold Acquisition completed in 2022, Warburg Pincus & Company US, LLC and its affiliates hold approximately 28.9 million shares of our common stock. This represents approximately 14% of our presently outstanding shares of common stock and if the selling stockholders choose to sell all or a large number of their shares, from time to time, it likely would have a depressive effect on the market price of our common stock. Further, the market's perception of future sales of common stock may adversely affect the price of our common stock.
We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our Board of Directors and will depend upon various factors, including our business, financial condition, results of operations, capital requirements, and investment opportunities. In addition, the terms of our Second Credit Agreement have restrictions on dividend payments to our equity holders, including our common stockholders.
Management's Discussion & Analysis (MD&A)
New heading “Lime Rock Acquisition”
New heading “Credit Agreement”
New heading “Year Ended December 31, 2025 Compared to Year Ended December 31, 2024”
Removed heading “Year Ended December 31, 2023 Compared to Year Ended December 31, 2022”
Largest changes
“We perform a ceiling test at the end of each reporting period to evaluate for potential non-cash impairments. Under the full cost method of accounting, the net book value of properties, less related deferred income taxes, may not exceed a calculated “ceiling,” which is defined as the estimated after-tax future net revenues from proved oil and natural gas properties, discounted at an annual rate of 10%. The discounted future net revenues are estimated using spot prices for oil and natural gas, based on the average price during the preceding twelve months. …”see in full comparison
Inflation has increased costs associated with our capital program and production operations. We have experienced increases in the costs of many of the materials, supplies, equipment, and services used in our operations and we expect inflation to continue based on current economicsee in full comparisoncircumstances.circumstances,Inincludingaddition,tariffs,thetradeattempts to reduce inflation by the U.S. Federal Reserve have resulted in increased interest rates on debt, contributed to debtwars, andequitysupplymarketchainvolatility, and increased substantially our interest expense.disruptions. We continue to closely monitor costs and take all reasonable steps to mitigate the inflationary effect on our cost structure and also work to enhance our efficiency to minimize additional cost increases where possible.
“During the year ended December 31, 2025, the Company recorded non-cash write-downs of the carrying value of the Company’s proved oil and natural gas properties as a result of ceiling test limitations of approximately $108.8 million, which is reflected as ceiling test impairment in the accompanying Statements of Operations. The Company did not have any write-downs related to the full cost ceiling limitation during the years ended December 31, 2024 or 2023.”see in full comparison
see in full comparisonRather than Eurodollar loans, the reference rate in the Second Credit Agreement is the SOFR. Also, the SecondThe Credit Agreement permits the Company to declare restricted payments (including dividends) for its equity owners, subject to certain limitations, including (a) (i) no default or event of default has occurred or will occur upon such payments, (ii) the pro forma Leverage Ratio (outstanding debt to adjusted earnings before interest,taxes,incomedepreciationtax expense, depreciation, depletion and amortization, exploration expenses, and all other non-cash charges acceptable to the Administrative Agent) does not exceed 2.00 to 1.00, (iii) the amount of such payments does not exceed Available Free Cash Flow (as defined in theSecondCredit Agreement), and (iv) the Borrowing Base Utilization Percentage (as defined in theSecondCredit Agreement) is not greater than80%.80%; or (b) (i) no default or event of default has occurred or will occur upon such payments, (ii) the pro forma Leverage Ratio does not exceed 1.50 to 1.00, and (iii) the Borrowing Base Utilization Percentage is not greater than 75%.
“Year Ended December 31, 2025 Compared to Year Ended December 31, 2024”see in full comparison
“Year Ended December 31, 2023 Compared to Year Ended December 31, 2022”see in full comparison
Full comparison: every changed paragraph (88)
The following discussion and analysis should be read in conjunction with our accompanying financial statements and the notes to those financial statements included elsewhere in this Annual Report. The following discussion includes forward-looking statements that reflect our plans, estimates, and beliefsbeliefs, and our actual results could differ materially from those discussed in these forward-looking statements as a result of many factors, including those discussed under “Risk Factors,” "Forward Looking Statements," and elsewhere in this Annual Report.
•Employ industry leading drilling and completion techniques. Ring’s executive team intends to continue to utilize new and innovative technological advancements for completion optimization, comprehensive geological evaluation, and reservoir engineering analysis to generate value and to build future development opportunities. These technological advancements have led to a low-cost structure that helps maximize the returns generated by our drilling programs.
Lime Rock Acquisition
On March 31, 2025, the Company, as buyer, and Lime Rock Resources IV-A, L.P. (“LRRA”), and Lime Rock Resources IV-C, L.P. (“LRRC” and with LRRA, “Lime Rock”), as seller, consummated the transactions contemplated in that certain Purchase and Sale Agreement dated February 25, 2025, by and among the Company, LRRA and LRRC (the “Purchase Agreement”) that was previously reported on Form 8-K filed on February 28, 2025 with the Securities and Exchange Commission (“SEC”). At the closing of the Purchase Agreement, among other things, the Company acquired (the “Lime Rock Acquisition”) interests in oil and gas leases and related property of Lime Rock located in Andrews County, Texas, for an aggregate consideration consisting of: (i) approximately $69.3 million in cash, net of customary purchase price adjustments, paid at the closing of the Lime Rock Acquisition, (ii) $10.0 million in cash paid on December 31, 2025, and (iii) 6,452,879 shares of common stock (the "LRR Shares"). On March 31, 2025, in connection with the closing of the Lime Rock Acquisition, the Company and Lime Rock entered into a customary registration rights agreement relating to the LRR Shares. On May 2, 2025, a registration statement on Form S-3 with respect to the resale of the LRR Shares was declared effective by the SEC.
Credit Agreement
On June 18, 2025, the Company as borrower, Bank of America, N. A. as the Administrative Agent and Issuing Bank (“Bank of America”), and the lenders party thereto (the “Lenders”) entered into the Third Amended and Restated Credit Agreement (the “Credit Agreement”) which amended and restated that certain Second Amended and Restated Credit Agreement dated as of August 31, 2022, by and among the Company, Truist Bank, as administrative agent, and the lenders party thereto, as amended by that certain First Amendment to Second Amended and Restated Credit Agreement, dated as of February 12, 2024 (the “Existing Credit Agreement”). All of the obligations under the Credit Agreement, and the guarantees of those obligations, are secured by substantially all of the Company’s assets. Among other things, the Credit Agreement changed the administrative agent from Truist Bank to Bank of America; reduced the borrowing base and aggregate elected commitment from $600 million to $585 million; extended the maturity date of the Credit Agreement from August 31, 2026 to June 18, 2029; reduced the applicable margin pricing grid by 25 basis points; and made certain administrative changes to the Existing Credit Agreement.
In the first quarter of 2024, in the Northwest Shelf, the Company drilled and completed two 1-mile horizontal wells (one with a working interest of 99.5% and the other with a working interest of 100%). In the Central Basin Platform, the Company drilled and completed nine wells, all with a working interest of 100%. Specifically, in our Andrews County acreage the Company drilled and completed three 1-mile horizontal wells, in the Ector County acreage the Company drilled three vertical wells, and in the Crane County acreage the Company drilled and completed three vertical wells. Additionally, within the Central Basin Platform, the Company drilled and completed one salt water disposal ("SWD") well in Crane County.
In the second quarter of 2024, in the Central Basin Platform, the Company drilled and completed eleven wells, all with a working interest of 100%. Specifically, in our Andrews County acreage the Company drilled and completed five 1-mile horizontal wells, in the Ector County acreage the Company drilled three vertical wells, and in the Crane County acreage the Company drilled and completed three vertical wells.
DuringIn the thirdfirst quarter of 2024,2025, in the Northwest Shelf in Yoakum County, the Company drilled and completed twothree 1-mile horizontal wells,wells eachand one 1.25-mile horizontal well, all with a working interest of 100%,75%. and one 1.5-mile horizontal well with a working interest of approximately 94.2%. Meanwhile, inIn the Central Basin Platform,Platform in Ector County, the Company drilled and completed sixthree vertical wells, all with a working interest of 100%, three in Ector County and three in Crane County. Finally, in the Central Basin Platform in Andrews County, the Company drilled four 1-mile horizontal wells, all with a working interest of 100%. Two of these wells were completed. The remaining two wells were completed in the fourth quarter of 2024.
In the second quarter of 2025, in the Central Basin Platform in Andrews County, the Company drilled and completed one 1-mile horizontal well, with a working interest of 100%. Also in the Central Basin Platform in Crane County, the Company drilled and completed one vertical well, with a working interest of 100%.
In the fourththird quarter of 2024, the Company completed and placed on production the two aforementioned 1-mile horizontal wells in the Central Basin Platform. The Company completed two additional 1-mile horizontal wells2025, in the Central Basin Platform in Andrews CountyCounty, (boththe Company drilled and completed three 1-mile horizontal wells, each with a working interest of 100%).100%. OnAlso the southern side ofin the Central Basin Platform,Platform in Crane County, the Company drilled and completed one vertical1-mile horizontal well in its Crane County acreage and threeone vertical wellswell, inboth itswith Ectora Countyworking acreageinterest of 100%. Finally, the Company began drilling one 1.5-mile horizontal well (each with a working interest of 100%). Also in Crane County the Company drilled three 1-mile horizontal wells (each with a working interest of 100%), completing the first two in the fourthNorthwest quarter, and the last well will be completedShelf in 2025.Yoakum County.
In the fourth quarter of 2025, the Company finished drilling and completed the aforementioned 1.5-mile horizontal well in the Northwest Shelf. The Company drilled and completed two additional 1-mile horizontal wells in the Central Basin Platform, one in Andrews County and one in Crane County (both with a working interest of 100%). Also in Crane County the Company drilled and completed one vertical well (with a working interest of 100%).
In summary, for 2024,2025, the Company drilled 22and completed 12 horizontal wells,wells 22and 6 vertical wells, and one SWD well, completing all but one horizontal well.wells. The table below sets forth our drilling and completion activities for 20242025 by quarter, and full year total through December 31, 2024.2025.
Average oil and natural gas prices received through 2024 and 2025 continued to demonstrate commodity price volatility and we believe oil and natural gas prices will continue to be volatile for the foreseeable future. The ability to find and develop sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success.
Ceiling Test
We perform a ceiling test at the end of each reporting period to evaluate for potential non-cash impairments. Under the full cost method of accounting, the net book value of properties, less related deferred income taxes, may not exceed a calculated “ceiling,” which is defined as the estimated after-tax future net revenues from proved oil and natural gas properties, discounted at an annual rate of 10%. The discounted future net revenues are estimated using spot prices for oil and natural gas, based on the average price during the preceding twelve months. This average is calculated as an unweighted arithmetic mean of the first-day-of-the-month prices for each month within that period, except when changes are fixed and determinable by existing contracts. As a result of the ceiling test, driven by a decrease in the twelve month average commodity prices, the Company recognized a non-cash impairment charge of $108.8 million during the year ended December 31, 2025. If this downward trend continues, the Company's discounted future net revenues could continue to decline, which may trigger additional non-cash impairments recognized in future periods. Estimating potential future non-cash impairments is complex due to numerous factors affecting the ceiling test calculation, including but not limited to future prices, operating costs, upward or downward reserve revisions, reserve additions, and tax attributes. The amount of any additional non-cash impairment, if any, is not estimable at this time given the uncertainty of these factors.
The Permian Basin has been experiencing a lack of sufficient pipeline transportation thatfor is connected to markets that are purchasing theits natural gas produced.production. This has resulted in negative natural gas prices at times, whereby the seller is actually paying the purchaser to take the gas. We experienced negative realized gas prices for all of 2024 and 2025 and conditions are continuing. If these depressed or inverted natural gas prices returncontinue toin the region, our natural gas revenues will continue to be negatively impacted.
Inflation has increased costs associated with our capital program and production operations. We have experienced increases in the costs of many of the materials, supplies, equipment, and services used in our operations and we expect inflation to continue based on current economic circumstances.circumstances, Inincluding addition,tariffs, thetrade attempts to reduce inflation by the U.S. Federal Reserve have resulted in increased interest rates on debt, contributed to debtwars, and equitysupply marketchain volatility, and increased substantially our interest expense.disruptions. We continue to closely monitor costs and take all reasonable steps to mitigate the inflationary effect on our cost structure and also work to enhance our efficiency to minimize additional cost increases where possible.
Year Ended December 31, 2025 Compared to Year Ended December 31, 2024
Oil sales. Oil sales decreased approximately $56.4 million to $307.6 million in 2025 from $364.0 million in 2024. This was due to a price variance of approximately $(54.9) million from a decrease in the average realized per barrel oil price to $63.53 in 2025 from $74.87 in 2024. Also impacting the oil sales was a volume variance of approximately $(1.5) million from a decrease in sales volumes to 4,841,164 barrels of oil in 2025 from 4,861,628 barrels of oil in 2024, primarily driven by natural asset decline, offset by production from wells within the assets acquired with the Lime Rock Acquisition (closed in March 2025) and organic growth from workovers, new drills, and other capital expenditures.
Natural gas sales. Natural gas sales remained essentially constant, with approximately $(9.3) million in 2025 and $(9.3) million in 2024. The average realized per Mcf gas price increased to $(1.33) in 2025 from $(1.44) in 2024. The positive change in price was due to an increase in the average gross realized price that was higher than the increase in the average fees. In 2025, the average gross realized price for natural gas was $0.75 per Mcf, and the average fees per Mcf were $(2.08), bringing the net average price to $(1.33) per Mcf. In 2024, the average gross realized price for natural gas was $0.29 per Mcf, and the average fees per Mcf were $(1.73), bringing the net average price to (1.44) per Mcf. The natural gas sales volume increased to 6,980,958 Mcf in 2025 from 6,423,674 Mcf in 2024.
NGL sales. NGL sales decreased approximately $2.7 million to $8.9 million in 2025 from $11.6 million in 2024, due to a price variance of approximately $(3.9) million, as the average realized price per barrel of NGLs was $6.43 in 2025 compared to $9.23 in 2024. This was due to a reduction in the gross realized price per NGL barrel to $18.84 in 2025 compared to $20.00 in 2024 coupled with a growth in the average fees per barrel to $(12.41) in 2025 compared to $(10.77) in 2024. Offsetting this decrease to sales was a volume variance of approximately $1.2 million, as volumes were 1,387,818 barrels of NGLs in 2025 compared to 1,258,814 barrels in 2024, with 82% of the increase in barrels due to the assets acquired in the Lime Rock Acquisition in March 2025.
Lease operating expenses. Our total lease operating expenses (“LOE”) increased approximately $1.0 million to $79.4 million in 2025 from $78.3 million in 2024 and decreased on a Boe basis to $10.73 in 2025 from $10.89 in 2024. These per Boe amounts are calculated by dividing our total LOE by our total volume sold, in Boe. LOE increased due to additional expenses from the assets acquired with the Lime Rock Acquisition (closed in March 2025) which contributed to a 3% increase in production of 201,422 Boe. Specifically, the Company experienced increases of $4.7 million for electrical/utilities costs, $0.7 million for environmental sustainability and cleanup, $0.7 million for communications, and $0.5 million for compressor rentals. This was offset by reductions in costs including $3.1 million for workover expense, $1.0 million for chemicals and treating, $0.6 million for pumping unit repairs, $0.5 million for hot oil paraffin control, $0.2 million for supplies, and $0.2 million for insurance costs.
Gathering, transportation and processing costs. Our total GTP costs increased by $78,754 to $585,087 in 2025 from $506,333 in 2024 and slightly increased on a Boe basis to $0.08 in 2025 from $0.07 in 2024. The increase in costs was $107,637 in gas processing costs, offset by a reduction of $28,883 from NGL processing costs.
Ad valorem taxes. Our total ad valorem taxes decreased approximately $0.2 million to $7.9 million in 2025 from $8.1 million in 2024 and decreased on a Boe basis to $1.07 in 2025 from $1.12 in 2024. Ad valorem taxes decreased due to $1.2 million lower taxes in Yoakum County and $1.1 million for the reversal of the waste emissions charge ("WEC") that was recognized in 2024. This was offset by tax increases of $2.0 million in Andrews County, primarily from properties acquired in the Lime Rock Acquisition, and $0.1 million in Ector County.
Oil and natural gas production taxes. Oil and natural gas production taxes as a percentage of oil and natural gas sales increased to 4.66% in 2025 from 4.40% during 2024. In 2024, an accrual of $1.2 million was made for estimated severance tax refunds expected, which lowered the average rate for 2024. As of December 31, 2024, $0.9 million of the estimated refund was received. Excluding this refund, the overall average percentage of production taxes to oil and gas sales in 2024 was 4.7%, which is in line with the historical rates.
Depreciation, depletion and amortization. Our depreciation, depletion and amortization expense decreased approximately $2.3 million to $96.4 million in 2025 from $98.7 million in 2024, with $2.2 million of the decrease from reduced depletion on our oil and natural gas properties and $0.1 million from a reduction in amortization of financing lease assets. The $2.2 million decrease in depletion on oil and gas properties is due to a decreased average expense per unit of $12.86 in 2025 from $13.52 in 2024. Produced Boe increased by 201,422 in 2025; however, the reduced expense per unit resulted in lower depletion costs year over year. While average costs of property increased from the Lime Rock Acquisition and other capital well work, the asset impairment in 2025 resulted in a 5% increase in average estimated costs of property change year over year compared to an 11% increase in the amortization base (Boe).
Ceiling test impairment. During 2025, as a result of the lower oil prices impacting the present value of estimated future net revenues, the Company incurred a ceiling test impairment on its oil and natural gas properties of $108.8 million.
Asset retirement obligation accretion. Our asset retirement obligation (“ARO”) accretion increased by $109,957 to $1,490,255 in 2025 from $1,380,298 in 2024. The primary drivers in this increase of ARO accretion were the wells acquired in the Lime Rock Acquisition, which closed in March 2025, as well as new wells drilled in 2025. This was offset by wells plugged and abandoned and sold in 2025.
Operating lease expense. Our operating lease expense was consistent year over year, as the Company experienced no changes in its office leases.
General and administrative expenses (including share-based compensation). General and administrative expenses increased approximately $2.3 million to $31.9 million in 2025 from $29.6 million in 2024. The increase was primarily related to an increase of $2.5 million in salaries, wages, and bonuses, $0.6 million in share-based compensation, and $0.6 million in other professional fees. This was offset by reductions of $0.5 million in environmental sustainability costs, $0.5 million in legal fees, $0.4 million in additional costs capitalized, and $0.1 million in credit loss expense.
Interest income. Interest income decreased by $201,067 to $290,879 in 2025 from $491,946 in 2024. This was driven by a reduction of $184,997 in sweep accounts interest income and $16,070 for severance tax refund interest income.
Interest expense. Interest expense decreased approximately $2.9 million to $40.4 million in 2025 from $43.3 million in 2024. The decrease was primarily due to a 1% decrease in the average interest rate on the Company's long-term credit facility, which was 8.2% in 2025 and 9.2% in 2024, notwithstanding the increase in the Company's average amounts drawn on the same. Other reductions included lower deferred financing costs and interest on royalty suspense. This was offset by an increase in deferred cash payment accretion related to the Lime Rock Acquisition.
Gain (loss) on derivative contracts. During 2025, the Company recognized a gain on derivative contracts of approximately $31.7 million. During 2024, the Company incurred a loss on derivative contracts of approximately $2.4 million. For the derivative contract settlements, the Company recorded a realized gain of $5.5 million during 2025 and a realized loss of $5.2 million during 2024. The change of approximately $10.6 million in the realized derivative settlements was $14.1 million from realized oil derivative settlements and $(3.5) million from realized natural gas derivative settlements. For the marked-to-market contracts, the Company recorded an unrealized gain of $26.2 million during 2025 and an unrealized gain of $2.8 million during 2024. This change of approximately $23.4 million in unrealized derivatives was from $16.5 million in favorable derivative portfolio changes and futures pricing for marked-to-market oil derivative contracts, as well as $6.9 million favorable changes to the marked-to-market natural gas derivative contract balance.
Gain (loss) on disposal of assets. Gain (loss) on disposal of assets increased $356,707 to a gain of $446,400 in 2025 from a gain of $89,693 in 2024. The increase was primarily the result of an increase of $349,442 from the sale of leased vehicles and an increase of $7,265 from the sale of owned vehicles.
Other income. Other income increased $82,638 to $189,294 in 2025 from $106,656 in 2024. The increase was primarily due to income of $150,770 from a pipeline easement lease, offset by a reduction of $68,132 in income from the Company's charge card rebate program.
Benefit from (provision for) income taxes. The provision for income taxes changed to a benefit of $7,452,746 for 2025 from a provision of $20,440,954 for 2024, primarily driven by the change from pre-tax book income in 2024 to a pre-tax book loss in 2025, impacted by the ceiling test impairment recognized in 2025.
Net income (loss). The Company recognized a net loss of $34,731,199 in 2025 compared to net income of $67,470,314 in 2024. The decrease in income associated with operations was due to the reduction in commodity pricing, which reduced revenues as well as led to the ceiling test impairment recognized. Lessening this impact was the gain on derivative contracts, which was positive in terms of both unrealized and realized gains.
The following table sets forth selected operating data for the periods indicated:
Lease operating expenses. Our total lease operating expenses (“LOE”) increased approximately $8.1 million to $78.3 million in 2024 from $70.2 million in 2023 and increased slightly on a Boe basis to $10.89 in 2024 from $10.61 in 2023. These per Boe amounts are calculated by dividing our total LOE by our total volume sold, in Boe. LOE increased due to the full year of expenses from the assets acquired with the Founders Acquisition (closed in August 2023) which contributed to a 9% increase in production of 577,733 Boe year-over-year.Boe. Specifically, the Company experienced increases of $4.1 million for chemicals and treating, $1.8 million for electrical/utilities costs, $0.6 million for pumping unit repairs, $0.6 million for other employee costs, $0.4 million for environmental sustainability, and $0.4 million for insurance costs.
Gathering, transportation and processing costs. Our total GTP costs increased by $48,760 to $506,333 in 2024 from $457,573 in 2023 and remained unchanged on a Boe basis towith $0.07 in 2024 fromand $0.07 in 2023. The increase in costs was $30,298 from NGL processing costs and $18,462 from gas processing costs.
Operating lease expense. Our operating lease expense increased by $158,561 to $700,362 in 2024 from $541,801 in 2023 due to additional office space leased in The Woodlands office, which was substantially completed in September 2023.
Gain (loss) on disposal of assets. Gain (loss) on disposal of assets increased $176,821 to a gain of $89,693 in 2024 from a loss of $87,128 in 2023. The increase was primarily the result of the Company recognizing a gain on disposal of assets primarily from selling multiple leased vehicles during 2024, ascompared opposed towith a loss on disposal of assets primarily from selling multiple company owned vehicles during 2023.
Year Ended December 31, 2023 Compared to Year Ended December 31, 2022
Oil sales. Oil sales increased approximately $28.0 million to $349.0 million in 2023 from $321.1 million in 2022. The oil sales increased by a volume variance of approximately $103.9 million from a significant increase in sales volumes to 4,579,942 barrels of oil in 2023 from 3,459,840 barrels of oil in 2022, with approximately 19% of the increase in oil volumes related to the Founders Acquisition. Other impacts to revenue volumes include organic growth from workovers, new drills, and other capital expenditures, offset by divestitures completed. The volume variance was offset by a negative price variance of approximately $76.0 million from a decrease in the average realized per barrel oil price to $76.21 in 2023 from $92.80 in 2022.
Natural gas sales. Natural gas sales decreased approximately $18.4 million to $0.3 million in 2023 from $18.7 million in 2022. The natural gas sales decreased by a negative price variance of approximately $28.6 million, as the average realized per Mcf gas price decreased to $0.05 in 2023 from $4.57 in 2022. The significant reduction in realized natural gas prices was driven by a lower market index price. In 2023, the average gross realized price for natural gas was $1.67 per Mcf, and the average fees per Mcf were $(1.62), bringing the net average price to $0.05 per Mcf. In 2022, the average gross realized price for natural gas was $6.32 per Mcf, and the average fees per Mcf were $(1.75), bringing the net average price to $4.57 per Mcf. This was partially offset by a volume variance of approximately $10.3 million as the volume increased to 6,339,158 Mcf in 2023 from 4,088,642 Mcf in 2022.
NGL sales. NGL sales increased approximately $4.2 million to $11.7 million in 2023 from $7.5 million in 2022. NGL sales had a volume variance of approximately $12.2 million, as volumes were 976,852 barrels of NGLs in 2023 compared to 371,329 barrels in 2022. The volumes increase was primarily due to the Company's change in reporting presentation for its natural gas productions, which were presented on a three-stream basis basis beginning July 1, 2022. Offsetting this increase to sales was a negative price variance of approximately $8.0 million, as the average realized price per barrel of NGLs was $11.95 in 2023 compared to $20.18 in 2022.
Lease operating expenses. Our total lease operating expenses (“LOE”) increased approximately $22.5 million to $70.2 million in 2023 from $47.7 million in 2022 and increased slightly on a Boe basis to $10.61 in 2023 from $10.57 in 2022. These per Boe amounts are calculated by dividing our total LOE by our total volume sold, in Boe. LOE increased primarily due to a 47% increase in production of 2,100,711 Boe year-over-year. Specifically, the following cost increases accounted for the majority of the increase in LOE: $7.5 million in LOE workover costs, $4.2 million in salaries and wages, $2.5 million in electrical/utilities costs, $1.6 million in equipment rental/services $1.3 million in supplies/materials, $1.2 million in contract services, and $1.0 million in chemicals/treating costs.
Gathering, transportation and processing costs. Our total GTP costs decreased by $1,372,451 to $457,573 in 2023 from $1,830,024 in 2022 and decreased slightly on a Boe basis to $0.07 in 2023 from $0.41 in 2022. In May 2022, a contract update with one of our largest natural gas processors altered the point of control of gas resulting in a change to the recording of those fees from expense to a netted reduction to revenues. There remains only one contract with a natural gas processing entity in place where point of control of gas dictates requiring the fees be recorded as an expense.
Ad valorem taxes. Our total ad valorem taxes increased approximately $2.1 million to $6.8 million in 2023 from $4.7 million in 2022 and decreased on a Boe basis to $1.02 in 2023 from $1.04 in 2022. Ad valorem taxes increased due to a full year of taxes for the properties within counties acquired in the Stronghold Acquisition (i.e. Crane County) as well as a partial year of taxes for properties within Ector County, acquired in the Founders Acquisition. Additional increases were primarily in Yoakum County and Andrews County.
Oil and natural gas production taxes. Oil and natural gas production taxes as a percentage of oil and natural gas sales increased to 5.02% in 2023 from 4.93% during 2022. Overall, the percentage was consistent year over year.
Depreciation, depletion and amortization. Our depreciation, depletion and amortization expense increased approximately $32.9 million to $88.6 million in 2023 from $55.7 million in 2022 due to an increase in our total estimated costs of property, resulting in a higher depletion expense per unit, as well as an increase of 2,100,711 in Boe produced. Our average depreciation, depletion and amortization per Boe increased to $13.40 per Boe during 2023 from $12.35 per Boe during 2022.
Asset retirement obligation accretion. Our asset retirement obligation (“ARO”) accretion increased by $442,254 to $1,425,686 in 2023 from $983,432 in 2022. This was due to a full year of accretion on the assets acquired in the Stronghold Acquisition, a partial year of accretion on the assets acquired in the Founders Acquisition, and new wells drilled during 2023, offset by wells sold during 2023.
Operating lease expense. Our operating lease expense increased by $177,893 to $541,801 in 2023 from $363,908 in 2022 due to a full year of the Midland office lease additional space, which was amended effective October 1, 2022, as well as a quarter's impact of The Woodlands office lease additional space, which was substantially completed on September 27, 2023.
General and administrative expenses (including share-based compensation). General and administrative expenses increased approximately $2.1 million to $29.2 million in 2023 from $27.1 million in 2022. The increase was primarily related to a $2.2 million increase in salaries, wages, and bonuses, a $1.7 million increase in share-based compensation, $0.6 million in additional legal fees, $0.5 million in higher software costs, $0.1 million in engineering costs, and $0.1 million in accounting, tax, and audit fees. These cost increases were partially offset by a reduction of $2.0 million in transaction costs and a $0.6 million reduction in G&A costs from the Employee Retention Tax Credit.
Interest income. Interest income increased by $257,151 to $257,155 in 2023 from $4 in 2022. The 2023 interest income consisted of $226,315 from depositing excess cash balances in bank sweep accounts beginning in May 2023, $29,042 from interest earned on the Employee Retention Tax Credit, and $1,798 from interest earned on the escrow deposit made for the Founders Acquisition.
Interest expense. Interest expense increased approximately $20.8 million to $43.9 million in 2023 from $23.2 million in 2022. The increase was the result of a combination of higher interest rates, with a weighted average interest rate of 8.8% in 2023 and 5.8% in 2022, and having higher amounts outstanding on our credit facility throughout 2023, with a weighted average daily debt of approximately $422.5 million in 2023 compared to approximately $344.0 million in 2022.
Gain (loss) on derivative contracts. During 2023, the Company incurred a gain on derivative contracts of approximately $2.8 million. During 2022, the Company recorded a loss on derivative contracts of approximately $21.5 million. For the derivative contract settlements, the Company recorded a realized loss of $9.1 million during 2023 and a realized loss of $62.5 million during 2022. The decrease of $53.4 million in the realized loss was $50.5 million from realized oil derivative settlements and $2.9 million from realized natural gas derivative settlements. For the marked-to-market contracts, the Company recorded an unrealized gain of $11.9 million during 2023 and an unrealized gain of $41.0 million during 2022. This change of $29.1 million in unrealized derivatives was from $31.1 million in favorable derivative portfolio changes and futures pricing for marked-to-market oil derivative contracts, offset by $1.9 million unfavorable changes to the marked-to-market natural gas derivative contract balance.
Loss on disposal of assets. During 2023, the Company recognized a loss on disposal of assets of $87,128 from selling multiple company owned vehicles.
Other income. During 2023, the Company's other income of $198,935 primarily resulted from the termination of The Woodlands office operating lease as of May 31, 2023, along with a bank rebate related to the use of a vendor payment program.
What changed in the latest 10-Q
Risk Factors
We are subject to certain risks and hazards due to the nature of the business activities we conduct. For a discussion of these risks, see “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2025 as filed with the SEC. We may experience additional risks and uncertainties not currently known to us. Further, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect us. Any such risks may materially and adversely affect our business, financial condition, cash flows, and results of operations.
No wording changes found in this section.
Full comparison: every changed paragraph (0)
Management's Discussion & Analysis (MD&A)
New heading “Commodity Price Environment and Hedging Impact”
New heading “Production Costs for the Three Months Ended June 30, 2026 and 2025”
New heading “Production Costs for the Six Months Ended June 30, 2026 and 2025”
New heading “Other Costs and Operating Expenses for the Three Months Ended June 30, 2026 and 2025”
New heading “Other Income (Expense) for the Six Months Ended June 30, 2026 and 2025”
New heading “Benefit from (Provision for) Income Taxes: for the Three Months Ended June 30, 2026 and 2025”
New heading “Benefit from (Provision for) Income Taxes: for the Six Months Ended June 30, 2026 and 2025”
New heading “Equity Offering”
Removed heading “Production Costs for the Three Months Ended March 31, 2026 and 2025”
Largest changes
“Interest expense. Interest expense decreased by approximately $0.9 million from $9.5 million to $8.6 million, primarily due to a decrease in the amortization of deferred financing costs as a result of the amendment and restatement of the credit agreement in the second quarter of 2025. Interest on the Credit Facility decreased due to lower interest rates, with a weighted average annual interest rate of 7.3% during the three months ended March 31, 2026 compared to 8.3% during the three months ended March 31, 2025. …”see in full comparison
“Interest expense. Interest expense decreased by approximately $4.3 million from $21.3 million to $17.0 million, primarily due to lower interest rates, with a weighted average annual interest rate of 7.3% during the six months ended June 30, 2026 compared to 8.4% during the six months ended June 30, 2025, as well as lower amounts outstanding on our Credit Facility, with a weighted average daily debt of approximately $422.7 million during the six months ended June 30, 2026 compared to approximately $425.0 million during the six months ended June 30, 2025. …”see in full comparison
“The Company's underlying operating performance and liquidity remained solid during the quarter, and the non-cash charges we incurred did not affect compliance with the financial covenants under the Company’s Credit Facility. Core operating results remain resilient, supported by disciplined capital allocation, ongoing cost improvements, and a hedge position designed to provide cash flow stability in a volatile pricing environment.”see in full comparison
“Benefit from (Provision for) Income Taxes: for the Three Months Ended June 30, 2026 and 2025”see in full comparison
“Benefit from (Provision for) Income Taxes: for the Six Months Ended June 30, 2026 and 2025”see in full comparison
“Other Costs and Operating Expenses for the Three Months Ended June 30, 2026 and 2025”see in full comparison
Full comparison: every changed paragraph (85)
During the second quarter of 2026, the Company drilled a total of seven wells and completed a total of four wells. Specifically, in the Northwest Shelf the Company drilled and completed one 1.5-mile horizontal well and one 1-mile horizontal well in Yoakum County, with a working interest of approximately 98% and 100%, respectively. In the Central Basin Platform, the Company drilled and completed one 1.5-mile horizontal well in Andrews County with a working interest of approximately 99%, and one 1.5-mile horizontal well in Crane County with a working interest of of approximately 96%. The latter of these two wells, while completed, was not put on pump until the third quarter of 2026 and did not contribute significant volumes in the second quarter of 2026. Also in Crane County, the Company drilled three 2-mile horizontal wells, each with a working interest of 100%, and was in the process of drilling one SWD well. The three 2-mile horizontal wells represent the first laterals of this length drilled by the Company in an area that has been historically developed with vertical wells. All four of these wells are to be completed during the third quarter of 2026.
As a result of the Company's drilling and operational activities, total production for the three months ended March 31, 2026 increased 5%year over year to 1.74 million Boe. The increase in production was driven by contributions from the Lime Rock acquisition and new operated development, partially offset by natural production declines in legacy assets.
Operationally, the Company delivered solid field level performance during the quarter. For the three months ended March 31, 2026, Ring generated Exploration and Production segment profit of $49.7 million, despite a challenging commodity price environment, particularly for natural gas. These results reflect continued cost discipline, efficient execution of the development program, and the benefits of the Company’s oil weighted asset base.
At the Total Company level, reported results were materially impacted by certain non-cash items. The Company recorded a net loss of $220.6 million for the quarter, driven primarily by a $162.1 million full cost ceiling test impairment and $77.0 million unrealized derivative mark to market adjustments resulting from changes in forward commodity prices.
The Company's underlying operating performance and liquidity remained solid during the quarter, and the non-cash charges we incurred did not affect compliance with the financial covenants under the Company’s Credit Facility. Core operating results remain resilient, supported by disciplined capital allocation, ongoing cost improvements, and a hedge position designed to provide cash flow stability in a volatile pricing environment.
Our financial results are significantly affected by crude oil and natural gas prices. Commodity prices are influenced by numerous factors beyond our control, including changes in domestic and global supply and demand, geopolitical events, macroeconomic conditions, transportation and processing constraints, and other market factors. As a result, commodity prices have been volatile and are expected to remain volatile.
During the second quarter of 2026, crude oil prices remained elevated through much of the quarter before declining toward quarter-end. In addition, natural gas prices in the Permian Basin continued to be adversely affected by regional takeaway constraints and elevated processing and transportation costs. These conditions adversely affected realized natural gas prices during the quarter. The Company continues to monitor market conditions and evaluate available alternatives with respect to the marketing of its production and commodity price risk management activities.
Future changes in commodity prices may materially affect the Company's financial condition, results of operations and cash flows.
Commodity Price Environment and Hedging Impact
During the second quarter of 2026, crude oil prices increased meaningfully relative to the levels when a significant portion of the Company's hedge portfolio was established. As a result, while the Company benefited from higher oil prices, realized settlements on crude oil derivative contracts reduced realized pricing and cash flow relative to unhedged market prices. During the quarter, the Company recognized realized losses on crude oil derivative contracts of approximately $19.6 million.
Our hedge program is largely required under our Credit Facility and was designed to protect cash flows, support liquidity, and provide greater certainty around capital allocation and balance sheet objectives. While our hedge positions reduced participation in higher oil prices during the quarter, they also provide downside protection in a volatile commodity price environment.
The Company continues to evaluate its commodity price risk management strategy and hedge profile in light of requirements under the Credit Facility, market conditions, balance sheet strength, capital allocation priorities, and anticipated commodity price exposure.
The Company’s financial results are highly sensitive to changes in commodity prices, and during the first quarter of 2026, oil and natural gas markets experienced significant volatility driven by different factors. In the Permian Basin, natural gas prices remained under severe pressure due to regional takeaway constraints and elevated processing and transportation costs, while crude oil prices were influenced by broader global events late in the quarter.
As a result of the sustained weakness in Permian natural gas markets, the Company realized negative net natural gas prices during the quarter, as processing and transportation fees exceeded gross realized sales prices, which adversely impacted reported revenues. In response, management continues to pursue commercially reasonable mitigations, including basis hedging, marketing optimization, and disciplined capital allocation, while maintaining a strong focus on preserving liquidity and long term value.
Separately, late first quarter 2026 geopolitical developments affected global crude oil markets, resulting in a sharp increase in crude oil prices. These late quarter price movements adversely impacted the fair value of the Company’s outstanding crude oil derivative positions and contributed to the unrealized derivative losses recorded during the quarter. By contrast, the SEC full cost ceiling test is based on an unweighted arithmetic average of first day of the month prices for the preceding twelve months, and accordingly, these late quarter oil price movements had limited impact on the twelve month average prices used in the Company’s March 31, 2026 ceiling test calculation.
Accordingly, because the ceiling test is based on historical twelve month average pricing, it does not fully reflect significant changes in commodity prices that occur late in a reporting period.
As a result of the ceiling test, driven by a decrease in the twelve month average commodity price over the past few months, the Company recognized a non-cash impairment charge of $162.1 million for the three months ended March 31, 2026. Depending on market conditions, the Company's discounted future net revenues could continue to decline, which may trigger additional non-cash impairments recognized in future periods. Estimating potential future non-cash impairments is complex due to numerous factors affecting the ceiling test calculation, including but not limited to future prices, operating costs, upward or downward reserve revisions, reserve additions, and tax attributes. The amount of any additional non-cash impairment, if any, is not estimable at this time given the uncertainty of these factors.
No impairment was recorded for the three months ended June 30, 2026. For the six months ended June 30, 2026, the Company recorded a non-cash impairment charge of $162.1 million as a result of lower oil prices impacting the present value of estimated future net revenues.
Oil, Natural Gas, and Natural Gas Liquids Revenues for the Three Months Ended MarchJune 31,30, 2026 and 2025
Oil sales. Oil sales decreasedincreased approximately $0.3$27.4 million from $76.5$82.8 million to $76.2$110.2 million, withdriven by a price variance of $(1.6)$37.8 million from aan decreaseincrease in the average realized price per barrel from $70.40$62.69 to $68.97$95.45 as a result of higher oil commodity prices. This was offset by a volume variance of $1.3$(10.4) million duefrom toa an increasedecrease in sales volume from 1,086,6941,320,508 barrels to 1,104,8231,154,147 barrels. The increasedecrease in volume of 18,129(166,361) barrels consisted of two components: an increase in volumes of 143,132 was due to the Lime Rock acquisition, and a decrease of 125,003 was attributed to natural production declines infrom theour legacy assets. The Company's drilling and completion spend was 43% lower in the months that affected production for the first three months of 2026 compared to the same months that affected production in the first three months of 2025. This resulted in less offsets to declining production in the legacy assets. The decreased average realized price per barrel was primarily the result of lower oil prices.
Natural gas sales. Natural gas sales decreased approximately $4.0$6.9 million from a negative $0.3$2.2 million to a negative $4.3$9.2 million. TheOur natural gas sales volumevolumes increased from 1,615,1961,703,808 Mcf to 1,689,5121,764,659 Mcf, and the average realized price per Mcf decreased from $(0.191.31) to $(2.545.20). Of the increase in volume of 74,31660,851 Mcf, an increase of 146,52230,268 Mcf was duefrom tothe wells acquired and drilled in the Lime Rock acquisition,acquisition offsetarea byand aan decreaseincrease of 72,20630,583 forMcf ourwas attributable to legacy assets. The price decrease was driven by lowerdepressed market conditions. The realized revenue pricing includesincluded the impact of gas plant processing fees that were netted from revenue. For the three months ended MarchJune 31,30, 2026, gross revenues were $(0.483.01) per Mcf and fees were $(2.062.19) per Mcf, compared to gross revenues of $1.86$0.87 per Mcf and fees of $(2.052.18) per Mcf for the three months ended MarchJune 31,30, 2025. This resulted in a net realized price of $(2.54) for the three months ended March 31, 2026 compared to $(0.195.20) per Mcf for the three months ended MarchJune 31,30, 2026 compared to $(1.31) per Mcf for the three months ended June 30, 2025.
Natural gas liquids sales. NGL sales decreasedincreased approximately $1.1$1.6 million from $2.9$2.1 million to $1.8$3.7 million. NGL sales volumes for the three months ended MarchJune 31,30, 2026 were 355,173370,819 barrels compared to 299,366333,374 barrels for the comparable period in 2025. Of the increase in volume of 55,80737,445 barrels, an17,360 increasebarrels ofwere 40,450 was dueattributable to wells acquired and drilled in the Lime Rock acquisition,acquisition area, and an increase of 15,35720,085 barrels was fromattributable to our legacy assets.assets in correlation with gas sales. The average realized price per barrel decreasedof byNGLs $4.69was to $4.96$9.96 for the three months ended MarchJune 31,30, 2026 compared to $9.65$6.19 for the three months ended MarchJune 31,30, 2025, due to lowerstronger prices.market conditions. Specifically, the gross realized price per NGL barrel was $17.42$22.38 and the average fees per barrel waswere $(12.4612.42), resulting in a net realized price of $4.96$9.96 for the three months ended MarchJune 31,30, 2026, while the gross realized price per NGL barrel was $22.64$19.02 and the average fees per barrel waswere $(12.9912.83), resulting in a net realized price of $9.65$6.19 for the same period in 2025.
Production Costs for the Three Months Ended March 31, 2026 and 2025
Lease operating expenses. Our total LOE decreased from $19.7 million to $18.1 million and LOE per Boe decreased from $11.89 to $10.41. Total LOE decreased despite a 5% increase in production of 86,322 Boe, as a result of the additional production and well count from the Lime Rock acquisition as well as new wells drilled and completed in our development program. The primary cost drivers for the period were decreases in contract and lease services of $1.0 million, chemicals of $0.9 million, equipment rentals of $0.5 million, location repairs and environmental sustainability of $0.3 million, non-op of $0.2 million, and contract pumping services of $0.1 million. This was offset by increases in LOE costs from salt water disposal of $0.5 million, salaries of $0.4 million, and workovers of $0.4 million.
Gathering, transportation and processing costs. Our total GTP decreased $86,563 from $203,612 to $117,049 and decreased on a per Boe basis from $0.12 to $0.07. The decrease in GTP costs was due to a reduction of $77,561 in gas processing costs and a reduction of $9,002 in NGL processing costs.
Ad valorem taxes. Our total ad valorem taxes increased $0.7 million from $1.5 million to $2.2 million and increased on a per Boe basis from $0.93 to $1.26. An increase in ad valorem taxes of $0.5 million was from the reversal made in the first quarter of 2025 for the 2024 methane tax accrual for the waste emissions charge ("WEC"), which was repealed by Congress on March 14, 2025, with no similar reversal made in 2026. There was also an increase of $0.6 million in Andrews County due primarily to the Lime Rock acquisition. Offsetting these increases was a decrease in the Yoakum County estimates of approximately $0.4 million.
Oil and natural gas production taxes. Oil and natural gas production taxes as a percentage of oil and natural gas sales were 4.53% for the three months ended March 31, 2025 and increased to 4.82% for the three months ended March 31, 2026. The overall average percentage of production taxes to oil and gas sales was consistent period over period.
OtherOil, CostsNatural Gas, and OperatingNatural ExpensesGas Liquids Revenues for the ThreeSix Months Ended MarchJune 31,30, 2026 and 2025
(1) Boe is calculated using six Mcf of natural gas as the equivalent of one barrel of oil.
Oil sales. Oil sales increased approximately $27.1 million from $159.3 million to $186.4 million, with a price variance of $36.9 million from an increase in the average realized price per barrel from $66.17 to $82.50 as a result of higher oil commodity prices. This was offset by a volume variance of $(9.8) million due to a decrease in sales volume from 2,407,202 barrels to 2,258,970 barrels. The decrease in volume of 148,232 barrels was impacted by a decrease of 274,977 attributable to natural production declines in the legacy assets, offset by an increase in volumes of 126,745 from wells acquired and drilled in the Lime Rock acquisition area.
Natural gas sales. Natural gas sales decreased approximately $10.9 million from a negative $2.5 million to a negative $13.5 million. The natural gas sales volume increased from 3,319,004 Mcf to 3,454,171 Mcf, and the average realized price per Mcf decreased from $(0.77) to $(3.90). Of the increase in volume of 135,167 Mcf, an increase of 176,790 was due to wells acquired and drilled in the Lime Rock acquisition area, offset by a decrease of 41,623 for our legacy assets. The price decrease was driven by lower market conditions. The realized revenue pricing includes the impact of gas plant processing fees that were netted from revenue. For the six months ended June 30, 2026, gross revenues were $(1.77) per Mcf and fees were $(2.13) per Mcf, compared to gross revenues of $1.35 per Mcf and fees of $(2.12) per Mcf for the six months ended June 30, 2025. This resulted in a net realized price of $(3.90) for the six months ended June 30, 2026 compared to $(0.77) per Mcf for the six months ended June 30, 2025.
Natural gas liquids sales. NGL sales increased approximately $0.5 million from $5.0 million to $5.5 million. NGL sales volumes for the six months ended June 30, 2026 were 725,992 barrels compared to 632,740 barrels for the comparable period in 2025. Of the increase in volume of 93,252 barrels, an increase of 57,810 was due to wells acquired and drilled in the Lime Rock acquisition area, and an increase of 35,442 was from legacy assets. The average realized price per barrel decreased by $0.31 to $7.52 for the six months ended June 30, 2026 compared to $7.83 for the six months ended June 30, 2025, due to lower prices. Specifically, the gross realized price per NGL barrel was $19.95 and the average fees per barrel was $(12.43), resulting in a net realized price of $7.52 for the six months ended June 30, 2026, while the gross realized price per barrel was $20.74 and the average fees per barrel was $(12.91), resulting in a net realized price of $7.83 for the same period in 2025.
Production Costs for the Three Months Ended June 30, 2026 and 2025
Lease operating expenses. Our total lease operating expenses (“LOE”) decreased from $20.2 million to $18.4 million and decreased on a per Boe basis from $10.45 to $10.12. These per Boe amounts are calculated by dividing our total lease operating expenses by our total volume sold, in Boe. Total LOE decreased primarily due to a 6% decrease in production of 118,774 Boe as well as targeted cost reductions. The primary cost drivers for the period were decreases of $0.9 million in electricity costs, $0.6 million in chemicals, $0.5 million in equipment rentals, and $0.3 million in pressure, vacuum, and hot oil truck costs, offset by increases of $0.3 million in workovers and $0.2 million in contract and lease services.
Gathering, transportation and processing costs. Our total gathering, transportation and processing costs (“GTP”) decreased from $133,809 to $101,902 and decreased slightly on a per Boe basis from $0.07 to $0.06. The decrease in GTP costs was due to a reduction of $40,353 in gas processing costs offset by an increase of $8,446 in NGL processing costs.
Ad valorem taxes. Our total ad valorem taxes increased from $1.6 million to $2.2 million and increased on a per Boe basis from $0.85 to $1.21. Of the $0.6 million increase in ad valorem taxes, $0.3 million was for Yoakum County tax estimates, $0.1 million was for Andrews County tax estimates, $0.1 million was for Crane County tax estimates, and $0.1 million was for Ector County tax estimates.
Oil and natural gas production taxes. Oil and natural gas production taxes as a percentage of oil and natural gas sales were 4.64% for the three months ended June 30, 2025 and increased to 4.82% for the three months ended June 30, 2026. Both percentages are in line with historical rates.
Production Costs for the Six Months Ended June 30, 2026 and 2025
Lease operating expenses. Our total LOE decreased from $39.9 million to $36.5 million and LOE per Boe decreased from $11.11 to $10.26. Total LOE decreased from targeted reductions in costs as well as a 1% decrease in production of 32,452 Boe. The primary cost drivers for the period were decreases in chemicals of $1.5 million, equipment rentals of $1.0 million, electricity costs of $0.9 million, contract and lease services of $0.8 million, pressure, vacuum, and hot oil truck costs of $0.5 million, non-operated costs of $0.4 million, and location repairs and environmental sustainability of $0.3 million. This was offset by increases in LOE costs from workovers of $0.7 million, salt water disposal of $0.7 million, salaries of $0.5 million, and compressor rentals of $0.1 million.
Gathering, transportation and processing costs. Our total GTP decreased $118,470 from $337,421 to $218,951 and decreased on a per Boe basis from $0.09 to $0.06. The decrease in GTP costs was primarily a result of a reduction in gas processing costs.
Ad valorem taxes. Our total ad valorem taxes increased $1.2 million from $3.2 million to $4.4 million and increased on a per Boe basis from $0.89 to $1.24. An increase in ad valorem taxes of $0.5 million was from the reversal made in the first quarter of 2025 for the 2024 methane tax accrual for the waste emissions charge ("WEC"), which was repealed by Congress on March 14, 2025, with no similar reversal made in 2026. There was also an increase of $0.6 million in Andrews County due primarily to the Lime Rock acquisition as well as a $0.1 million increase from Crane County tax estimates. Offsetting these increases was a decrease in the Yoakum County tax estimates of approximately $0.1 million.
Oil and natural gas production taxes. Oil and natural gas production taxes as a percentage of oil and natural gas sales were 4.59% for the six months ended June 30, 2025 and increased to 4.82% for the six months ended June 30, 2026. The overall average percentage of production taxes to oil and gas sales was consistent period over period.
Other Costs and Operating Expenses for the Three Months Ended June 30, 2026 and 2025
Depreciation, depletion and amortization. Our depreciation, depletion and amortization decreased approximately $1.2 million from $22.6$25.6 million to $21.4$20.1 million, with substantially$5.4 allmillion of the reduction from lower depletion. The decrease in depletion was primarilythe dueresult toof a price variance of $(2.33.8) million, fromdue to a lower depletion expenserate per Boe, duedriven toby a decrease in the total estimated costs of property from the impairment recognized in the last two quarters of 2025 and the first quarter of 2026, coupled with an increase in the amortization base.base Offsetting(total this,Boe). Also impacting the lower depletion hadwas a volume variance of approximately $1.2$(1.6) million from a increasedecrease of 86,322118,774 in Boe produced. Our average depreciation, depletion and amortization per Boe decreased from $13.66$13.19 per Boe to $12.29$11.06 per Boe.
Ceiling test impairment. As a result of the lowerhigher oil prices impacting the present value of estimated future net revenues, the Company incurreddid not incur a ceiling test impairment on its oil and natural gas properties during each of $162.1the million.three month periods presented.
Asset retirement obligation accretion. Our asset retirement obligation (“ARO”) accretion increased by $68,947 from $326,549$382,251 to $395,496 primarily$401,944 as a result of result of newly acquired and drilled wells, offset by those plugged and abandoned and sold.
General and administrative expense. General and administrative ("G&A") expense increased from $7.1 million to approximately $8.0 million. The approximate $0.8 million cost increase was primarily driven by an increase of $0.8 million in stock compensation, $0.2 million in other professional fees, and $0.1 million in meals and entertainment. These costs were offset by reductions of $0.3 million in salaries and bonuses.
General and administrative expense. G&A expense decreased approximately $1.2 million from $8.6 million to $7.4 million, with the $1.2 million cost decrease primarily due to a decrease of $0.6 million in salaries and bonuses, $0.5 million in additional costs capitalized, and a decrease of $0.1 million in insurance expense.
Other IncomeCosts (Expense)and Operating Expenses for the ThreeSix Months Ended MarchJune 31,30, 2026 and 2025
Depreciation, depletion and amortization. Our depreciation, depletion and amortization decreased approximately $6.7 million from $48.2 million to $41.5 million, with substantially all of the reduction from lower depletion. The decrease in depletion was primarily due to a price variance of $(6.1) million, from a lower depletion expense per Boe, due to reduction in the total estimated costs of property from the impairment recognized in the last two quarters of 2025 and the first quarter of 2026, coupled with an increase in the amortization base (total Boe). Adding to this was a volume variance of approximately $(0.4) million from a decrease of 32,452 in Boe produced. Our average depreciation, depletion and amortization per Boe decreased from $13.41 per Boe to $11.66 per Boe.
Ceiling test impairment. As a result of the lower oil prices impacting the present value of estimated future net revenues, the Company incurred a ceiling test impairment on its oil and natural gas properties of $162.1 million during the six months ended June 30, 2026.
Asset retirement obligation accretion. Our ARO accretion increased by $88,640 from $708,800 to $797,440 primarily due to additional ARO accretion associated with properties acquired in the Lime Rock Acquisition, as well as newly drilled wells, offset by those plugged and abandoned and sold.
Operating lease expense. Our operating lease expense costs were the same period over period.
General and administrative expense. G&A expense decreased approximately $0.4 million from $15.8 million to $15.4 million, with the $0.4 million cost decrease primarily due to a decrease of $0.9 million in salaries and bonuses, $0.5 million in additional costs capitalized, offset by an increase of $0.6 million in stock compensation, $0.3 million in other professional fees, and $0.1 million in allowance for credit losses.
Interest income. Interest income decreased $19,529 from $90,058 to $70,529, as a result of $41,747 in lower earnings on excess cash balances in bank sweep accounts, offset by an increase of $22,218 in severance tax interest receipts.
Interest expense. Interest expense decreased by approximately $0.9 million from $9.5 million to $8.6 million, primarily due to a decrease in the amortization of deferred financing costs as a result of the amendment and restatement of the credit agreement in the second quarter of 2025. Interest on the Credit Facility decreased due to lower interest rates, with a weighted average annual interest rate of 7.3% during the three months ended March 31, 2026 compared to 8.3% during the three months ended March 31, 2025. Offsetting this impact was higher amounts outstanding on our Credit Facility, with a weighted average daily debt of approximately $430.4 million during the three months ended March 31, 2026 compared to approximately $393.3 million during the three months ended March 31, 2025.
Gain (loss) on derivative contracts. We recorded a loss on derivative contracts of $82.2 million for the three months ended March 31, 2026 and a loss on derivative contracts of $0.9 million for the three months ended March 31, 2025. For the derivative contract settlements, we recorded a realized loss of $5.3 million for the three months ended March 31, 2026 compared with a realized loss of $0.6 million for the three months ended March 31, 2025. The change of $4.7 million in the realized derivative gain (loss) was primarily a result of less favorable settlements of crude oil derivative contracts during the current year. For the marked-to-market contracts, we recorded an unrealized loss of $77.0 million for the three months ended March 31, 2026 and an unrealized loss of $0.4 million for the three months ended March 31, 2025. This negative change in unrealized derivatives primarily reflects changes in the crude oil forward curve during the quarter, including a late quarter increase in forward prices, which reduced the fair value of the Company's outstanding crude oil derivative positions.
Gain (loss) on disposal of assets. The Company's gain on disposal of assets decreased by $124,610 from $124,610 to $— with $131,584 of the decrease from the sale of leased vehicles offset by $6,974 from selling owned vehicles.
Other income. Other income decreased $3,105 from $8,942 to $5,837 due to a reduction of $3,105 in income from the Company's charge card rebate program.
Benefit from (Provision for)Other Income Taxes:(Expense) for the Three Months Ended MarchJune 31,30, 2026 and 2025
REI insider buying and selling (Form 4)
Since 2026-04-11, insiders reported open-market purchases in 2 Form 4 filings (2 insiders, 1 trade date, 281,000 shares, about $339.0K) and open-market sales in 0 filings. Net open-market shares: 281,000 (purchases minus sales); net value about $339.0K.Totals add up every open-market (code P and S) line in those filings, using the prices reported in the filings. Awards, option exercises, tax withholding and gifts are listed below but not counted.
| Trade date | Insider | Transaction | Shares | Price | Value |
|---|---|---|---|---|---|
| 2026-06-15 | Mckinney Paul D. |
Open-market purchase | 50,000 | $1.19 | $59.5K |
| 2026-06-15 | Johl Sundip Singh |
Open-market purchase | 231,000 | $1.21 | $279.5K |
Well-known investors holding REI (13F)
| Investor | Quarter | Shares | Reported value | % of their 13F | Change vs prior quarter |
|---|---|---|---|---|---|
| Two Sigma Investments | 2026-06-30 | 8,047,045 | $8.7M | 0.01% | Added 33% |
| Renaissance Technologies | 2026-06-30 | 4,117,089 | $4.4M | 0.01% | Added 154% |
| Citadel Advisors (Ken Griffin) | 2026-06-30 | 738,183 | $1.1M | — | Sold out |
| Millennium Management (Israel Englander) | 2026-06-30 | 902,106 | $974.3K | 0.0% | Reduced 71% |
| Point72 Asset Management (Steve Cohen) | 2026-06-30 | 157,726 | $170.3K | 0.0% | Reduced 36% |
| Gotham Asset Management (Joel Greenblatt) | 2026-06-30 | 12,666 | $13.7K | 0.0% | New position |