EDGAR 10-K Filing

Company CIK: 1384195
Filing Year: 2025
Filename: 1384195_10-K_2025_0001628280-25-010585.json

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ITEM 1. BUSINESS
Item 1: Business
General
Ring Energy, Inc., a Nevada corporation (“Ring,” “Ring Energy,” the “Company,” “we,” “us,” “our,” or similar terms), is a growth oriented independent oil and natural gas exploration and production company based in The Woodlands, Texas engaged in oil and natural gas development, production, acquisition, and exploration activities currently focused in the Permian Basin of Texas. Our drilling operations target the oil and liquids rich producing formations in the Northwest Shelf and the Central Basin Platform, in the Permian Basin in Texas.
As of December 31, 2024, our leasehold acreage positions totaled 97,599 gross (80,919 net) acres and we held interests in 935 gross (763 net) producing wells. Proved reserves as of December 31, 2024 (based upon the report of our independent petroleum engineer of that date) were approximately 134.2 million Boe, of which we are the operator of approximately 99%. All of our properties are located in the Permian Basin and our proved reserves are oil-weighted, with approximately 60% consisting of oil, 19% consisting of natural gas, and 21% consisting of NGLs. Approximately 69% of the reserves are classified as PD and 31% are classified as PUD. Within the PD reserve category, 220 recompletion and re-activation opportunities are classified as PDNP and within the PUD reserve category, we have a total of 211 proved locations (27% horizontal and 73% vertical) based on the reserve report as of December 31, 2024. We believe our core leasehold in the Northwest Shelf and Central Basin Platform contain additional potential drilling locations.
2024 Highlights and Major Developments
•Achieved record full year production of 19,648 Boepd (68% oil), a year-over-year increase in total Boe of 9%
•Executed a phased drilling program in 2024 that included drilling 44.00 gross / 43.94 net operated wells consisting of 22.00 horizontal and 22.00 vertical wells (gross).
•Maintained our revolving credit facility borrowing base of $600 million
•Total proved reserves were 134.2 MMBoe at year-end 2024, which increased 4.4 MMBoe, or 3% from year-end 2023.
Lime Rock Purchase and Sale Agreement
On February 25, 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, entered into a purchase and sale agreement (the "Purchase Agreement"). The Purchase Agreement provides that the Company will acquire (the "Lime Rock Acquisition") interests in oil and gas leases and related property of Lime Rock located in the Central Basin Platform of Texas for a purchase price (the "Purchase Price") of approximately $90 million in cash with $80 million due at closing and $10 million due on the nine months anniversary of closing, and 7,388,799 shares of our common stock. The Purchase Price is subject to customary purchase price adjustments with an effective date of October 1, 2024. On February 26, 2025, in connection with the Purchase Agreement, the Company deposited $5.0 million in cash into a third party escrow account as a deposit pursuant to the Purchase Agreement, which will be credited against the Purchase Price upon the closing of the Lime Rock Acquisition.
Our Mission
Ring’s mission is to deliver competitive and sustainable returns to its shareholders by developing, acquiring, exploring for, and commercializing oil and natural gas resources that are vital to the world’s health and welfare.
Our Key Principles
Successfully achieving Ring’s mission requires a firm commitment to operating safely in a socially responsible and environmentally friendly manner. Key principles supporting Ring’s strategic vision are to:
•Ensure health, safety, and environmental excellence with a strong commitment to Ring’s employees and the communities in which we work and operate;
•Continue our focus on generating adjusted free cash flow to improve and build a sustainable financial foundation;
•Pursue rigorous capital discipline focused on Ring’s highest returning opportunities;
•Improve margins and drive value by targeting additional operating cost reductions and capital efficiencies; and
•Strengthen our balance sheet by paying down debt, divesting of non-core assets and becoming a peer leader in Debt/EBITDA metrics.
Our Business Strategy
Our business strategy is guided by the above key principles and implemented by pursuing the following five strategic objectives, which are foundational aspects of our culture and success.
Attract and retain highly qualified people - Achieving our mission is only possible through our employees. It is critical to have compensation, development, and human resource programs that attract, retain, and motivate the people we need to succeed.
Pursue operational excellence with a sense of urgency - We seek to deliver low cost, consistent, timely, and efficient execution of our drilling campaigns, work programs, and operations. We execute our operations in a safe and environmentally responsible manner, focus on reducing our emissions, applying advanced technologies, and continuously seeking ways to reduce our operating cash costs on a per barrel basis.
Invest in high-margin, high rate-of-return projects - We prioritize our work programs and allocate capital to the highest return opportunities in our inventory on an ongoing basis. This objective is key to profitably growing our production and reserve levels and generating the excess cash from operations.
Focus on generating adjusted free cash flow and strengthening our balance sheet - We seek to continuously reduce long-term debt using excess cash from operations and potentially through the sale of non-core assets. Continuing to generate adjusted free cash flow through a disciplined capital allocation program and reducing our operating and corporate costs are key components of this objective. Our capital program is funded by operational cash flow and we seek to balance our production and reserve growth with paying down debt. We believe that remaining focused and disciplined in this regard will lead to meaningful returns for our shareholders and provide additional financial flexibility to manage potential future swings in business cycles. Our commodity hedges are designed to help ensure the necessary cash flow to adhere to these plans while retaining the flexibility to participate in prevailing commodity markets.
Pursue strategic acquisitions that maintain or reduce our break-even costs - We actively pursue accretive acquisitions, mergers, and property dispositions in seeking to improve our margins, returns, and break-even costs. Financial strategies associated with these efforts focus on delivering competitive debt-adjusted per share returns. This objective is key to delivering competitive returns to our shareholders on a sustainable basis.
Primary Business Operations
We seek to rigorously manage our asset portfolio to optimize shareholder value over the long term. Refer to Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations, Drilling and Completion, for details of our 2024 operations.
Ring Energy’s Strengths
Our strengths include:
•High quality asset base in one of North America’s leading oil and gas producing regions characterized by relatively low declines and attractive margins;
•De-risked Permian Basin acreage position with multi-year drilling inventory of horizontal and vertical development potential;
•Concentrated acreage position with high degree of operational control;
•Experienced and proven management team with substantive technical and operational expertise;
•Operating control over most of our production and development activities; and
•Commitment to cost efficient operations, health, safety, protecting the environment, our employees, and the communities in which we work and operate.
Competitive Business Conditions
We operate in a highly competitive environment for acquiring properties, marketing oil and natural gas, and securing competent personnel. Some of our competitors possess and employ financial resources substantially greater than ours and some of our competitors employ more technical personnel. In addition, those companies may be able to pay more for producing oil and natural gas properties and exploratory prospects, and to evaluate, bid for, and purchase a greater number of properties and prospects than what our financial or technical resources permit. Our ability to acquire additional properties and to find and develop reserves in the future will depend on our ability to identify, evaluate, and select suitable properties and to consummate transactions in this highly competitive environment.
Marketing, Pricing, and Transportation
The actual price range of crude oil is largely established by major crude oil purchasers and commodities trading. Pricing for natural gas is based on regional supply and demand conditions. To this extent, we believe we receive oil and natural gas prices comparable to other producers in our areas of operation. We believe there is little risk in our ability to sell our production at prevailing prices. We view potential declines in oil and gas prices to a level which could render our current production uneconomical as our primary pricing risk.
We are presently committed to use the services of the existing gathering systems of the companies that purchase our natural gas production. This commitment is tied to existing natural gas purchase contracts associated with our production, which potentially gives such gathering companies certain short-term relative monopolistic powers to set gathering and transportation costs. Obtaining the services of an alternative gathering company is not currently realistic as it would require substantial additional costs (since an alternative gathering company would be required to lay new pipeline and/or obtain new rights of way to any lease from which we are selling production).
We are not subject to third-party gathering systems with respect to our oil production. Some of our oil production is sold through third-party pipelines that have no regional competition and all other oil production is transported by the oil purchaser by trucks with competitive trucking costs in the area.
Our oil is transported from the wellhead to tank batteries or delivery points through our flowlines or gathering systems. Purchasers of our oil take delivery (i) at a pipeline delivery point or (ii) at our tank batteries for transport by truck. Our natural gas is transported from the wellhead to the purchaser’s meter and pipeline interconnection point through our gathering systems. We have implemented a Leak Detection and Repair program, or LDAR, to locate and repair leaking components including valves, pumps, and connectors, in order to minimize the emission of fugitive volatile organic compounds and hazardous air pollutants. Our produced saltwater is generally moved by pipeline connected to our operated saltwater disposal wells or by truck to commercial disposal facilities.
Major Customers
We principally sell our oil and natural gas production to end users, marketers and other purchasers that have access to nearby pipeline facilities. In areas where there is no practical access to pipelines, oil is trucked to storage facilities.
For the year ended December 31, 2024, sales to three customers represented 88% of our oil, natural gas, and natural gas liquids revenues. As of December 31, 2024, accounts receivable from these three customers represented 86% of our total accounts receivable. Refer to the table below for the details of these percentages, respectively. We believe that the
loss of any of these purchasers would not materially impact our business because we could readily find other purchasers for our oil and natural gas.
For the Year Ended
As of
December 31, 2024
December 31, 2024
Percentage of Oil, Natural Gas, and Natural Gas Liquids Revenues
Percentage of accounts receivables from the sale of our Oil, Natural Gas and NGL production
Customer:
Phillips 66 Company ("Phillips")
61%
64%
Concord Energy LLC ("Concord") 14% 11%
LPC Crude III, LLC ("LPC") 13% 11%
Total of top three customers
88% 86%
Delivery Commitments
As of December 31, 2024, we were not committed to providing a fixed quantity of oil or natural gas under any existing contracts.
Commodity Hedging
We have an active commodity hedging program through which we seek to hedge a meaningful portion of our expected oil and gas production, thereby reducing our exposure to downside commodity prices and enabling us to protect cash flows to meet our debt obligations under our credit facility and secondarily to maintain liquidity to fund our capital expenditure needs.
Governmental Regulations
Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements of governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, can affect our profitability.
Regulation of Drilling and Production
The production of oil and natural gas is subject to regulation under a wide range of local, state, and federal statutes, rules, orders, and regulations. Federal, state, and local statutes and regulations require permits for drilling operations, drilling bonds, and reports concerning operations. Until recently, the trend in oil and natural gas regulation was to increase regulatory restrictions and limitations on such activities. Any changes in, or more stringent enforcement of, these laws and regulations may result in delays or restrictions in permitting or development of projects or more stringent or costly construction, drilling, water management, or completion activities or waste handling, storage, transport, remediation, or disposal emission or discharge requirements which could have a material adverse effect on the Company.
Currently, all of our operated properties are in Texas, which has regulations governing conservation matters, such as the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, Texas imposes a production or severance tax with respect to the production and sale of oil, natural gas, and NGLs within its jurisdictions.
The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
Regulation of Transportation of Oil
Sales of crude oil, natural gas, and NGLs are not currently regulated and are made at negotiated prices; however, Congress could reenact price controls in the future.
Our sales of crude oil are affected by the availability, terms, and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The Federal Energy Regulatory Commission, (“FERC”), regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors. Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by pro-rationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.
Regulation of Transportation and Sale of Natural Gas
Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”) and regulations issued under those Acts by FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.
Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.
We cannot accurately predict whether FERC’s actions have achieved the goal of increasing competition in markets in which our natural gas is sold. Therefore, we cannot provide any assurance that the less stringent regulatory approach established by FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.
Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in Texas will not affect our operations in any way that is of material difference from those of our competitors.
Environmental Compliance and Risks
Our oil and natural gas exploration, development, and production operations are subject to numerous stringent federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. At the federal level, among the more significant laws that may affect our business and the oil and natural gas industry generally are: the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”); the Oil Pollution Act of 1990 (“OPA”); the Resource Conservation and Recovery Act (“RCRA”); the Clean Air Act (“CAA”); Federal Water Pollution Control Act of 1972, or the Clean Water Act (“CWA”); and the Safe Drinking Water Act of 1974 (“SDWA”). These federal laws are administered by the United States Environmental Protection Agency (“EPA”). Generally, these laws (i) regulate air and water quality, impose limitations on
the discharge of pollutants and establish standards for the handling of solid and hazardous wastes; (ii) subject our operations to certain permitting and registration requirements; (iii) require remedial measures to mitigate pollution from former or ongoing operations; and (iv) may result in the assessment of administrative, civil and criminal penalties for failure to comply with such laws. In addition, there is environmental regulation of oil and gas production by state and local governments in the jurisdictions where we operate. As described below, there are various regulations issued by the EPA and other governmental agencies pursuant to these federal statutes that govern our operations.
In Texas, specific oil and natural gas regulations apply to oil and natural gas operations, including the drilling, completion and operations of wells, and the disposal of waste oil and saltwater. There are also procedures incident to the plugging and abandonment of dry holes or other non-operational wells, all as governed by the applicable governing state agency.
At the federal level, among the more significant laws and regulations that may affect our business and the oil and natural gas industry are:
Hazardous Substances and Wastes
CERCLA, also known as the Superfund Law, and analogous state laws impose liability on certain classes of persons, known as “potentially responsible parties,” for the disposal or release of a regulated hazardous substance into the environment. These potentially responsible parties include (1) the current owners and operators of a facility, (2) the past owners and operators of a facility at the time the disposal or release of a hazardous substance occurred, (3) parties that arranged for the offsite disposal or treatment of a hazardous substance, and (4) transporters of hazardous substances to off-site disposal or treatment facilities. While petroleum and NGLs are not designated as a “hazardous substance” under CERCLA, other chemicals used in or generated by our operations may be regulated as hazardous substances. Potentially responsible parties under CERCLA may be subject to strict, joint and several liability for the costs of investigating and cleaning up environmental contamination, for damages to natural resources, and for the costs of certain health studies. In addition to statutory liability under CERCLA, common law claims for personal injury or property damage can also be brought by neighboring landowners and other third parties related to contaminated sites.
RCRA, and comparable state statutes and their implementing regulations, regulate the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and solid (non-hazardous) wastes. Under a delegation of authority from the EPA, most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Federal and state regulatory agencies can seek to impose administrative, civil, and criminal penalties for alleged non-compliance with RCRA and analogous state requirements. Certain wastes associated with the production of oil and natural gas, as well as certain types of petroleum-contaminated media and debris, are excluded from regulation as hazardous waste under Subtitle C of RCRA. These wastes, instead, are regulated as solid waste (i.e. non-hazardous waste) under the less stringent provisions of Subtitle D of RCRA. It is possible, however, that certain wastes now classified as non-hazardous could be classified as hazardous wastes in the future and therefore be subject to more rigorous and costly disposal requirements. Legislation has been proposed from time to time in Congress to regulate certain oil and natural gas wastes as hazardous waste under RCRA. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.
Under CERCLA, RCRA and analogous state laws, we could be required to remove or remediate environmental impacts on properties we currently lease or formerly owned or leased (including hazardous substances or wastes disposed of or released by prior owners or operators), to clean up contaminated off-site disposal facilities where our wastes have come to be located or to implement remedial measures to prevent or mitigate future contamination. Compliance with these laws may constitute a significant cost and effort for us. No specific accounting for environmental compliance has been maintained or projected by us at this time.
Air Emissions
Our operations are subject to the CAA and comparable state and local laws and regulations, which regulate emissions of air pollutants from various sources and mandate certain permitting, monitoring, recordkeeping, and reporting requirements. The CAA and its implementing regulations may require that we obtain permits prior to the construction, modification, or operation of certain projects or facilities expected to produce or increase air emissions above certain threshold levels and strictly comply with those permits, including emissions and operational limitations. These permits may require us to install emission control technologies to limit emissions, which can impose significant costs on our business.
In November 2021, the EPA issued a proposed rule under the CAA’s New Source Performance Standards, known as Subpart OOOOa, intended to reduce methane emissions from new and existing oil and gas sources. The proposed rule sought to make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the CAA (including intermittent vent pneumatic controllers, associated gas, and liquids unloading facilities). In addition, the proposed rule sought to establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by the EPA. In November 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule. Among other things, the November 2022 supplemental proposed rule sought to remove an emissions monitoring exemption for small wellhead-only sites and creates a new third-party monitoring program to flag large emissions events, referred to in the proposed rule as “super emitters.” In December 2023, the EPA announced a final rule, which, among other things, requires the phase out of routine flaring of natural gas from newly constructed wells (with some exceptions) and routine leak monitoring at all well sites and compressor stations. Notably, the EPA updated the applicability date for Subparts OOOOb and OOOOc to December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with later compliance deadlines under state plans. The final rule gave states until March 2026 to develop and submit their plans for reducing methane emissions from existing sources. The final emissions guidelines under Subpart OOOOc provides until 2029 for existing sources to comply. As a result of these regulatory changes, the scope of any final air emissions regulations or the costs for complying with such regulations are uncertain. We may incur costs as necessary to remain in compliance with these regulations. Obtaining or renewing permits also has the potential to delay the development of oil and natural gas projects. Federal and state regulatory agencies can impose administrative, civil and criminal penalties and seek injunctive relief for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations.
In August 2022, the Inflation Reduction Act of 2022 (“IRA”) was signed into law. The IRA allocated $1.55 billion to the Methane Emissions and Waste Reduction Incentive Program. The IRA also required the EPA to implement a waste emission charge ("WEC") on methane emitted from applicable oil and gas facilities that exceed certain thresholds. The WEC for 2024 was $900 per metric ton of methane and increases to $1,200 in 2025 and $1,500 in 2026. In November 2024, the EPA finalized a rule implementing the WEC that took effect in January 2025. The charge is designed to act as an incentive for operators to reduce emissions by minimizing leaks and replacing equipment rather than paying for excessive emissions. In February 2025, however, the U.S. House and Senate approved a joint resolution of disapproval under the Congressional Review Act to repeal the methane emissions charge, which President Trump is expected to sign into law.
While the State of Texas has not formally conducted recent rulemaking related to air emissions, scrutiny of oil and natural gas operations and the rules affecting them have increased in recent years. For example, the EPA and environmental non-governmental organizations have conducted flyovers with optical gas imaging cameras to survey emissions from oil and natural gas production facilities and transmission infrastructure. In August 2022, for example, the EPA announced that it would be conducting helicopter flyovers of the Permian Basin region in Texas. The flyovers used infrared cameras to survey oil and gas operations to identify large emitters of methane and volatile organic compounds ("VOCs"). Based on data obtained during flyovers, EPA intends to initiate enforcement follow up actions with facilities operators. In addition, the RRC has increased oversight related to flaring, with reporting reviews and site inspections. While none of these activities increases our compliance obligations, they signal the potential for increased enforcement and possible rulemaking in the future.
Oil Pollution Prevention
The OPA amended the CWA to impose liability for releases of crude oil from vessels or facilities into navigable waters. If a release of crude oil into navigable waters occurs during shipment or from an oil terminal, we could be subject to liability under the OPA. In 1973, the EPA adopted oil pollution prevention regulations under the CWA. These oil pollution prevention regulations require the preparation of a Spill Prevention Control and Countermeasure (“SPCC”) plan for facilities engaged in drilling, producing, gathering, storing, processing, refining, transferring, distributing, using, or consuming crude oil and oil products, and which due to their location, could reasonably be expected to discharge oil in harmful quantities into or upon the navigable waters of the United States. SPCC requirements under the CWA require appropriate containment berms and similar structures to help prevent the discharge of pollutants into regulated waters in the event of a crude oil or other constituent tank spill, rupture, or leak. The SPCC regulations require affected facilities to prepare a written, site-specific SPCC plan, which details how a facility’s operations comply with the requirements of the pollution prevention regulations. To be in compliance, the facility’s SPCC plan must satisfy all of the applicable requirements for drainage, bulk storage tanks, tank car and truck loading and unloading, transfer operations (intra-facility
piping), inspections and records, security, and training. Most importantly, the facility must fully implement the SPCC plan and train personnel in its execution. Where applicable, we maintain and implement SPCC plans for our facilities.
Water Discharges
The CWA and analogous state laws and regulations impose restrictions and strict controls regarding the discharge of pollutants into navigable waters, defined as waters of the United States (“WOTUS”), as well as state waters. The CWA prohibits the placement of dredge or fill material in wetlands or other WOTUS unless authorized by a permit issued by the U.S. Army Corps of Engineers (“Corps”) or a delegated state agency pursuant to Section 404 of the CWA. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Also, in June 2016, the EPA issued a final rule implementing wastewater pretreatment standards that prohibit onshore unconventional oil and natural gas extraction facilities from sending wastewater to publicly owned treatment works. This restriction of disposal options for hydraulic fracturing waste and other changes to CWA requirements have resulted in increased costs to operators, including us. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.
In January 2023, the EPA and the Corps issued a final rule that revised the definition of WOTUS. Separately, in May 2023, the U.S. Supreme Court’s decision in Sackett v. EPA narrowed federal jurisdiction over wetlands to “traditional navigable waters” and wetlands or other waters that have a “continuous surface connection” with or are otherwise indistinguishable from traditional navigable water. In September 2023, the EPA and the Corps published a direct-to-final rule that conforms the regulatory definition of “Waters of the United States” to the Supreme Court’s May 2023 decision in Sackett v. EPA. However, litigation opposing the September 2023 final rule remains ongoing and substantial uncertainty exists with respect to future implementation of the September 2023 rule and the scope of CWA jurisdiction more generally. Following legal actions, implementation of the most recent rule is currently split across the country. The rule is subject to an injunction in 27 states, including Texas, resulting in implementation of the pre-2015 rule adjusted to take into account jurisdictional limitations decided by the Supreme Court in Sackett v. EPA. The other 23 states are subject to the WOTUS-defining rule published in September 2023. Additionally, the Trump administration may pursue a new rulemaking to further revise or clarify the extent of federal jurisdiction under the CWA, though the substance and timing of such action cannot be predicted. As such, uncertainty remains with respect to future implementation of the rule and the outcome of the pending litigation. Many of our customers and service providers rely on permits obtained under the CWA for their oil and gas pipeline projects, the most common of which is Nationwide Permit 12 (“NWP 12”), which, from time to time, is renewed or modified by the Corps, whose actions in turn may be subject to litigation. To the extent any action expands the scope of the CWA in areas where we or our suppliers, customers or service providers operate or imposes new or enhanced permitting requirements, our operations could be adversely impacted by increased compliance costs and energy infrastructure project delays or cancellations.
Underground Injection Control
The underground injection of crude oil and natural gas wastes is regulated by the Underground Injection Control (“UIC”) program, as authorized by the SDWA, as well as by state programs. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluid from the injection zone into underground sources of drinking water, as well as to prevent communication between injected fluids and zones capable of producing hydrocarbons. The SDWA establishes requirements for permitting, testing, monitoring, recordkeeping, and reporting of injection well activities, as well as a prohibition against the migration of fluid containing contaminants into underground sources of drinking water. Any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in the suspension of permits, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource, and imposition of liability by third parties for property damages and personal injuries.
Under the auspices of the federal UIC program as implemented by states with UIC primacy, regulators, particularly at the state level, are becoming increasingly sensitive to possible correlations between underground injection and seismic activity. Consequently, state regulators implementing both the federal UIC program and state corollaries have been heavily scrutinizing the location of injection facilities relative to faulting and are limiting both the density and injection facilities as well as the rate of injection.
In Texas, the RRC regulates the disposal of produced water by injection well. Permits must be obtained before drilling saltwater disposal wells, and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking saltwater to groundwater. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SDWA and state laws. In response to recent seismic events near underground injection wells used for the disposal of oil and natural gas-related waste waters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or placed volumetric injection limits on existing wells or imposed moratoria on the use of such injection wells. In response to concerns related to induced seismicity, regulators in some states have already adopted or are considering additional requirements related to seismic safety. For example, the RRC has adopted rules for injection wells to address these seismic activity concerns in Texas. Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. More stringent regulation of injection wells could lead to reduced construction or the capacity of such wells, which could in turn impact the availability of injection wells for disposal of wastewater from our operations. Increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability. The costs associated with the disposal of produced water are commonly incurred by all oil and natural gas producers, however, and we do not believe that these costs will have a material adverse effect on our operations. In addition, third-party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury.
Hydraulic Fracturing
Hydraulic fracturing is a practice in the oil and natural gas industry used to stimulate production of natural gas and/or oil from low permeability subsurface rock formations by injecting water, sand, and chemicals under pressure. Oil and natural gas may be recovered from certain of our oil and natural gas properties through the use of hydraulic fracturing. Hydraulic fracturing is subject to regulation by state regulatory authorities, and several federal agencies have asserted federal regulatory authority over certain aspects of the hydraulic fracturing process. For example, the EPA published permitting guidance in February 2014 addressing the use of diesel fuel in fracturing operations, and in June 2016 EPA issued final effluent limitations guidelines under the CWA that waste-water from shale natural gas extraction operations must meet before discharging to a publicly owned treatment works.
Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process but, at this time, federal legislation related to hydraulic fracturing appears uncertain. In Texas, specific oil and natural gas regulations apply to oil and gas operations, including the drilling, completion and operations of wells, and the disposal of waste oil and salt water. In October 2023, the RRC announced draft amendments to its water protection rules to, among other things, encourage waste recycling. There are also procedures incident to the plugging and abandonment of dry holes or other non-operational wells, all as governed by the applicable governing state agency. As an example, the RRC adopted rules in 2014 requiring companies seeking permits for disposal wells to provide seismic activity data in permit applications. The rules also allow the RRC to modify, suspend, or terminate permits if a disposal well is determined to be causing seismic activity. Determinations by the RRC under these rules may adversely affect our operations.
If new laws or regulations that significantly restrict hydraulic fracturing are adopted at the local, state, or federal level, our fracturing activities could become subject to additional permit and financial assurance requirements, more stringent construction requirements, increased reporting or plugging and abandoning requirements or operational restrictions and associated permitting delays and potential increases in costs. These delays or additional costs could adversely affect the determination of whether a well is commercially viable and could cause us to incur substantial compliance costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce in commercial quantities.
Climate Change
Continuing political and social attention to the issue of global climate change has resulted in both existing and pending international agreements and national, regional, or local legislation and regulatory measures to limit or reduce emissions of so-called greenhouse gases (“GHGs”), such as cap and trade regimes, carbon taxes, restrictive permitting, increased fuel efficiency standards, and incentives or mandates for renewable energy. The EPA has adopted and implemented regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant
Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that already are major sources of criteria pollutants under the CAA. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that typically are GHG emissions. If we are required to meet "best available control technology," our operations could be adversely affected and our ability to obtain air permits for new or modified facilities that exceed GHG emission thresholds could be restricted or delayed. In addition, the EPA has adopted rules requiring the reporting of GHG emissions from oil and natural gas production and processing facilities on an annual basis, as well as reporting GHG emissions from gathering and boosting systems, oil well completions and workovers using hydraulic fracturing.
In addition, in November 2016, the BLM issued final rules to reduce methane emissions from venting, flaring, and leaks during oil and natural gas operations on federal lands that are substantially similar to the CAA’s New Source Performance Standards in 40 C.F.R. Part 60, Subpart OOOOa (“GHG NSPS”) requirements. In September 2018, the BLM published a final rule revising or rescinding certain provisions of the 2016 rule, which became effective on November 27, 2018. Both the 2016 and the 2018 rule were challenged in federal court resulting in the rescission of both rules. Appeals to those decisions are ongoing, but with little activity in the last several years. Moreover, several states have already adopted rules requiring operators of both new and existing sources to develop and implement an LDAR program and to install devices on certain equipment to capture methane emissions. Compliance with these rules could require us to purchase pollution control and leak detection equipment, and to hire additional personnel to assist with inspection and reporting requirements.
Additionally, a number of state and regional efforts are aimed at tracking and/or reducing GHG emissions by means of cap-and-trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. At the international level, there is an agreement, the United Nations-sponsored "Paris Agreement," for nations to limit their GHG emissions through non-binding, individually determined reduction goals every five years after 2020. The United States rejoined the Paris Agreement in February 2021. In early 2021, the Biden Administration issued a moratorium on oil and gas leasing on federal lands and waters to reduce emissions. Since then, the moratorium has been the subject of litigation and, in August 2022, a federal judge entered an injunction against the moratorium. In November 2021, the United States participated in the United Nations Climate Change Conference in Glasgow, Scotland, United Kingdom (“COP26”). COP26 resulted in a pact among approximately 200 countries, including the United States, called the Glasgow Climate Pact. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. In conjunction with COP26, the United States committed to an economy-wide target of reducing net greenhouse gas emissions by 50-52 percent below 2005 levels by 2030. Also in November 2021, President Biden signed a $1 trillion dollar infrastructure bill into law. The new infrastructure law includes several climate-focused investments, including upgrades to power grids to accommodate increased use of renewable energy and expansion of electric vehicle infrastructure. The above-referenced IRA allocated $369 billion to energy and climate initiatives. In November 2022, the United States participated in the United Nations Climate Change Conference in Egypt (“COP27”). In December 2023, the United States participated in the United Nations Climate Change Conference in the United Arab Emirates (“COP28”). In November 2024, the United States participated in the United Nations Climate Change Conference in Baku, Azerbaijan ("COP29"). Further, several states and local governments remain committed to the principles of the Paris Agreement in their effectuation of policy and regulations. However, in January 2025, President Trump issued an executive order directing immediate notice to the United Nations of the United States’ withdrawal from the Paris Agreement and all other agreements made under the United Nations Framework Convention on Climate Change. The full impact of these actions remains uncertain at this time; however, any such future laws and regulations imposing reporting obligations on, limiting emissions of GHGs from, our equipment and operations, or restricting federal leases could impair our production, could require us to incur costs to reduce emissions of GHGs associated with our operations and could decrease demand for oil and natural gas.
The adoption and implementation of any laws or regulations imposing reporting obligations on, or limiting emissions of GHG from, our equipment and operations could require additional expenditures to reduce emissions of GHGs associated with its operations or could adversely affect demand for the oil and natural gas we produce, and thus possibly have a material adverse effect on our revenues, as well as having the potential effect of lowering the value of our reserves. Recently, stakeholders concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities. Finally, to the extent increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events, such events could have a material adverse
effect on the Company and potentially subject the Company to further regulation. The trend of more expansive and stringent environmental legislation and regulations, including greenhouse gas regulation, could continue, resulting in increased costs of conducting business and consequently affecting our profitability.
Threatened and Endangered Species
Various federal and state statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands, and natural resources. These statutes include the Endangered Species Act (“ESA”), the Migratory Bird Treaty Act (“MBTA”) and the CWA. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. The dunes sagebrush lizard is one example of a species that was recently listed as an endangered species. The State of Texas has filed suit challenging the listing. The dunes sagebrush lizard is found in portions of Texas, including areas where we operate. The listing of the dunes sagebrush lizard as an endangered species, may impact our operations in any area that is designated as the dunes sagebrush lizard’s habitat. Depending on the locations of our operations, we may be required to comply with expensive mitigation measures intended to protect the dunes sagebrush lizard and its habitat. The U.S. Fish and Wildlife Service (“FWS”) may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause increased costs arising from species protection measures or could result in limitations on development activities that could have an adverse impact on the ability to develop and produce reserves within our assets. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.
Operational Hazards and Insurance
The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, well blow-outs, pipe failures, industrial accidents, and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil releases, chemical releases, natural gas leaks, and the discharge of toxic gases.
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us, for example, as a result of damage to our property or equipment or injury to our personnel. These operational risks could also result in the spill or release of hazardous materials such as drilling fluids or other chemicals, which may result in pollution, natural resource damages, or other environmental damage and necessitate investigation and remediation costs. As a result, we could be subject to liability under environmental law or common law theories. In addition, these operational risks could result in the suspension or delay of our operations, which could have significant adverse consequences on our business.
In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. Under certain circumstances, we may be liable for environmental damage caused by previous owners or operators of properties that we own, lease or operate. As a result, we may incur substantial liabilities to third parties or governmental entities for environmental matters for which we do not have insurance coverage, which could reduce or eliminate funds available for exploration, development or acquisitions or cause us to incur losses.
Human Capital Management
Key to our mission is our employees upon which the foundation of our Company is built. We seek to employ highly trained people who exemplify our core values of honesty and integrity, and are diligent, hard-working individuals who deliver results, and who are good neighbors that contribute to the communities in which they live.
As of December 31, 2024, we had 115 full-time employees. Our employees are extremely valuable to the success of the Company, and we encourage their collaboration and respect their diverse points of view and opinions. In addition to our full-time employees, the Company also employs a diverse group of independent contractors who assist our full-time staff in a range of areas including geology, engineering, land, accounting, and field operations, as needed. None are represented by labor unions or covered by any collective bargaining agreements.
We recognize that attracting, retaining and developing our employees is critical for our future success. Our Vice President General Counsel together with our Chief Executive Officer are responsible for developing and executing our
human capital strategy, with oversight by the Board of Directors and the board committees. Some of our key human capital areas of focus include the following.
Building a Safe Workforce Starts with Our Culture: Ring is committed to building a safety culture that empowers employees and contractors to act as needed to work safely and to stop a job, without retribution, if conditions are deemed unsafe. We strive to be incident-free every day across our operations. We are focused on building and maintaining a safe workplace for all employees and contractors. The oil and gas industry has a number of inherent risks and our workers are often outdoors, in all seasons and all types of weather. In addition, our field personnel spend significant time driving on a daily basis, putting them at risk for driving accidents. A strong safety culture is essential to our success, and we emphasize the important role that all personnel play in creating and maintaining a safe work environment.
Health and Safety Training and Education: We offer a wide range of training opportunities for employees and contractors to help them develop their skills and understanding of our health and safety policy and programs. In addition to teaching specific skills, these training opportunities encourage personal responsibility for safe operating conditions and help to build a culture of individual accountability for conducting job tasks in a safe and responsible manner.
Ring supports both Company identified and employee identified educational opportunities for employees to advance in their technical and managerial skills and to help provide opportunities to advance throughout our Company. Ring’s support comes in the form of full or partial funding of educational programs and opportunities, including time off work to attend and/or prepare for such programs.
Seasonal Nature of Business
Weather conditions often affect the demand for, and prices of, natural gas and can also delay oil and natural gas drilling, completion, and production activities, disrupting our overall business plans. Generally, the demand for oil and natural gas fluctuates depending on the time of year. Seasonal anomalies such as mild winters and summers may sometimes lessen this fluctuation. Demand for natural gas is typically higher during the winter, resulting in higher natural gas prices for our natural gas production during our first and fourth fiscal quarters. Further, pipelines, utilities, local distribution companies, and industrial end users utilize oil and natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can also lessen seasonal demand. Due to these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of the results that we may realize on an annual basis.
Available Information
Our website can be found at www.ringenergy.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed pursuant to Section 13(a) or 15(d) of the Exchange Act will be available through our website free of charge as soon as reasonably practical after we electronically file such material with, or furnish it to, the SEC. The information on, or that can be accessed through, our website is not incorporated by reference into this Annual Report and should not be considered part of this Annual Report. The SEC also maintains a website (http://www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.

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ITEM 1A. RISK FACTORS
Item 1A: Risk Factors
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 Report under “Forward-Looking Statements” and other information included and incorporated by reference into this Report.
Risks Relating to Our Business, Operations, and Strategy
Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve additional risks and uncertainties in their application compared to vertical drilling.
Our operations use some of the latest horizontal drilling and completion techniques as developed by us, other oil and natural gas exploration and production companies and our service providers. The additional risks that we face while drilling horizontally include, but are not limited to, the following:
•drilling wells that are significantly longer and/or deeper than vertical wells;
•landing our wellbores in the desired drilling zones;
•staying in the desired drilling zones while drilling horizontally through the formations;
•running our casing the entire length of wellbores; and
•being able to run tools and other equipment consistently through horizontal wellbores.
Risks that we face while completing our horizontal wells include, but are not limited to, the following:
•the ability to fracture or stimulate the planned number of stages in a horizontal wellbore;
•the ability to run tools and other equipment the entire length of a wellbore during completion operations; and
•the ability to successfully clean out a wellbore after completion of the final fracture stimulation stage.
If our assessments of purchased properties are materially inaccurate, it could have a significant impact on future operations and earnings.
The successful acquisition of producing properties requires assessments of many factors, which are inherently inexact and may be inaccurate, including the following:
•unforeseen title issues;
•the amount of recoverable reserves;
•future oil and natural gas prices;
•estimates of operating costs;
•estimates of future development costs;
•estimates of the costs and timing of plugging and abandonment of wells; and
•potential environmental and other liabilities.
Our assessments will not reveal all existing or potential problems, nor will they permit us to become familiar enough with the potential properties we may acquire to assess fully their capabilities and deficiencies. We plan to undertake further development of our properties generally through the use of cash flow from existing production. Therefore, a material deviation in our assessments of these factors could result in less cash flow being available for such purposes than we presently anticipate, which could either delay future development operations (and delay the anticipated conversion of reserves into cash) or cause us to seek alternative sources to finance development activities.
Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.
Our prospects are in various stages of evaluation, ranging from prospects that are currently being drilled to prospects that will require substantial additional seismic data processing and interpretation. We are unable to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. This risk may be enhanced in our situation, due to the
fact that a significant percentage of our proved reserves is currently proved undeveloped reserves. The use of seismic data and other technologies and the study of producing fields in the same area may not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data obtained by analyzing other wells, more fully explored prospects or producing fields will be applicable to all of our drilling prospects.
A substantial percentage of our proved properties are undeveloped; therefore, the risk associated with our success is greater than would be the case if a substantial majority of our properties were categorized as proved developed.
Because a substantial percentage of our proved properties are proved undeveloped (approximately 31%), we will require significant additional capital to develop such 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 borrowings or other means.
Hedging transactions may limit our potential gains.
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.
Hedging transactions may expose us to risk of financial loss.
While intended to reduce the effects of volatile oil and natural gas prices, derivative contracts designed as hedges expose us to risk of financial loss in some circumstances, including when there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received, or when the counterparty to the derivative contract defaults on its contractual obligations. It is also possible that sales volumes fall below the hedged volumes leaving a portion of our position uncovered.
We may be adversely affected by natural disasters, pandemics and other catastrophic events, and by man-made problems such as terrorism, that could disrupt our business operations.
Natural disasters, adverse weather conditions (particularly abnormally cold weather in the winter, and hurricanes and thunderstorms in the summer), floods, pandemics, acts of terrorism 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.
The loss of key members of management or failure to attract and retain other highly qualified personnel could affect the Company’s business results.
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 such individuals without incurring significant additional costs.
Risks Relating to the Oil and Natural Gas Industry
A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure obligations and financial commitments.
The prices we receive for our oil and natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile and we expect these markets will continue to be volatile. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include, but are not limited to, the following:
•changes in global supply and demand for oil and natural gas;
•the actions of the Organization of Petroleum Exporting Countries, or OPEC;
•the actions of oil exporting countries that are not members of OPEC;
•the price and quantity of imports and exports of oil and natural gas;
•political conditions, including embargoes, in or affecting other oil-producing activities;
•acts of war and related armed conflicts;
•the level of global oil and natural gas exploration and production activity;
•the level of global oil and natural gas inventories;
•weather conditions;
•technological advances affecting energy consumption; and
•the price and availability of alternative fuels.
Lower oil and natural gas prices may not only decrease our revenues on a per Boe basis but also may reduce the amount of oil and natural gas that we can produce economically. Lower prices also negatively impact the value of our proved reserves. A substantial or extended decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures.
Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition, and results of operations.
Our future success will depend on our exploitation, exploration, development, and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production.
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 uncertainty 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.
Decreases in oil and natural gas prices may require us to incur write-downs of the financial carrying values of our oil and natural gas properties which could negatively impact the price of our common stock.
Accounting rules require that we review periodically the financial carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics, and other factors, we may be required to write-down the financial carrying value of our oil and natural gas properties. A write-down would likely constitute a non-cash charge. The cumulative effect of one or more write-downs could also negatively impact the trading price of our common stock.
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 years ended December 31, 2024, 2023, and 2022 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.
It is difficult to estimate with any degree of reasonable certainty the amount of any future impairments given the many factors impacting the ceiling test calculation including, but not limited to, future pricing, operating costs, upward or downward reserve revisions, reserve adds, and tax attributes.
Decreases in oil and natural gas prices may affect our bank borrowing base, potentially requiring earlier than anticipated debt repayment, which could negatively impact our financial position, results of operations, and the price of our common stock.
Decreases in oil and natural gas prices could result in reductions in the borrowing base under our Credit Facility, thus requiring earlier than anticipated repayment of debt or trigger a possible default under our Credit Facility in the event we are unable to make payments or repayments under the Credit Facility on a timely basis.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could negatively affect the estimated quantities and present value of our reported reserves.
In order to prepare our estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production, and engineering data. The extent, quality, and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes, and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses, and quantities of recoverable oil and natural gas reserves will likely vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reported reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
You should not assume that the present value of future net revenues from our reported proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we generally base the estimated discounted future net cash flows from our proved reserves on prices and costs calculated on the date of the estimate. 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. Actual future prices and costs may differ materially from those used in the present value estimate. If future values decline or costs increase it could negatively impact our ability to finance operations, and individual properties could cease being commercially viable, affecting our decision to continue operations on certain producing properties or to attempt to develop certain properties. All of these factors would have a negative impact on earnings and net income, and most likely the price of our common stock. These factors could also result in the acceleration of debt repayment and a reduction in our borrowing base under our Credit Facility.
We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations.
We are not insured against all risks. Losses and liabilities arising from uninsured and under insured events could materially and adversely affect our business, financial condition, and results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:
•environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas, or other pollution into the environment, including groundwater;
•abnormally pressured formations;
•mechanical difficulties, such as stuck oil field drilling and service tools and casing collapses;
•fires and explosions;
•personal injuries and death; and
•natural disasters.
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses. We may elect to not obtain certain insurance coverage if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially and adversely affect us.
Unless we replace our oil and natural gas reserves, our reserves and production will decline as reserves are produced.
Unless we conduct successful exploration and development activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and, therefore, our cash flow and income, are highly dependent on our success in efficiently developing and producing our current reserves and economically finding or acquiring additional recoverable reserves. If we are unable to develop, find, or acquire additional reserves to replace our current and future production, our cash flow and income will decline as production declines, until our existing properties would be incapable of producing profitably.
Competition is intense in the oil and natural gas industry.
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 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.
If our access to markets is restricted, it could negatively impact our production, our income, and our ability to retain our leases.
Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of our producing properties to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. For example, for the year ended December 31, 2024, we experienced a negative price of $1.44 per Mcf of natural gas with negative net sales of approximately $9.3 million, adversely affecting our cash flows and net income.
Currently, some of our production is sold to marketers and other purchasers that have access to pipeline facilities. Much of our production is in areas with limited or no access to pipelines, thereby necessitating delivery by trucking. Further, much of our natural gas production is sold to companies who are the only gathering and processing facilities near most of our properties. Such restrictions on our ability to sell our oil or natural gas could have several adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in increased exposure to facility breakdowns and a lower selling prices) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possibly causing us to lose a lease due to lack of production.
Many of our properties are in areas that may have been partially depleted or drained by offset wells and certain of our wells may be adversely affected by actions we or other operators may take when drilling, completing, or operating wells that we or they own.
Many of our properties are in reservoirs that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling and completing additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations by us or other operators could cause depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells by us or other operators could cause production from our wells to be shut-in for indefinite periods of time, could result in increased lease operating expenses, and could adversely affect the production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators.
Multi-well pad drilling may result in volatility in our operating results.
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 such pad. As a result, multi-well pad drilling can cause delays in the scheduled commencement of production or interruptions in ongoing production.
Extreme weather conditions, which could become more frequent or severe due to multiple factors, could adversely affect our ability to conduct drilling, completion, and production activities in the areas where we operate.
Our exploration and development activities and equipment can be adversely affected by extreme weather conditions, such as abnormally low temperatures, which can cause a loss of production from temporary cessation of activity from regional power outages or lost or damaged facilities and equipment. For example, we had production stoppages in 2022, 2023, and 2024 that adversely affected our revenues. Extreme weather conditions could also impact access to our drilling and production facilities for routine operations, maintenance, and repairs and the availability of and our access to, necessary third-party services, such as gathering, processing, compression, and transportation services. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operation and capital costs, which could have a material adverse effect on our business, financial condition, and results of operations.
Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.
Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect certain wildlife, such as those restrictions imposed under the Endangered Species Act. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration, development and production activities that could have an adverse impact on our ability to develop and produce our reserves.
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 results 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 are 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, storage or use of surface water or ground water necessary for hydraulic fracturing of our wells, could increase our operating costs and cause delays, interruptions 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.
Risks Relating to Legal, Regulatory, Privacy, and Tax Matters
We are subject to complex laws that can affect the cost, manner, or feasibility of doing business.
Exploration, development, production, and sale of oil and natural gas are subject to extensive federal, state 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.
Under these laws, we could be liable for personal injuries, property damage, and other damages. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil, and criminal penalties. Moreover, these laws could change in ways that substantially increase our costs. Any such liabilities, penalties, suspensions, terminations, or regulatory changes could materially adversely affect our financial condition and results of operations.
Our operations may incur substantial liabilities to comply with environmental laws and regulations.
Our oil and natural gas operations are subject to stringent federal, state, and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences; restrict the types, quantities, and concentration of substances that can be released into the environment in connection with drilling and production activities; limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, and other protected areas; and impose substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties; incurrence of investigatory or remedial obligations; or the imposition of injunctive relief. Changes in environmental laws and regulations and the interpretation thereof occur from time to time, and any changes that result in more stringent or costly waste handling, storage, transport, disposal, or cleanup requirements could require us to make significant expenditures to maintain compliance and may otherwise have a material adverse effect on our results of operations, competitive position, and financial condition as well as the industry in
general. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or if our operations were standard in the industry at the time they were performed. The amount of any additional future costs is not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions or compliance efforts that may be required, the determination of the Company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties.
Our operations are subject to a series of risks arising out of the perceived threat of climate change that could result in increased operating costs, limit the areas in which we may conduct oil and natural gas exploration and production activities, and reduce demand for the oil and natural gas we produce.
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, federal regulators, state and local governments, and private parties have taken (or announced that they plan to take) actions that have or may have a significant influence on our operations. International climate commitments made by political, industrial, and financial 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. 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, the United Nations-sponsored “Paris Agreement” encourages member states to individually determine and submit non-binding emissions reduction targets. The United States’ most recent goal was to reduce its economy-net GHG emissions by 61 to 66 percent from 2005 levels by 2035. 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 United States’ withdrawal from the Paris Agreement and ordered the revocation of any related financial commitments. 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.
Increasingly, oil and natural gas companies are exposed to litigation risks associated with the threat of climate change. A number of parties have brought lawsuits against oil and natural gas companies in state or federal court for alleged contributions to, or failures to disclose the impacts of, climate change. We are not currently party to any such litigation, but could be named in future actions making similar claims of liability. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.
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.
The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives related to climate change or GHG emissions from oil and natural gas facilities could result in increased costs of compliance or costs of consumption, thereby reducing demand for, oil and natural gas. Additionally, political, litigation, and financial risks may result in (i) restriction or cancellation of certain oil and natural gas production activities, (ii) incurrence of obligations for alleged damages resulting from climate change, or (iii) impairment of our ability to continue operating in an economic manner. One or more of these developments could have a material adverse effect on our business, financial condition, and results of operations.
Moreover, climate change may also result in various physical risks such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns, that could adversely impact our financial condition and operations, as well as those of our suppliers or customers. Such physical risks may result in damage to our facilities, or otherwise adversely impact our operations, such as if we become subject to water use curtailments in response to drought, or demand for our products, such as to the extent warmer winters reduce the demand for energy for heating purposes. Such physical risks may also impact the infrastructure on which we rely to produce or transport our products. One of more of these developments could have a material adverse effect on our business, financial condition, and operations. In addition, while our consideration of changing weather conditions and inclusion of safety factors in design is intended to reduce the uncertainties that climate change and other events may potentially introduce, our ability to mitigate the adverse impacts of these events depends in part on the effectiveness of our facilities and our disaster preparedness and response and business continuity planning, which may not have considered or be prepared for every eventuality.
Changes in tax laws or the interpretation thereof or the imposition of new or increased taxes or fees may adversely affect our operating results and cash flows.
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 these or similar 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 legislation as a result of these proposals and 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, the U.S. Department of Treasury and the Internal Revenue Service are expected to release regulations and interpretive guidance relating to the CAMT, and any 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.
Also, we are subject to unclaimed or abandoned property (escheat) laws which require us to turn over to certain government authorities the property of others held by us that has been unclaimed for a specified period. We are subject to audits by individual U.S. states regarding our escheatment practices. The legislation and regulations related to unclaimed property matters are complex and subject to varying interpretations by state governmental authorities.
Risks Relating to Our Capital Structure
We have significant indebtedness.
We have a Credit Facility in place with $600 million in commitments from borrowings and letters of credit under our Second Amended and Restated Credit Agreement dated August 31, 2022 with Truist Bank as Administrative Agent (the "Second Credit Agreement"). As of December 31, 2024, $385 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:
•a significant portion of our cash flow would need to be used to service the indebtedness;
•we are required to put into place derivative contracts to hedge a significant portion of our oil and gas production;
•a high level of debt would increase our vulnerability to general adverse economic and industry conditions;
•the covenants contained in our Credit Facility limit our ability to borrow additional funds, dispose of assets, pay dividends, and make certain investments, and;
•a high level of debt could impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate, or other purposes.
In addition, our bank borrowing base is subject to semi-annual redeterminations. We could be required to repay a portion of our bank borrowings due to redeterminations of our borrowing base. If we are required to do so, we may not have sufficient funds to make such repayments, and we may need to negotiate renewals of our borrowings or arrange new financing or sell significant assets. Any such actions could have a material adverse effect on our business and financial results. Further, our borrowings under our Credit Facility expose us to interest rate risks, as it bears variable interest based upon a prime rate and is therefore susceptible to interest rate fluctuations.
We may be unable to access the equity or debt capital markets to meet our obligations.
Our plans for growth may include accessing the capital markets. Recent reluctance to invest in the exploration and production sector based on market volatility, historically perceived underperformance, and ESG trends, among other
things, has raised concerns regarding capital availability for the sector. If those markets are unavailable, or if we are unable to access alternative means of financing on acceptable terms, we may be unable to implement all of our development plans, make acquisitions, or otherwise carry out our business strategy, which would have a material adverse effect on our financial condition and results of operations, and impair our ability to service our indebtedness.
We continue to be impacted by inflationary pressures on our operating costs and capital expenditures.
Beginning in the second half of 2021 and continuing throughout 2024, we, similar to other companies in our industry, experienced inflationary pressures on our operating costs and capital expenditures - namely the costs of fuel, steel (i.e., wellbore tubulars), labor, and drilling and completion services. Such inflationary pressures on our operating and capital costs, which we currently expect to continue in 2025, have impacted our cash flows and results of operations. We have undertaken, and plan to continue with, certain initiatives and actions (such as agreements with service providers to secure the costs and availability of services) to mitigate such inflationary pressures. However, there can be no assurance that such efforts will offset, largely or at all, the impacts of any future inflationary pressures on our operating costs and capital expenditures and, in turn, our cash flows and results of operations.
Risks Relating to Technology and Cybersecurity
We rely on computer and telecommunications systems, and failures in our systems or cyber security 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 security 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.
As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyberattacks. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities, and infrastructure may result in increased capital and operating costs. A cyberattack or security breach could result in liability under data privacy laws, regulatory penalties, damage to our reputation, or loss of confidence in us, or additional costs for remediation and modification or enhancement of our information systems to prevent future occurrences, all of which could have a material and adverse effect on our business, financial condition, or results of operations. While we maintain insurance that covers certain cybersecurity incidents, we may not be insured for, or our insurance may be insufficient to protect us against, particular types of cybersecurity risks, and, in the future, such insurance may not continue to be available to us on reasonable terms, if at all. To date we have not experienced any material losses relating to cyber-attacks; however, there can be no assurance that we will not suffer such losses in the future. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition, and results of operations.
Risks Relating to Our Common Stock
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.
The market price of our common stock may be volatile, which could cause the value of your investment to decline.
The stock markets have experienced volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. The market price of our common stock may also fluctuate significantly in response to the following factors, some of which are beyond our control:
•our operating and financial performance and prospects;
•variations in our quarterly operating results and changes in our liquidity position;
•investor perceptions of us and the industry and markets in which we operate;
•future sales, or the availability for sale, of equity or equity-related securities;
•changes in securities analysts’ estimates of our financial performance;
•changes in market valuations of similar companies;
•changes in the price of oil and natural gas; and
•general financial, domestic, economic, and other market conditions.
We currently do not pay cash dividends on 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.
Our Board of Directors can, without stockholder approval, cause preferred stock to be issued on terms that could adversely affect common stockholders.
Under our Articles of Incorporation, our Board of Directors is authorized to issue up to 50,000,000 shares of preferred stock, of which none are issued and outstanding as of the date of this Annual Report. Also, our Board of Directors, without stockholder approval, may determine the price, rights, preferences, privileges, and restrictions, including voting rights, of those shares. If the Board of Directors causes shares of preferred stock to be issued, the rights of the holders of our common stock could be adversely affected. The Board of Directors’ ability to determine the terms of preferred stock and to cause its issuance, while providing desirable flexibility in connection with possible acquisitions and other corporate purposes, could have the effect of making it more difficult for a third party to acquire a majority of our outstanding voting stock. Preferred shares issued by the Board of Directors could include voting rights, or even super voting rights, which could shift the ability to control the Company to the holders of the preferred stock. Preferred shares could also have conversion rights into shares of common stock at a discount to the market price of the common stock which could negatively affect the market for our common stock. In addition, preferred shares would typically have preference in the event of liquidation of the Company, which means that the holders of preferred shares would be entitled to receive the net assets of the Company distributed in liquidation before the common stockholders receive any distribution of the liquidated assets. We have no current plans to issue any shares of preferred stock.
Provisions under Nevada law could delay or prevent a change in control of our company, which could adversely affect the price of our common stock.
In addition to the ability of the Board of Directors to issue preferred stock, the existence of some provisions under Nevada law could delay or prevent a change in control of the Company, which could adversely affect the price of our
common stock. Nevada law imposes some restrictions on mergers and other business combinations between us and any holder of 10% or more of our outstanding common stock.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B: Unresolved Staff Comments
None.

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ITEM 2. PROPERTIES
Item 2: Properties
General Background
Ring is engaged in oil and natural gas development, production, acquisition, and exploration activities currently focused in the Permian Basin of Texas.
Management’s Business Strategy Related to Properties
Our goal is to increase stockholder value by investing in oil and natural gas projects with attractive rates of return on capital employed. We plan to achieve this goal by developing our existing oil and natural gas properties and pursuing strategic acquisitions of additional properties.
Developing Existing Properties
We believe that there is significant value to be created by drilling the undeveloped opportunities on our properties. As of December 31, 2024, we owned interests in a total of 76,284 gross (65,342 net) developed acres and operate the vast majority of our acreage position. In addition, as of December 31, 2024, we owned interests in approximately 21,315 gross (15,577 net) undeveloped acres. While our near-term plans are focused on drilling wells on our existing acreage to develop the potential contained therein, our long-term plans also include continuing to evaluate acquisition and leasing opportunities that can earn attractive rates of return on capital employed.
Within the Northwest Shelf, we have a total of 35 proved undeveloped locations (100% horizontal) and 3 PDNP opportunities based on the reserve report as of December 31, 2024. Our reserve estimates account for the capital costs required to develop these wells and the future plugging and abandonment costs. We believe the Northwest Shelf leases contain additional potential drilling locations.
Within the Central Basin Platform, we had a total of 176 proved undeveloped locations (13% horizontal and 88% vertical) and 217 PDNP opportunities based on the reserve report as of December 31, 2024. Our reserve estimates account for the capital costs required to develop these wells and the future plugging and abandonment costs. We believe the Central Basin Platform leases contain additional potential drilling locations.
Pursuing Profitable Acquisitions
We have historically pursued acquisitions of properties that we believe to have exploitation and development potential comparable to our existing inventory of drilling locations. We have an experienced team of management, engineering, geoscience, and land professionals who identify and evaluate acquisition opportunities, negotiate and close purchases and manage acquired properties.
Summary of Oil and Natural Gas Properties and Projects
Significant Operations
The Company's significant operations are in two core areas which it has actively drilled over the last several years located in the Northwest Shelf and the Central Basin Platform of the Permian Basin.
Northwest Shelf - Yoakum County, Texas and Lea County, New Mexico - In 2019, we acquired properties consisting of 49,754 gross (38,230 net) acres with an average working interest of 77% and an average net revenue interest of 58%. As of December 31, 2024, we owned interests in a total of 12,572 gross (8,722 net) developed acres and 14,979 gross (11,548 net) undeveloped acres with an average proved operated working interest of 91% and net revenue interest of 69%. As of December 31, 2024, the Company had interests in approximately five gross vertical and 151 gross horizontal producing wells, of which we operate five vertical and 116 horizontal wells. The horizontal wells predominately produce from the San Andres conventional reservoir and the verticals produce from Wolfcamp reservoir.
Central Basin Platform - Andrews, Gaines, Crane, Ector, Winkler, and Ward Counties, Texas - In 2011, we acquired a 100% working interest and a 75% net revenue interest in our initial leases in Andrews County. Since that time, we have acquired working and net revenue interests in additional producing leases and acquired additional undeveloped acreage in and around our Andrews County and Gaines County leases. In 2022, we acquired properties consisting of approximately 37,000 net acres, with an average working interest of 99% and an average net revenue interest of 88% for oil and 96% for natural gas in our initial leases in Crane, Winkler, and Ward counties. In 2023, we acquired properties in Ector County. As of December 31, 2024, we owned interests in a total of 63,712 gross (56,620 net) developed acres and 6,336 gross (4,029 net) undeveloped acres with an average proved operated working interest of 97% and net revenue interest of 83% in the area. As of December 31, 2024, the Company had interests in approximately 581 gross vertical and 198 gross horizontal producing wells, of which we operate 470 vertical and 196 horizontal wells. The horizontal wells predominately produce from the San Andres conventional reservoir and the vertical wells produce from a variety of conventional pay sands including Holt, Glorieta, Clear Fork, Wichita Albany, Tubb, Wolfcamp and Devonian reservoirs.
Title to Properties
We generally conduct a preliminary title examination prior to the acquisition of properties or leasehold interests. Prior to commencement of operations on such acreage, a thorough title examination is usually conducted and any significant defects are remedied before proceeding with operations. We believe the title to our leasehold properties is good, defensible, and customary with practices in the oil and natural gas industry, subject to such exceptions that we believe do not materially detract from the use of such properties. With respect to our properties of which we are not the record owner, we rely on contracts with the owner or operator of the property or assignment of leases, pursuant to which, among other things, we generally have the right to have our interest placed on record.
Our properties are generally subject to royalty, overriding royalty and other interests customary in the industry, liens incident to lending agreements, current taxes and other customary burdens, minor encumbrances, easements, and restrictions. We do not believe any of these burdens materially interfere with our use of these properties.
Summary of Oil and Natural Gas Reserves
As of December 31, 2024, our estimated proved reserves had a pre-tax PV-10 value (present value discounted at 10%) of approximately $1,462.8 million and a Standardized Measure of Discounted Future Net Cash Flows of
approximately $1,232.9 million, over 99.7% of which relates to our properties in the Permian Basin in Texas. We spent approximately $391.6 million on acquisitions and capital projects during 2024 and 2023. We expect to further develop these properties through additional drilling.
The following table summarizes our total net proved reserves, pre-tax PV-10 value and Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2024. Approximately 99.8% of our proved reserves are in the Permian Basin in Texas.
Oil
(Bbl) Natural
Gas (Mcf) Natural
Gas Liquids (Bbl) Total
(Boe) (1)
Pre-Tax PV-10
Value (2)
Standardized
Measure of
Discounted Future
Net Cash Flows
80,904,071 149,817,162 28,303,085 134,176,684 $ 1,462,827,136 $ 1,232,936,343
(1) Six Mcf is deemed the equivalent of one Boe.
(2) PV-10 is a non-GAAP financial measure. See below for a reconciliation.
We present the pre-tax PV-10 value, which is a non-GAAP financial measure, because it is a widely used industry standard which we believe is useful to those who may review this Report when comparing our asset base and performance to other comparable oil and natural gas exploration and production companies. PV-10 is a non-GAAP measure that differs from a measure under accounting principles generally accepted in the United States ("GAAP") known as “standardized measure of discounted future net cash flows” in that PV-10 is calculated without including future income taxes. PV-10 does not necessarily represent the fair market value of oil and natural gas properties. PV-10 is not a measure of financial or operational performance under GAAP, nor should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.
The table below provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows:
Present value of estimated future net revenues (PV-10) $ 1,462,827,136
Future income taxes, discounted at 10% $ 229,890,793
Standardized measure of discounted future net cash flows $ 1,232,936,343
Reserve Quantity Information
Our estimates of proved reserves and related valuations are based on reports independently determined and prepared by Cawley, Gillespie & Associates, Inc. ("CGA"), independent petroleum engineers. These reserves are
attributable solely to properties within the United States. A summary of the changes in quantities of proved (developed and undeveloped) oil, natural gas, and natural gas liquid reserves is shown below.
Oil (Bbl) Gas (Mcf)(2)
Natural Gas Liquids (Bbl)(2)
Boe(1)
Balance, December 31, 2022 88,704,743 157,870,449 23,105,658 138,122,143
Purchase of minerals in place 6,543,640 3,372,965 1,089,382 8,195,183
Extensions, discoveries and improved recovery 3,098,845 4,113,480 1,014,343 4,798,768
Sales of minerals in place (4,897,921) (2,674,955) (392,953) (5,736,700)
Production (4,579,942) (6,339,158) (976,852) (6,613,320)
Revisions of previous quantity estimates (6,728,088) (9,946,459) (621,014) (9,006,845)
Balance, December 31, 2023 82,141,277 146,396,322 23,218,564 129,759,229
Purchase of minerals in place - - - -
Extensions, discoveries and improved recovery 11,495,236 10,630,769 2,738,451 16,005,482
Sales of minerals in place (1,140,568) (56,020) (16,361) (1,166,266)
Production (4,861,628) (6,423,674) (1,258,814) (7,191,054)
Revisions of previous quantity estimates (6,730,246) (730,235) 3,621,245 (3,230,707)
Balance, December 31, 2024 80,904,071 149,817,162 28,303,085 134,176,684
(1)Six Mcf is deemed the equivalent of one Boe.
(2)At year-end 2022, we began reporting reserves on a three-stream basis, including NGLs separately from natural gas.
Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history, a rule that undeveloped reserves must be drilled within five years of originally being booked, and/or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.
Notable changes in proved reserves for the year ended December 31, 2024 included the following:
•Extensions. In 2024, extensions of 16.0 MMBoe were primarily the result of the successful operated drilling program in the Northwest Shelf and Central Basin Platform.
•Purchase of minerals in place. In 2024, the Company did not purchase any additional reserves.
•Sales of minerals in place. In 2024, the Company sold 1.2 MMBoe from the divestiture of certain oil and gas properties, including vertical wells and associated facilities, within the Central Basin Platform in Andrews and Gaines Counties.
•Revision of previous estimates. In 2024, the negative revisions of prior reserves of 3.2 MMBoe consisted of a positive 0.2 MMBoe related to changes in price (including differentials and gathering related contract change that effects differentials), offset by a negative 3.4 MMBoe related to changes in performance and other economic factors.
Our proved oil, natural gas, and natural gas liquid reserves are shown below.
For the years ended December 31,
2024 2023
Oil (Bbl)
Developed 56,106,714 56,029,039
Undeveloped 24,797,357 26,112,238
Total 80,904,071 82,141,277
Natural Gas (Mcf)
Developed 102,538,111 99,896,022
Undeveloped 47,279,051 46,500,300
Total 149,817,162 146,396,322
Natural Gas Liquids (Bbl)
Developed 19,426,387 15,449,907
Undeveloped 8,876,698 7,768,657
Total 28,303,085 23,218,564
Total (Boe) (1)
Developed 92,622,787 88,128,284
Undeveloped 41,553,897 41,630,945
Total 134,176,684 129,759,229
(1) Six Mcf is deemed the equivalent of one Boe.
Standardized Measure of Discounted Future Net Cash Flows
Our standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves and changes in the standardized measure as described below were prepared in accordance with GAAP.
Future income tax expenses are calculated by applying appropriate year-end tax rates to future pre-tax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences, tax credits, and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value of our oil and natural gas properties.
Our estimates of reserves and future cash flow as of December 31, 2024 and 2023 were prepared using an average price equal to the unweighted arithmetic average of the first day of the month price for each month within the 12-month periods ended December 31, 2024 and 2023, respectively, in accordance with SEC guidelines. As of December 31, 2024, our reserves were based on an SEC average price of $71.96 per Bbl of WTI oil posted and $2.130 per MMBtu of Henry Hub natural gas. As of December 31, 2023, our reserves were based on an SEC average price of $74.70 per Bbl of WTI oil posted and $2.637 per MMBtu Henry Hub natural gas. Prices are adjusted by local field and lease level differentials and are held constant for life of reserves in accordance with SEC guidelines.
The standardized measure of discounted future net cash flows relating to the proved oil, natural gas, and NGLs reserves are shown below.
Standardized Measure of Discounted Future Net Cash Flows
As of December 31, 2024 2023 2022
Future cash inflows $ 6,165,487,616 $ 6,622,410,752 $ 9,871,961,000
Future production costs (2,432,555,200) (2,413,303,488) (2,751,896,250)
Future development costs (1)
(536,825,664) (562,063,424) (647,196,750)
Future income taxes (465,768,645) (548,664,988) (1,142,147,641)
Future net cash flows 2,730,338,107 3,098,378,852 5,330,720,359
10% annual discount for estimated timing of cash flows (1,497,401,764) (1,699,193,661) (3,058,606,841)
Standardized Measure of Discounted Future Net Cash Flows $ 1,232,936,343 $ 1,399,185,191 $ 2,272,113,518
(1) Future development costs include not only development costs but also future asset retirement costs.
The changes in the standardized measure of discounted future net cash flows relating to the proved oil, natural gas and natural gas liquid reserves are shown below.
Changes in Standardized Measure of Discounted Future Net Cash Flows
2024 2023 2022
Beginning of the year $ 1,399,185,191 $ 2,272,113,518 $ 1,137,364,848
Purchase of minerals in place - 141,738,066 996,313,882
Extensions, discoveries and improved recovery 226,741,618 57,607,609 20,447,842
Development costs incurred during the year 71,665,321 70,697,664 67,454,522
Sales of oil and gas produced, net of production costs (263,830,836) (266,004,598) (283,588,498)
Sales of minerals in place (10,230,951) (59,600,128) -
Accretion of discount 164,703,142 277,365,650 133,209,763
Net changes in price and production costs (285,618,955) (1,181,594,019) 646,819,172
Net change in estimated future development costs 6,732,428 37,865,811 (53,253,626)
Revisions of previous quantity estimates (50,292,499) (187,443,783) 33,583,837
Changes in estimated timing of cash flows (44,073,556) (17,257,348) (119,428,019)
Net change in income taxes 17,955,440 253,696,749 (306,810,205)
End of the Year $ 1,232,936,343 $ 1,399,185,191 $ 2,272,113,518
Our proved reserves by state as of December 31, 2024 are summarized in the table below.
Oil (Bbl) Gas (Mcf) NGL (Bbl)
Total (Boe) % of Total
Proved Pre-tax PV-10
(In thousands) Standardized
Measure of
Discounted Future
Net Cash Flows
(In thousands) Future Capital
Expenditures
(In thousands)
Texas
PD 55,923,366 102,194,638 19,356,935 92,312,741 69 % $ 1,126,097 $ 949,125 $ 149,138
PUD 24,797,357 47,279,051 8,876,698 41,553,897 31 % 332,654 280,376 378,175
Total Proved: 80,720,723 149,473,689 28,233,633 133,866,638 100 % $ 1,458,751 $ 1,229,501 $ 527,313
New Mexico
PD 183,348 343,473 69,452 310,046 - % $ 4,076 $ 3,435 $ 98
PUD - - - - - % - - -
Total Proved: 183,348 343,473 69,452 310,046 - % $ 4,076 $ 3,435 $ 98
Total
PD 56,106,714 102,538,111 19,426,387 92,622,787 69 % $ 1,130,173 $ 952,561 $ 149,236
PUD 24,797,357 47,279,051 8,876,698 41,553,897 31 % 332,654 280,376 378,175
Total Proved: 80,904,071 149,817,162 28,303,085 134,176,684 100 % $ 1,462,827 $ 1,232,936 $ 527,411
Proved Reserves
As of December 31, 2024, we had approximately 134.2 MMBoe of proved reserves, consisting of approximately 60% oil, 19% natural gas, and 21% NGLs, as summarized in the table above. Our reserve estimates have not been filed with any Federal authority or agency (other than the SEC).
As of December 31, 2024, approximately 69% of the proved reserves were classified as PD and the remaining 31% were PUD.
As of December 31, 2024, our total proved reserves had a net pre-tax PV-10 value of approximately $1,462.8 million and a Standardized Measure of Discounted Future Net Cash Flows ("SMOG") of approximately $1,232.9 million. Approximately $1,130.2 million pre-tax PV-10 and $952.6 million SMOG, respectively, of total proved reserves are associated with the PD reserves, which is approximately 77% of the total proved reserves’ pre-tax PV-10 value. The remaining $332.7 million pre-tax PV-10 and $280.4 million SMOG, respectively, are associated with PUD reserves.
Proved Undeveloped Reserves
Our reserve estimates as of December 31, 2024 include approximately 41.6 MMBoe as PUDs. As of December 31, 2023, our reserve estimates included approximately 41.6 MMBoe as PUDs. In accordance with our December 31, 2024 year-end independent engineering reserve report, we plan to drill our PUD drilling locations within five years of original classification. Below is a description of the changes in our PUD reserves from December 31, 2023 to December 31, 2024.
Notable changes in proved undeveloped reserves for the year ended December 31, 2024 included the following:
•Conversions to developed. During the year ended December 31, 2024, we incurred costs of approximately $64.7 million to convert 33 properties from PUD to PD through development. These 33 properties produced 893 MBoe during the year ended December 31, 2024, and have reserves of 6,538 MBoe as of December 31, 2024.
•Extensions. In 2024, extensions of 12.8 MMBoe were primarily the result of the successful operated drilling program in the Northwest Shelf and Central Basin Platform.
•Purchase of minerals in place. In 2024, we did not purchase any additional reserves.
•Sales of minerals in place. In 2024, we sold 0.1 MMBoe from the divestiture of certain oil and gas properties within the Central Basin Platform.
•Revision of previous estimates. In 2024, the negative revisions of prior reserves of 5.6 MMBoe consisted of a positive 0.2 MMBoe (4%) related to changes in price (including differentials and gathering related contract change that effects differentials) offset by a negative 5.8 MMBoe (104%) related to changes in performance and other economic factors.
The following table indicates projected reserves that we currently estimate will be converted from proved undeveloped to proved developed, as well as the estimated costs per year involved in such development. Our PUD reserves are part of a management adopted development plan that schedules PUD reserves to be developed within five years of initial disclosure as proved reserves. As of December 31, 2024, no material amount of proved undeveloped reserves were not scheduled to be converted to proved developed status within five years of when they were initially disclosed.
Estimated Costs Related to Conversion of Proved Undeveloped Reserves to Proved Developed Reserves
Year Estimated Oil
Reserves
Developed (Bbl) Estimated Gas
Reserves
Developed (Mcf) Estimated NGL
Reserves
Developed (Bbl) Total Boe Estimated
Development Costs
2025 9,654,298 6,533,610 1,631,662 12,374,895 $ 119,174,352
2026 6,405,076 12,440,141 2,262,321 10,740,754 101,542,200
2027 4,796,872 21,769,433 3,283,966 11,709,077 107,656,840
2028 3,941,111 6,535,867 1,698,749 6,729,171 44,293,536
2029 (1)
5,508,540
Total
24,797,357 47,279,051 8,876,698 41,553,897 $ 378,175,468
Preparation and Internal Controls Over Reserves Estimates
All the proved oil and natural gas reserves disclosed in this Report are based on reserve estimates determined and prepared by our independent reserve engineers, Cawley, Gillespie & Associates, Inc. (“CGA”), a leader of petroleum property analysis for industry and financial institutions. CGA was founded in 1960 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No.. Within CGA, the technical person primarily responsible for preparing the estimates set forth in the CGA letter dated January 24, 2025, filed as an exhibit to this Annual Report, was Mr. Zane Meekins. Mr. Meekins has been a practicing consulting petroleum engineer at CGA since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas (License No. 71055) and has over 37 years of practical experience in petroleum engineering, with over 35 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a Bachelor of Science degree in Petroleum Engineering. Mr. Meekins meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.
The proved oil and natural gas reserves disclosed in this Annual Report are based on reserve estimates determined and prepared by our independent reserve engineers primarily using decline curve analysis to determine the reserves of individual producing wells. To establish reasonable certainty with respect to our estimated proved reserves, the independent reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using volumetric estimates or performance from analogous wells in the surrounding area. These wells were considered to be analogous based on production performance from the same formation and completions using similar techniques. The technologies and economic data used to estimate our proved reserves include, but are not limited to, well logs, geological maps, seismic data, well test data, production data, historical price and cost information, and property
ownership interests. This data was reviewed by various levels of our management for accuracy before consultation with our independent reserve engineers. This consultation included review of properties, assumptions, and available data. Internal reserve estimates were compared to those prepared by CGA to test the estimates and conclusions before the reserves were included in this Annual Report. The accuracy of the reserve estimates is dependent on many factors, including the following:
•the quality and quantity of available data and the engineering and geological interpretation of that data;
•estimates regarding the amount and timing of future costs, which could vary considerably from actual costs;
•the accuracy of economic assumptions; and
•the judgment of the personnel preparing the estimates.
Our Executive Vice President of Engineering and Corporate Strategy, Mr. Alex Dyes, is the technical professional primarily responsible for overseeing the preparation of our reserves estimates. He has a Bachelor of Science degree in Petroleum Engineering from the University of Texas with over 18 years of practical industry experience, including over 14 years of estimating and evaluating reserve information. He has been a member of the Society of Petroleum Engineers since 2013 and his qualifications meet or exceed the Society of Petroleum Engineers’ standard requirements to be a professionally qualified Reserve Estimator and Auditor.
We encourage ongoing professional education for our engineers and reservoir analysts on new technologies and industry advancements as well as refresher training on basic skill sets. In order to ensure the reliability of reserves estimates, our Corporate Reserves department follows comprehensive SEC-compliant internal controls and policies to determine, estimate, and report proved reserves including:
•confirming that we include reserves estimates for all properties owned and that they are based upon proper working and net revenue interests;
•ensuring the information provided by other departments within the Company, such as accounting, land, and operations is accurate;
•communicating, collaborating, and analyzing with technical personnel in our business units;
•comparing and reconciling the internally generated reserves estimates to those prepared by third parties; and
•utilizing experienced reservoir engineers or those under their direct supervision to prepare reserve estimates.
Each quarter, the Corporate Reserves team along with the Executive Vice President of Engineering and Corporate Strategy presents the status of the Company’s reserves to senior executives, and subsequently obtains approval of significant changes from key executives. Additionally, our five-year PUD development plan is reviewed and approved annually by the Company’s Chief Executive Officer; Chief Financial Officer; Executive Vice President of Engineering and Corporate Strategy; Vice President of Operations; Executive Vice President, Exploration and Geosciences; and Vice President, General Counsel.
The Corporate Reserves department works closely with independent reserve engineers from CGA at each fiscal year end to ensure the integrity, accuracy, and timeliness of annual independent reserves estimates. These independently developed reserves estimates are presented to the Audit Committee. In addition to reviewing the independently developed reserve reports, the Audit Committee also meets with CGA annually at a minimum.
Summary of Oil and Natural Gas Properties and Projects
Acreage
The following table summarizes our gross and net developed and undeveloped acreage as of December 31, 2024 by region (net acreage is our percentage ownership of gross acreage). Acreage in which our interest is limited to royalty and overriding royalty interests is excluded, as it is de minimis.
Developed Acreage Undeveloped Acreage Total Acreage
Gross Net Gross Net Gross Net
Central Basin Platform 63,712 56,620 6,336 4,029 70,048 60,649
Northwest Shelf 12,572 8,722 14,979 11,548 27,551 20,270
Total 76,284 65,342 21,315 15,577 97,599 80,919
Leases of undeveloped acreage will generally expire at the end of their respective primary terms unless production from such leasehold acreage has been established prior to expiration of such primary terms. If production is established on the acreage, the lease will generally remain in effect until the cessation of production from the acreage and is referred to in the industry as HBP. Leases of undeveloped acreage may terminate or expire as a result of not meeting certain drilling commitments, if any, or otherwise by not complying with the terms of a lease depending on the specific terms that are negotiated between the lessor and the lessee.
The following table sets forth our gross and net undeveloped acreage, as of December 31, 2024, under lease that will expire over the next three years unless (i) production is established on the lease or within a spacing unit of which the lease is participating, or (ii) the lease is renewed or extended prior to the relevant expiration dates:
Undeveloped Acreage
2025 2026 2027
Gross Net Gross Net Gross Net
Central Basin Platform 640 115 240 108 1,223 996
Northwest Shelf 7,051 3,450 2,192 524 1,627 452
Total 7,691 3,565 2,432 632 2,850 1,448
Production History
The following table presents the historical information regarding our produced oil, natural gas and natural gas liquid volumes for the years ended December 31, 2024, 2023, and 2022:
Years ended December 31,
2024 2023 2022
Oil (Bbls)
Central Basin Platform 2,851,788 2,347,068 1,409,211
Delaware Basin (2)
- 25,743 81,936
Northwest Shelf 2,009,840 2,207,131 1,968,693
Total 4,861,628 4,579,942 3,459,840
Natural Gas (Mcf)(1)
Central Basin Platform 3,808,653 3,940,107 1,563,808
Delaware Basin (2)
- 11,265 96,516
Northwest Shelf 2,615,021 2,387,786 2,428,318
Total 6,423,674 6,339,158 4,088,642
Natural Gas Liquids (Bbls)(1)
Central Basin Platform 749,794 703,818 227,996
Delaware Basin (2)
- 2,867 3,718
Northwest Shelf 509,020 270,167 139,615
Total 1,258,814 976,852 371,329
Total production (Boe)
Central Basin Platform 4,236,357 3,707,571 1,897,842
Delaware Basin (2)
- 30,488 101,740
Northwest Shelf 2,954,697 2,875,262 2,513,028
Total 7,191,054 6,613,321 4,512,610
Daily production (Boe/d)
Central Basin Platform 11,575 10,158 5,200
Delaware Basin (2)
- 84 279
Northwest Shelf 8,073 7,877 6,885
Total 19,648 18,119 12,364
(1) Due to our acquisition of Stronghold's assets, which reported its volumes and revenues on a three-stream basis, beginning July 1, 2022, we began reporting volumes and revenues on a three-stream basis, separately reporting crude oil, natural gas, and NGL sales. For periods prior to July 1, 2022, sales and reserve volumes, prices, and revenues for NGLs were presented with natural gas.
(2) The Delaware Basin assets were sold with a closing date of May 11, 2023 and an effective date of March 1, 2023.
Production Prices and Production Costs
The following tables provides historical pricing and costs statistics for the years ended December 31, 2024, 2023, and 2022.
Years ended December 31,
2024 2023 2022
Average sales price:
Oil (per Bbl)
$ 74.87 $ 76.21 $ 92.80
Natural gas (per Mcf) (1)
$ (1.44) $ 0.05 $ 4.57
NGL (per Bbl) (1)
$ 9.23 $ 11.95 $ 20.18
Total (per Boe)
$ 50.94 $ 54.60 $ 76.95
(1) Due to our acquisition of Stronghold's assets, which reported its volumes and revenues on a three-stream basis, beginning July 1, 2022, we began reporting volumes and revenues on a three-stream basis, separately reporting crude oil, natural gas, and NGL sales. For periods prior to July 1, 2022, sales and reserve volumes, prices, and revenues for NGLs were presented with natural gas.
Years ended December 31,
2024 2023 2022
Average production costs (per Boe):
Lease operating expenses
$ 10.89 $ 10.61 $ 10.57
Gathering, transportation and processing costs
$ 0.07 $ 0.07 $ 0.41
Ad valorem taxes (including methane tax) $ 1.12 $ 1.02 $ 1.04
Methane tax (2)
$ 0.07 $ - $ -
Ad valorem taxes (excluding methane tax) $ 1.05 $ 1.02 $ 1.04
Production taxes
$ 2.24 $ 2.74 $ 3.80
(2) In accordance with the IRA, the EPA implemented a waste emission charge ("WEC") on methane emitted from applicable oil and gas facilities that exceed certain thresholds. The methane charge became effective in 2024 at $900 per metric ton of methane, and is set to increase to $1,200 per metric ton of methane for 2025, and $1,500 per metric ton of methane by 2026 and thereafter. For the year ended December 31, 2024, we accrued for $527,687 in methane taxes within Ad valorem taxes in our Statements of Operations.
The average oil sales price amounts above are calculated by dividing revenue from oil sales by the volume of oil sold, in Bbls. The average natural gas sales price amounts above are calculated by dividing revenue from natural gas sales by the volume of natural gas sold, in Mcf. The average NGL sales price amounts above are calculated by dividing revenue from NGL sales by the volume of NGLs sold, in Bbls. The total average sales price amounts are calculated by dividing total revenues by total volume sold, in Boe. The average production costs above are calculated by dividing production costs by total production in Boe.
Productive Wells
The following table presents our ownership as of December 31, 2024 in productive oil and natural gas wells (a net well is our percentage ownership of a gross well). Approximately 99.8% of such wells are in the Permian Basin in Texas.
Oil Wells Gas wells Total Wells
Gross Net Gross Net Gross Net
914 746 21 17 935 763
Drilling Activities
During 2024, as operator, we drilled a total of 44.00 gross (43.94 net) wells. Of this, 5.00 gross (4.94 net) horizontal San Andres wells were in the Northwest Shelf in Yoakum County (four 1.0-mile laterals and one 1.5-mile lateral) and 39.00 gross (39.00 net) wells were in the Central Basin Platform, of which seventeen were horizontal San Andres wells in Andrews County and Crane County, Texas (all 1.0-mile laterals) and 22.00 were vertical wells in Crane County, and Ector County, Texas. These wells were successful and there were no dry wells (1).
The table below contains information regarding the number of operated wells drilled and/or participated in during the periods indicated.
For the year ended December 31,
2024 2023 2022
Gross Net Gross Net Gross Net
Exploratory
Productive - - - - - -
Dry - - - - - -
Development
Productive (1)
43.00 42.94 31.00 29.75 32.00 31.35
Dry - - - - - -
Total
Productive 43.00 42.94 31.00 29.75 32.00 31.35
Dry - - - - - -
(1) One of the 44.00 drilled wells has been drilled but not yet completed as of December 31, 2024.
The table below contains information regarding the number of non-operated wells drilled and participated in during the periods indicated.
For the year ended December 31,
2024 2023 2022
Gross Net Gross Net Gross Net
Exploratory
Productive - - - - - -
Dry - - - - - -
Development
Productive - - 5.00 0.59 3.00 0.33
Dry - - - - - -
Total
Productive - - 5.00 0.59 3.00 0.33
Dry - - - - - -
Present Activities
We had one operated well waiting on completion as of December 31, 2024.
Cost Information
We conduct our oil and natural gas activities entirely in the United States. As can be calculated from the table under “Production Prices and Production Costs”, our average production costs including lease operating expenses, gathering, transportation and transportation ("GTP") and ad valorem, per Boe, were $12.08 and $11.70 for the years ended December 31, 2024 and 2023, respectively. As shown in the aforementioned table, our average production taxes, per Boe,
were $2.24 and $2.74 for the years ended December 31, 2024 and 2023, respectively. These amounts are calculated by dividing our total production costs or total production taxes by our total volume sold, in Boe.
Costs incurred for property acquisition, exploration and development activities for the years ended December 31, 2024, 2023 and 2022 are shown below:
2024 2023 2022
Payments to acquire oil and natural gas properties
$ 2,210,826 $ 82,900,900 $ 179,387,490
Payments to explore oil and natural gas properties
- - -
Payments to develop oil and natural gas properties 153,945,456 152,559,314 129,332,155
Total costs incurred
$ 156,156,282 $ 235,460,214 $ 308,719,645
Other Properties and Commitments
Effective January 1, 2021, the Company moved its corporate headquarters to The Woodlands, Texas. Prior to this, our principal offices were in Midland, Texas. Those offices now serve as an operations office.

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ITEM 3. LEGAL PROCEEDINGS
Item 3: Legal Proceedings
The Company is a defendant in a lawsuit in Harris County District Court, Houston, Texas, styled EPUS Permian Assets, LLC, v. Ring Energy, Inc., that was filed in July 2021. The plaintiff, EPUS Permian Assets, LLC, claims breach of contract, money had and received by fraudulent inducement, unjust enrichment and constructive trust. The plaintiff is requesting its forfeited deposit of $5,500,000 in connection with a proposed property sale by the Company plus related damages, and attorneys’ fees and costs. The action relates to a proposed property sale by the Company to the plaintiff, which was extended by the Company on several occasions with the plaintiff ultimately failing to perform on the agreement and the Company keeping the deposit. The Company believes that the claims by the plaintiff are entirely without merit and is conducting a vigorous defense and counterclaim. The Company has filed an answer and a counterclaim denying the allegations and asserting affirmative defenses that would bar or substantially limit the plaintiff’s claims, asserting breach of contract and requesting a declaratory judgment and attorneys’ fees and costs. The parties have concluded discovery in the matter and are currently set for trial in the first quarter of 2025.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4: Mine Safety Disclosures
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5: Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market for our Common Stock
Our common stock is listed on the NYSE American under the trading symbol “REI.”
Performance Graph
The following graph reflects a comparison of the cumulative total stockholder return of our common stock relative to the cumulative total returns of the S&P 500 Index and the S&P Oil and Gas Exploration and Production Select Industry Index ("SPSIOP"). The graph assumes the investment of $100 on December 31, 2019 in our common stock and each index and the reinvestment of all dividends, if any. This table is not intended to forecast future performance of our common stock.
The performance graph above is furnished and not filed for purposes of Section 18 of the Exchange Act and will not be incorporated by reference into any registration statement filed under the Securities Act unless specifically identified therein as being incorporated by reference. The performance graph is not solicitation material subject to Regulation 14A of the Exchange Act.
Record Holders
As of March 5, 2025, there were approximately 83 holders of record of our common stock. This is the number of record holders in the records of our transfer agent. It does not include holders of shares via brokerage accounts.
Dividend Policy
We do not currently anticipate paying any cash dividends on our common stock. We currently intend to retain future earnings, if any, to pay down debt and 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, our credit facility contains provisions limiting our ability to pay dividends unless certain conditions are met.
Recent Sales of Unregistered Securities and Use of Proceeds from Registered Securities
The information required by this item was disclosed and reported under Item 3.02, Unregistered Sales of Equity Securities, of our Form 8-K dated August 30, 2022, filed with the SEC on September 6, 2022, which disclosure is incorporated herein by reference.
Issuer Repurchases
We did not make any repurchases of our equity securities during the year ended December 31, 2024.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6: Reserved

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations
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 beliefs 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.
Overview
Ring Energy, Inc. (the "Company," "Ring," "we," "us," "our" and similar terms) is a growth oriented independent oil and natural gas exploration and production company based in The Woodlands, Texas engaged in oil and natural gas development, production, acquisition, and exploration activities currently focused in the Permian Basin of Texas. Our drilling operations target the oil and liquids rich producing formations in the Northwest Shelf and the Central Basin Platform, in the Permian Basin in Texas.
Business Description and Plan of Operation
The Company is focused on balancing the need to reduce long-term debt and further developing our oil and gas properties to maintain or grow our annual production. We intend to achieve both through proper allocation of cash flow generated by our operations and potentially through the sale of non-core assets. We intend to continue evaluating potential transactions to acquire strategic producing assets with attractive acreage positions that can provide competitive returns for our shareholders.
•Growing production and reserves by developing our oil-rich resource base through conventional and horizontal drilling. In an effort to maximize its value and resources potential, Ring intends to drill and develop its acreage base in both the Northwest Shelf and Central Basin Platform assets, allowing Ring to execute on its plan of operating within its generated cash flow.
•Reduction of long-term debt and deleveraging of asset. Ring intends to reduce its long-term debt primarily through the use of excess cash flow and potentially through the sale of non-core assets. The Company believes that with its attractive field level margins, it is positioned to maximize the value of its assets and deleverage its balance sheet. The Company also believes through potential accretive acquisitions and strategic asset dispositions, it can accelerate the strengthening of its balance sheet. During the three months ended December 31, 2024, the Company made net paydowns of $7 million on its revolving line of credit, resulting in the outstanding long-term debt balance of $385 million.
•Employ industry leading drilling and completion techniques. Ring’s executive team intends 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.
•Pursue strategic acquisitions with attractive upside potential. Ring has a history of acquiring leasehold positions that it believes to have additional resource potential that meet its targeted returns on invested capital and comparable to its existing inventory of drilling locations. We pursue an acquisition strategy designed to increase reserves at attractive finding costs and complement existing core properties. Management intends to continue to pursue strategic acquisitions and structure the potential transactions financially, so they improve our balance sheet metrics and are accretive to shareholders. Our executive team, with its extensive experience in the Permian Basin, has many relationships with operators and service providers in the region.
2024 Developments and Highlights
Drilling and Completion
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.
During the third quarter of 2024, in the Northwest Shelf in Yoakum County, the Company drilled and completed two 1-mile horizontal wells, each with a working interest of 100%, and one 1.5-mile horizontal well with a working interest of approximately 94.2%. Meanwhile, in the Central Basin Platform, the Company drilled and completed six 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 fourth 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 wells in the Central Basin Platform in Andrews County (both with a working interest of 100%). On the southern side of the Central Basin Platform, the Company drilled and completed one vertical well in its Crane County acreage and three vertical wells in its Ector County acreage (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 fourth quarter, and the last well will be completed in 2025.
In summary, for 2024, the Company drilled 22 horizontal wells, 22 vertical wells, and one SWD well, completing all but one horizontal well. The table below sets forth our drilling and completion activities for 2024 by quarter, and full year total through December 31, 2024.
Quarter Area Wells Drilled Wells Completed Drilled Uncompleted ("DUC") (2)
1Q 2024 Northwest Shelf (Horizontal) 2 2 -
Central Basin Platform (Horizontal) 3 3 -
Central Basin Platform (Vertical) 6 6 -
Total (1)
11 11 -
2Q 2024 Northwest Shelf (Horizontal) - - -
Central Basin Platform (Horizontal) 5 5 -
Central Basin Platform (Vertical) 6 6 -
Total 11 11 -
3Q 2024 Northwest Shelf (Horizontal) 3 3 -
Central Basin Platform (Horizontal) 4 2 2
Central Basin Platform (Vertical) 6 6 -
Total 13 11 2
4Q 2024 Northwest Shelf (Horizontal) - - -
Central Basin Platform (Horizontal) 5 6 1
Central Basin Platform (Vertical) 4 4 -
Total 9 10 1
FY 2024
Northwest Shelf (Horizontal) 5 5 -
Central Basin Platform (Horizontal) 17 16 1
Central Basin Platform (Vertical) 22 22 -
Total (1)
44 43 1
(1) First quarter total and full year total do not include one SWD well completed in the Central Basin Platform
(2) Note that the DUC wells represent period-end counts rather than period-to-date totals.
Market Conditions and Commodity Prices
Our financial results depend on many factors, particularly the price of crude oil and natural gas and our ability to market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand both domestically and world wide, which are impacted by many factors. As a result, we cannot accurately predict future commodity prices, and therefore, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our drilling program, production volumes, or revenues.
Average oil and natural gas prices received through 2024 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.
Natural Gas Takeaway Capacity
The Permian Basin has been experiencing a lack of sufficient pipeline transportation that is connected to markets that are purchasing the natural gas produced. This has resulted in negative natural gas prices at times, whereby the seller is
actually paying the purchaser to take the gas. If these depressed or inverted natural gas prices return to the region, our natural gas revenues will continue to be negatively impacted.
Inflation
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. In addition, the attempts to reduce inflation by the U.S. Federal Reserve have resulted in increased interest rates on debt, contributed to debt and equity market volatility, and increased substantially our interest expense. 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.
Results of Operations
The following table sets forth selected operating data for the periods indicated:
For the years ended December 31, 2024 2023 2022
Net production:
Oil (Bbls) 4,861,628 4,579,942 3,459,840
Natural gas (Mcf) 6,423,674 6,339,158 4,088,642
Natural gas liquids (Bbls) 1,258,814 976,852 371,329
Net sales:
Oil $ 363,971,394 $ 349,044,863 $ 321,062,672
Natural gas (9,265,335) 334,175 18,693,631
Natural gas liquids 11,621,355 11,676,963 7,493,234
Average sales price:
Oil (per Bbl) $ 74.87 $ 76.21 $ 92.80
Natural gas (per Mcf) (1.44) 0.05 4.57
Natural gas liquids (Bbl) 9.23 11.95 20.18
Production costs and expenses:
Lease operating expenses $ 78,310,949 $ 70,158,227 $ 47,695,351
Gathering, transportation and processing costs 506,333 457,573 1,830,024
Ad valorem taxes 8,069,064 6,757,841 4,670,617
Oil and natural gas production taxes 16,116,565 18,135,336 17,125,982
Other costs and operating expenses:
Depreciation, depletion and amortization $ 98,702,843 $ 88,610,291 $ 55,740,767
Asset retirement obligation accretion 1,380,298 1,425,686 983,432
Operating lease expense 700,362 541,801 363,908
General and administrative expense ("G&A")
29,640,300 29,188,755 27,095,323
Share-based compensation 5,506,017 8,833,425 7,162,231
G&A excluding share-based compensation
24,134,283 20,355,330 19,933,092
Other income (expense):
Interest income $ 491,946 $ 257,155 $ 4
Interest (expense) (43,311,810) (43,926,732) (23,167,729)
Gain (loss) on derivative contracts (2,365,917) 2,767,162 (21,532,659)
Gain (loss) on disposal of assets 89,693 (87,128) -
Other income 106,656 198,935 -
Provision for Income Taxes $ (20,440,954) $ (125,242) $ (8,408,724)
Year Ended December 31, 2024 Compared to Year Ended December 31, 2023
Oil sales. Oil sales increased approximately $14.9 million to $364.0 million in 2024 from $349.0 million in 2023. The oil sales increased by a volume variance of approximately $21.5 million from an increase in sales volumes to 4,861,628 barrels of oil in 2024 from 4,579,942 barrels of oil in 2023, primarily driven by production from wells within the
assets acquired with the Founders Acquisition (closed in August 2023). Other impacts to revenue volumes include organic growth from workovers, new drills, and other capital expenditures, offset by divestitures completed and natural asset decline. The volume variance was offset by a negative price variance of approximately $(6.5) million from a decrease in the average realized per barrel oil price to $74.87 in 2024 from $76.21 in 2023.
Natural gas sales. Natural gas sales decreased approximately $9.6 million to $(9.3) million in 2024 from $0.3 million in 2023. The natural gas sales decreased by a negative price variance of approximately $(9.6) million, as the average realized per Mcf gas price decreased to $(1.44) in 2024 from $0.05 in 2023. The significant reduction in realized natural gas prices was driven by a lower market index price. 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. 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. This was only slightly offset by the volume variance as the volume increased to 6,423,674 Mcf in 2024 from 6,339,158 Mcf in 2023.
NGL sales. NGL sales decreased approximately $0.1 million to $11.6 million in 2024 from $11.7 million in 2023. NGL sales had a volume variance of approximately $3.4 million, as volumes were 1,258,814 barrels of NGLs in 2024 compared to 976,852 barrels in 2023, with 36% of the increase in barrels due to the assets acquired in the Founders Acquisition in 2023. Offsetting this increase to sales was a negative price variance of approximately $(3.4) million, as the average realized price per barrel of NGLs was $9.23 in 2024 compared to $11.95 in 2023. This was due to a reduction in the gross realized price per NGL barrel to $20.00 in 2024 compared to $21.16 in 2023 coupled with a growth in the average fees per barrel to $(10.77) in 2024 compared to $(9.20) in 2023.
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. 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 to $0.07 in 2024 from $0.07 in 2023. The increase in costs was $30,298 from NGL processing costs and $18,462 from gas processing costs.
Ad valorem taxes. Our total ad valorem taxes increased approximately $1.3 million to $8.1 million in 2024 from $6.8 million in 2023 and increased on a Boe basis to $1.12 in 2024 from $1.02 in 2023. Ad valorem taxes increased $1.1 million due to a full year of taxes for the properties acquired in the Founders Acquisition (i.e. Ector County), $0.1 million in Yoakum County, and $0.1 million in Andrews County, offset by a reduction of $0.5 million in Crane County. Additionally, we have accrued approximately $0.5 million for the waste emissions charge ("WEC") in place for the calendar year 2024.
Oil and natural gas production taxes. Oil and natural gas production taxes as a percentage of oil and natural gas sales decreased to 4.40% in 2024 from 5.02% during 2023. 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 is 4.7%, which is in line with the historical rates.
Depreciation, depletion and amortization. Our depreciation, depletion and amortization expense increased approximately $10.1 million to $98.7 million in 2024 from $88.6 million in 2023, with $9.8 million of the increase from depletion on our oil and natural gas properties, $0.3 million from amortization of financing lease assets, and $0.04 million from depreciation of fixed assets. The increase in depletion was primarily due to a volume variance of $7.6 million was from an increase of 577,733 in Boe produced. Additionally, depletion experienced a price variance of $2.2 million, from a higher depletion expense per unit overall year over year, due to an 18.9 million increase in average estimated costs of property coupled with a 1.6 million reduction in the amortization base (Boe). Our average depreciation, depletion and amortization per Boe increased to $13.73 per Boe during 2024 from $13.40 per Boe during 2023.
Asset retirement obligation accretion. Our asset retirement obligation (“ARO”) accretion decreased by $45,388 to $1,380,298 in 2024 from $1,425,686 in 2023. The primary drivers in this reduction of ARO accretion were the sale of our operated New Mexico assets, which closed in September of 2023 and the divestiture of our Delaware Basin assets, which closed in May 2023, along with other wells sold. This was offset by additional ARO accretion from wells acquired in the Founders Acquisition, which closed in August 2023, as well as new wells drilled in 2024.
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.
General and administrative expenses (including share-based compensation). General and administrative expenses increased approximately $0.5 million to $29.6 million in 2024 from $29.2 million in 2023. The increase was primarily related to an increase of $3.1 million increase in salaries, wages, and bonuses in 2024 coupled with the $0.6 million G&A costs reduction in 2023 related to the employee retention tax credit. This was offset by a $3.3 million reduction in share-based compensation.
Interest income. Interest income increased by $234,791 to $491,946 in 2024 from $257,155 in 2023. This was driven by the increase of $239,797 in sweep accounts interest income and $25,834 for severance tax refund interest income, offset by a decrease of $29,042 from the employee retention tax credit interest income of 2023, as well as $1,798 from the interest earned on the escrow deposit made for the Founders Acquisition in 2023.
Interest expense. Interest expense decreased approximately $0.6 million to $43.3 million in 2024 from $43.9 million in 2023. The decrease was primarily the result of the deferred cash payment accretion of $0.6 million which was incurred in 2023, which was not required in 2024. Other changes include reductions in interest from our long-term credit facility, offset by an increase of interest on royalty suspense and deferred financing costs.
Gain (loss) on derivative contracts. During 2024, the Company incurred a loss on derivative contracts of approximately $2.4 million. During 2023, the Company recorded a gain on derivative contracts of approximately $2.8 million. For the derivative contract settlements, the Company recorded a realized loss of $5.2 million during 2024 and a realized loss of $9.1 million during 2023. The decrease of $3.9 million in the realized loss was $1.1 million from realized oil derivative settlements and $2.8 million from realized natural gas derivative settlements. For the marked-to-market contracts, the Company recorded an unrealized gain of $2.8 million during 2024 and an unrealized gain of $11.9 million during 2023. This change of approximately $9.0 million in unrealized derivatives was from $2.6 million in unfavorable derivative portfolio changes and futures pricing for marked-to-market oil derivative contracts, as well as $6.4 million unfavorable changes to the marked-to-market natural gas derivative contract balance.
Gain (loss) on disposal of assets. Gain (loss) on disposal of assets increased $176,821 to a gain $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, as opposed to a loss on disposal of assets primarily from selling multiple company owned vehicles during 2023.
Other income. Other income decreased $92,279 to $106,656 in 2024 from $198,935 in 2023. The decrease primarily resulted from the termination of The Woodlands office operating lease in 2023. Offsetting this reduction was a higher bank rebate related to the use of a vendor payment program earned in 2024 compared to 2023.
Provision for income taxes. The provision for income taxes changed to a provision of $20,440,954 for 2024 from a provision of $125,242 for 2023. The provision for income taxes was calculated using the annual effective tax rate method based on our estimated earnings and estimated state and federal income taxes due for 2024, taking into account all applicable tax rates and laws.
Net income. The Company achieved net income of $67,470,314 in 2024 compared to net income of $104,864,641 in 2023. The decrease in income associated with operations was due to increased LOE costs, ad valorem taxes, and depletion, depreciation, and amortization costs. This was offset by increased oil sales and also lower production taxes as a result of prior period refunds. A change in derivatives position from gain to loss further caused the reduction of net income. The 2024 income tax provision was a significant change from year to year impacting the overall decrease in net income realized by the Company.
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.
Provision for income taxes. The provision for income taxes changed to a provision of $125,242 for 2023 from a provision of $8,408,724 for 2022. The current year change in the Company's federal tax provision was the result of a full valuation allowance release on federal taxes in 2023 with state tax activity recognized.
Net income. The Company achieved net income of $104,864,641 in 2023 compared to net income of $138,635,025 in 2022 compared. The decrease in net income was due to increased LOE costs, depletion, depreciation, and amortization costs, and interest expense and lower natural gas revenues. This was offset by increased oil and NGL revenues in addition to a more favorable derivative contract portfolio in comparison with the year-end commodity futures prices.
Liquidity and Capital Resources
Financing of Operations. We have historically funded our operations through cash available from operations and from equity offerings of our stock. Our primary source of cash in 2024 was from funds generated from the sale of oil and natural gas production. These cash flows were primarily used to fund our capital expenditures and pay down our debt balance. We believe the combination of the sources of capital discussed will continue to be adequate to meet our short and long-term liquidity needs.
Credit Facility. On July 1, 2014, the Company entered into a Credit Agreement with SunTrust Bank (now Truist Bank), as lender, issuing bank and administrative agent for several banks and other financial institutions and lenders (the “Administrative Agent”), (which was amended several times) that provided for a maximum borrowing base of $1 billion with security consisting of substantially all of the assets of the Company. In April 2019, the Company amended and restated the Credit Agreement with the Administrative Agent (as amended and restated, the “Amended Credit Facility”).
On August 31, 2022, the Company modified its Amended Credit Facility through that certain Second Amended and Restated Credit Agreement (the "Second Credit Agreement"), extending the maturity date of the facility to August 2026 and the syndicate was modified to add five lenders, replacing five lenders. On February 12, 2024, the Company, Truist Bank as the Administrative Agent and Issuing Bank, and the lenders party thereto (the "Lenders") entered into an amendment (the "Amendment") to the Second Credit Agreement. Among other things, the Amendment amends the definition of Free Cash Flow so amounts used by the Company for acquisitions will no longer be subtracted from the calculation of Free Cash Flow.
The Second Credit Agreement has a borrowing base of $600 million, which is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time. The borrowing base is redetermined semi-annually each May and November. The borrowing base is subject to reduction in certain circumstances such as the sale or disposition of certain oil and gas properties of the Company and cancellation of certain hedging positions.
Rather than Eurodollar loans, the reference rate in the Second Credit Agreement is the SOFR. Also, the Second Credit Agreement permits the Company to declare dividends for its equity owners, subject to certain limitations, including (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, depreciation 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 the Second Credit Agreement), and (iv) the Borrowing Base Utilization Percentage (as defined in the Second Credit Agreement) is not greater than 80%.
The interest rate on each SOFR Loan will be the adjusted term SOFR for the applicable interest period plus a margin between 3.0% and 4.0% (depending on the then-current level of borrowing base usage). The annual interest rate on each base rate loan is (a) the greatest of (i) the Administrative Agent’s prime lending rate, (ii) the Federal Funds Rate (as defined in the Second Credit Agreement) plus 0.5% per annum, (iii) the adjusted term SOFR determined on a daily basis for an interest period of one month, plus 1.00% per annum and (iv) 0.00% per annum, plus (b) a margin between 2.0% and 3.0% per annum (depending on the then-current level of borrowing base usage).
The Second Credit Agreement contains certain covenants, which, among other things, require the maintenance of (i) a total Leverage Ratio of not more than 3.0 to 1.0 and (ii) a minimum ratio of Current Assets to Current Liabilities (as such terms are defined in the Second Credit Agreement) of 1.0 to 1.0. The Second Credit Agreement also contains other customary affirmative and negative covenants and events of default. The Company is required to maintain on a rolling 24 months basis, hedging transactions in respect of crude oil and natural gas, on not less than 50% of the projected production from its proved, developed, and producing oil and gas. However, if the borrowing base utilization is less than 25% at the hedge testing date and the Leverage Ratio is not greater than 1.25 to 1.00, the required hedging percentage for months 13 through 24 of the rolling 24 month period provided for will be 0% from such hedge testing date to the next succeeding hedge testing date and if the borrowing base utilization percentage is equal to or greater than 25%, but less than 50% and the Leverage Ratio is not greater than 1.25 to 1.00, the required hedging percentage for months 13 through 24 of the rolling 24 month period provided for will be 25% from such hedge testing date to the next succeeding hedge testing date.
As of December 31, 2024, $385 million was outstanding on the Credit Facility and the Company was in compliance with all covenants in the Second Credit Agreement.
Equity Offering. In October 2020, the Company closed on an underwritten public offering of (i) 9,575,800 Common Shares, (ii) 13,428,500 Pre-Funded Warrants and (iii) 23,004,300 Common Warrants at a combined purchase price of $0.70. This includes a partial exercise of the over-allotment. The Common Warrants have a term of five years and an exercise price of $0.80 per share. Gross proceeds totaled $16,089,582.
Concurrently with the underwritten public offering, the Company closed on a registered direct offering of (i) 3,500,000 Common Shares, (ii) 3,300,000 Pre-Funded Warrants and (iii) 6,800,000 Common Warrants at a combined
purchase price of $0.70. The Common Warrants have a term of five years and an exercise price of $0.80 per share. Gross proceeds totaled $4,756,700.
Total gross proceeds from the 2020 underwritten public offering and the registered direct offering aggregated $20,846,282. Total net proceeds for the Common Warrants exercised in 2020 aggregated $19,379,832.
The Common Shares of 9,575,800 and 3,500,000 were issued in 2020. The Pre-Funded Warrants of 3,300,000 were exercised and common stock was issued in 2020. The Pre-Funded Warrants of 13,428,500 were exercised and common stock was issued in 2021, as shown in our Statement of Stockholders' Equity. Of the aforementioned 23,004,300 Common Warrants, 442,600 were exercised and common stock was issued in 2021; 10,253,907 were exercised and common stock was issued in 2022; and 19,029,593 were exercised and common stock was issued in 2023 (4,517,427 exercised at $0.80 and 14,512,166 exercised at $0.62 - refer to NOTE 11 - STOCKHOLDERS' EQUITY), and no Common Warrants were exercised during 2024; as shown in our Statement of Stockholders' Equity.
Issuance of Common Stock and Convertible Preferred Stock for Stronghold Acquisition. As part of the consideration for the Stronghold Acquisition, on August 31, 2022 the Company issued 21,339,986 shares of common stock and 153,176 shares of newly created Series A Convertible Preferred Stock, which was converted into 42,548,892 shares of common stock on October 27, 2022.
Cash Flows. Historically, primary sources of cash have been from operations, equity offerings and borrowings on the Credit Facility. During 2024, 2023, and 2022 we had net cash provided by operating activities of $194.4 million, $198.2 million, and $197.0 million, respectively. During the three years ended December 31, 2024, we financed $20.5 million through proceeds from the sale of common stock. During 2024, 2023, and 2022, the Company had a net repayment of $40.0 million, a net draw of $10.0 million, and a net draw of $125.0 million on the Credit Facility, respectively. We used cash to fund our capital expenditures and development aggregating $700.3 million over the three years ended December 31, 2024. Additionally, during 2024, 2023 and 2022, we used cash of $170.0 million, $215.0 million and $511.0 million, respectively, to reduce the outstanding balance on our Credit Facility. As of December 31, 2024, we had cash on hand of $1.9 million and negative working capital of $54.6 million, compared to cash on hand of $0.3 million and negative working capital of $57.9 million as of December 31, 2023 and cash on hand of $3.7 million and negative working capital of $78.6 million as of December 31, 2022.
Contractual Obligations. The Company maintains a Credit Facility which currently has a $600 million borrowing base. The outstanding balance on that Credit Facility as of December 31, 2024 was $385 million, which will require repayment or refinancing at or prior to maturity in August 2026.
The Company leases office spaces in The Woodlands, Texas and Midland, Texas. The Woodlands office was under a five-and-a-half-year lease beginning January 15, 2021; however, effective as of May 31, 2023, The Woodlands office sub-lease was terminated. On May 9, 2023, the Company entered into a 71-month (five years and 11-month) new lease for a larger amount of office space in The Woodlands, Texas. The Midland office lease was amended effective October 1, 2022, with the revised five-year lease ending September 30, 2027.
The Company has financing leases for vehicles with varying maturity dates through 2027. Future lease payments for financing leases aggregate $1,667,763.
Effects of Inflation and Pricing
The oil and natural gas industry is cyclical and the demand for goods and services of oil field companies, suppliers, and others associated with the industry puts significant pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do associated costs. Material changes in prices impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, and the value of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money, and retain personnel. We anticipate business costs will vary in accordance with commodity prices for oil and natural gas, and the associated increase or decrease in demand for services related to production and exploration.
Off-Balance Sheet Financing Arrangements
As of December 31, 2024, we had no off-balance sheet financing arrangements.
Critical Accounting Policies and Estimates
Our discussion of financial condition and results of operations is based upon the information reported in our financial statements. The preparation of these statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, weather, politics, global economics, mechanical problems, general business conditions, and other factors. Our significant accounting policies, as well as considerations of recent accounting pronouncements, are detailed in "NOTE 1 - ORGANIZATION, BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES" to our financial statements included in this Annual Report. We have outlined below certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management.
Oil and Natural Gas Reserve Quantities. Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. Reserve quantities and future cash flows included in this Annual Report are prepared in accordance with guidelines established by the SEC and FASB. The accuracy of our reserve estimates is a function of:
•the quality and quantity of available data;
•the interpretation of that data;
•the accuracy of various mandated economic assumptions; and
•the judgments of the persons preparing the estimates.
Our proved reserve information included in this Annual Report was prepared and determined by Cawley, Gillespie & Associates, Inc., independent petroleum engineers. Because these estimates depend on many assumptions, all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered. We continually make revisions to reserve estimates throughout the year as additional properties are acquired. We make changes to depletion rates and impairment calculations in the same period that changes to the reserve estimates are made.
All capitalized costs of oil and natural gas properties, including the estimated future costs to develop proved reserves and estimated future costs to plug and abandon wells and costs of site restoration, less the estimated salvage value of equipment associated with the oil and natural gas properties, are amortized on the unit-of-production method using estimates of proved reserves as determined by independent petroleum engineers. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined.
Ceiling Test of Oil and Natural Gas Properties. Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly utilizing the average of prices in effect on the first day of the month for the preceding twelve-month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10%, plus the lower of cost or market value of unproved properties, less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depletion, depreciation and amortization (“DD&A”) rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling.
The Company did not have any write-downs related to the full cost ceiling limitation during the years ended December 31, 2024, 2023, or 2022.
Our estimates of reserves and future cash flow as of December 31, 2024 and 2023 were prepared using an average price equal to the unweighted arithmetic average of the first day of the month price for each month within the 12-month periods ended December 31, 2024 and 2023, respectively, in accordance with SEC guidelines. As of December 31, 2024,
our reserves were based on an SEC average price of $71.96 per Bbl of WTI oil posted and $2.130 per MMBtu Henry Hub natural gas. As of December 31, 2023, our reserves were based on an SEC average price of $74.70 per Bbl of WTI oil posted and $2.637 per MMBtu Henry Hub natural gas. Prices are adjusted by local field and lease level differentials and are held constant for life of reserves in accordance with SEC guidelines.
Income Taxes. Deferred income taxes are provided on differences between the tax basis of assets and liabilities and their carrying amounts in the financial statements, and tax carryforwards. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is settled. Since our tax returns are filed after the financial statements are prepared, estimates are required in valuing tax assets and liabilities. We record adjustments to the actual values in the period the Company files its tax returns.
In assessing the Company's deferred tax assets, we consider whether a valuation allowance should be recorded for some or all of the deferred tax assets which may not be realized. The ultimate realization of deferred tax assets is assessed at each reporting period and is dependent upon the generation of future taxable income and the Company's ability to utilize net operating loss carryforwards during the periods in which the temporary differences become deductible. We also consider the reversal of deferred tax liabilities and available tax planning strategies. As of December 31, 2024 and 2023, the Company did not carry a valuation allowance against its federal and state deferred tax assets.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A: Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Market risk refers to the risk of loss from adverse changes in oil and natural gas prices. Realized pricing is primarily driven by the prevailing domestic price for crude oil and spot prices applicable to the region in which we produce oil and natural gas. Historically, prices received for oil and natural gas production have been volatile and unpredictable. We expect pricing volatility to continue.
The prices we receive depend on many factors outside of our control. Oil prices received during 2024 ranged from a monthly average low of $67.84 per barrel to a monthly average high of $84.43 per barrel. Natural gas prices realized during 2024 ranged from a monthly average low of $(2.38) per Mcf to a monthly average high of $0.91 per Mcf. In some months, fees exceeded the pricing, causing a negative net realized price. Gross natural gas prices ranged from a monthly average low of $(0.82) per Mcf to a monthly average high of $2.43 per Mcf. Fees ranged from a monthly average low of $(1.88) per Mcf to a monthly average high of $(1.44) per Mcf. NGL prices received during 2024 ranged from a monthly average low of $7.04 per barrel to a monthly average high of $12.43 per barrel. A significant decline in the prices of oil or natural gas would likely have a material adverse effect on our financial condition and results of operations. In order to reduce commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas, we enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production. The following table summarizes the Company's hedges in place on a monthly basis by commodity type. See "NOTE 7 - DERIVATIVE FINANCIAL INSTRUMENTS" to our financial statements for further information.
Oil Hedges (WTI) Gas Hedges (Henry Hub)
Month Average BBL/day Average MMBtu/day
January 2025 7,420 -
February 2025 10,939 8,557
March 2025 9,963 7,558
April 2025 10,008 7,643
May 2025 9,616 7,248
June 2025 9,684 7,350
July 2025 9,333 6,987
August 2025 9,203 6,863
September 2025 9,290 6,970
October 2025 8,977 6,632
November 2025 9,071 6,743
December 2025 8,779 6,500
January 2026 5,211 6,327
February 2026 5,681 6,904
March 2026 5,056 6,150
April 2026 5,150 6,257
May 2026 4,914 5,971
June 2026 5,010 6,083
July 2026 4,781 5,809
August 2026 4,721 5,732
September 2026 4,817 5,846
October 2026 4,603 5,584
November 2026 4,700 5,703
December 2026 4,494 5,455
Customer Credit Risk
Our principal exposure to credit risk is through receivables from the sale of our oil and natural gas production (approximately $33.8 million as of December 31, 2024). We are subject to credit risk due to the concentration of our oil and natural gas receivables with our most significant customers, or purchasers. We do not require our purchasers to post collateral, and the inability of our significant purchasers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. The following table sets forth certain information regarding the top three purchasers of our oil, natural gas, and NGLs for the year ended December 31, 2024. We believe that the loss of any of these purchasers would not materially impact our business because we could readily find other purchasers for our oil and natural gas.
For the Year Ended
As of
December 31, 2024
December 31, 2024
Percentage of Oil, Natural Gas, and Natural Gas Liquids Revenues
Percentage of accounts receivables from the sale of our oil and natural gas production
Purchaser:
Phillips 66 Company ("Phillips")
61%
64%
Concord Energy LLC ("Concord") 14% 11%
LPC Crude III, LLC ("LPC") 13% 11%
Interest Rate Risk
We are subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility, which bears variable interest based upon a prime rate and is therefore susceptible to interest rate fluctuations. Changes in interest rates affect the interest earned on the Company’s cash and cash equivalents and the interest rate paid on borrowings under the Credit Facility.
As of December 31, 2024, we had $385 million outstanding on our Credit Facility with a weighted average annual interest rate for the year then ended of 9.2%. A 1% change in the interest rate on our Credit Facility would result in an estimated $3.9 million change in our annual interest expense. See "NOTE 9 - REVOLVING LINE OF CREDIT" in the notes to the financial statements for more information on the Company’s interest rates of our Credit Facility.
Currently, we do not use interest rate derivative instruments to manage exposure to interest rate changes.
Currency Exchange Rate Risk
Foreign sales accounted for none of the Company's sales; the Company accepts payment for its commodity sales only in U.S. dollars. Ring is therefore not exposed to foreign currency exchange rate risk on these sales.
Please also see Item 1A “Risk Factors” above for a discussion of other risks and uncertainties we face in our business.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8: Financial Statements and Supplementary Data
The financial statements and supplementary data required by this item are included beginning at page of this Annual Report.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9: Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A: Controls and Procedures
Evaluation of disclosure controls and procedures.
Under the direction of our Chief Executive Officer and Chief Financial Officer, we have established disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.
As of December 31, 2024, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that as of December 31, 2024, our disclosure controls and procedures are effective.
Changes in internal control over financial reporting.
We regularly review our system of internal control over financial reporting and make changes to our processes and systems to improve controls and increase efficiency, while ensuring that we maintain an effective internal control environment. Changes may include such activities as implementing new, more efficient systems, consolidating activities, and migrating processes.
There were no changes in our internal control over financial reporting that occurred during the fourth quarter ended December 31, 2024 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Annual Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal controls over financial reporting. Our internal control system is designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Furthermore, the effectiveness of a system of internal control over financial reporting in future periods can change as conditions change.
In making our assessment of internal control over financial reporting, our management used the criteria issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework (2013). Based on our assessment, we believe that, as of December 31, 2024, our internal control over financial reporting is effective based on those criteria.
The independent registered public accounting firm, Grant Thornton LLP, has audited the financial statements and internal control over financial reporting included in this Annual Report on Form 10-K, and has issued their report on the effectiveness of the Company’s internal control over financial reporting at December 31, 2024. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting at December 31, 2024, is set forth below.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Ring Energy, Inc.
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of Ring Energy, Inc. (a Nevada corporation) (the “Company”) as of December 31, 2024, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on criteria established in the 2013 Internal Control-Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the financial statements of the Company as of and for the year ended December 31, 2024, and our report dated March 5, 2025 expressed an unqualified opinion on those financial statements.
Basis for opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and limitations of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ GRANT THORNTON LLP
Houston, Texas
March 5, 2025

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ITEM 9B. OTHER INFORMATION
Item 9B: Other Information
During the quarter ended December 31, 2024, none of our directors or officers (as defined in Rule 16a-1(f) of the Securities Exchange Act of 1934) adopted, terminated or modified a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K).

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10: Directors, Executive Officers and Corporate Governance
The information required by this item, including information on our insider trading policy under the caption "Insider Trading Policy," is incorporated by reference herein from the Company's 2025 Proxy Statement to be filed with the SEC no later than 120 days after December 31, 2024. If the Proxy Statement is not filed with the SEC by such time, such information will be included in an amendment to this Annual Report by such time.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11: Executive Compensation
The information required by this item is incorporated by reference herein from the Company's 2025 Proxy Statement to be filed with the SEC no later than 120 days after December 31, 2024. If the Proxy Statement is not filed with the SEC by such time, such information will be included in an amendment to this Annual Report by such time.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12: Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by this item is incorporated by reference herein from the Company's 2025 Proxy Statement to be filed with the SEC no later than 120 days after December 31, 2024. If the Proxy Statement is not filed with the SEC by such time, such information will be included in an amendment to this Annual Report by such time.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13: Certain Relationships and Related Transactions, and Director Independence
The information required by this item is incorporated by reference herein from the Company's 2025 Proxy Statement to be filed with the SEC no later than 120 days after December 31, 2024. If the Proxy Statement is not filed with the SEC by such time, such information will be included in an amendment to this Annual Report by such time.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14: Principal Accountant Fees and Services
The information required by this item is incorporated by reference herein from the Company's 2025 Proxy Statement to be filed with the SEC no later than 120 days after December 31, 2024. If the Proxy Statement is not filed with the SEC by such time, such information will be included in an amendment to this Annual Report by such time.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15: Exhibits and Financial Statement Schedules
Incorporated by Reference
Exhibit
Number Exhibit Description Form File No. Exhibit Filing Date Filed
Here-with Furn-ished Here-with
2.1 Purchase and Sale Agreement dated July 1, 2022, by and among Ring Energy, Inc., Stronghold Energy II Operating, LLC, a Delaware limited liability company (“Stronghold OpCo”) and Stronghold Energy II Royalties, LP, a Delaware limited partnership, including the following Exhibits thereto: Exhibit I - Form of Registration Rights Agreement, Exhibit K - Form of Nomination Agreement, Exhibit L - Form of Certificate of Designation and Exhibit M - Form of Lock-Up Agreement
8-K 001-36057 2.1 7/8/22
2.2 First Amendment to Purchase and Sale Agreement by and among Stronghold Energy II Operating, LLC, Stronghold Energy II Royalties, LP, and Ring Energy, Inc., dated August 4, 2022
8-K 001-36057 2.1 8/9/22
2.3 Asset Purchase Agreement dated July 10, 2023 between Ring Energy, Inc. and Founders Oil & Gas IV, LLC.
8-K
001-36057
2.1 7/14/23
2.4 Purchase and Sale Agreement dated as of February 25, 2025 by and among Ring Energy, Inc., Lime Rock Resources IV-A, L.P., and Lime Rock Resources IV-C, L.P.
8-K
001-36057
2.1 2/28/25
3.1 Articles of Incorporation (as amended)
10-K 000-53920 3.1 4/1/13
3.2 Certificate of Amendment to the Articles of Incorporation, as amended, of Ring Energy, Inc.
8-K 001-36057 3.1 12/17/21
3.3 Certificate of Amendment to the Articles of Incorporation, as amended, of Ring Energy, Inc.
8-K
001-36057
3.1 5/26/23
3.4 Bylaws of Ring Energy, Inc. as amended April 13, 2021
8-K 001-36057 3.1 4/15/21
3.5 Certificate of Designation of the Series A Convertible Preferred Stock dated August 30, 2022
8-K 001-36057 3.1 9/6/22
3.6 Certificate of Withdrawal of Certificate of Designation filed with the Secretary of State of Nevada effective October 31, 2022
8-K 001-36057 3.1 10/31/22
4.1 Description of Ring Energy, Inc. equity securities registered under Section 12(b) of the Securities Exchange Act of 1934, as amended
10-K
001-36057 4.2 3/7/24
4.2 Securities Purchase Agreement, dated October 27, 2020
8-K 001-36057 4.1 10/29/20
10.1* Executive Employment and Severance Agreement, dated as of September 30, 2020, by and between the Company and Stephen D. Brooks
8-K 001-36957 10.1 12/4/20
10.1(a)*
Consulting Agreement, dated July 1, 2024 by and between Ring Energy, Inc. and Stephen D. Brooks.
8-K 001-36957 10.1 7/3/24
Incorporated by Reference
Exhibit
Number Exhibit Description Form File No. Exhibit Filing Date Filed
Here-with Furn-ished Here-with
10.2* Executive Employment and Severance Agreement, dated as of September 30, 2020, by and between the Company and Paul D. McKinney
8-K 001-36957 10.1 10/6/20
10.3* Employment and Severance Agreement, dated as of September 30, 2020, by and between the Company and Alexander Dyes
8-K 001-36057 10.1 12/22/20
10.4* Employment and Severance Agreement, dated as of September 30, 2020, by and between the Company and Marinos C. Baghdati
8-K 001-36057 10.2 12/22/20
10.5* Ring Energy Inc. Long Term Incentive Plan, as Amended
8-K 000-53920 99.3 1/24/13
10.6* Form of Option Grant for Long-Term Incentive Plan
10-Q 000-53920 10.2 8/14/12
10.7*
Executive Employment and Severance Agreement, dated as of October 26, 2020, by and between the Company and Travis T. Thomas
8-K 001-36057 10.1 3/26/21
10.8 Registration Rights Agreement dated August 31, 2022, by and among Ring Energy, Inc., Stronghold Energy II Operating, LLC, and Stronghold Energy II Royalties, LP.
8-K 001-36057 10.1 9/6/22
10.9 Director Nomination Agreement dated August 31, 2022, by and among Ring Energy, Inc., Stronghold Energy II Operating, LLC, and Stronghold Energy II Royalties, LP.
8-K 001-36057 10.3 9/6/22
10.10 Second Amended and Restated Credit Agreement dated August 31, 2022, by and among Ring Energy, Inc., Truist Bank, and the Lenders from time to time party thereto
8-K 001-36057 10.4 9/6/22
10.11*
Ring Energy, Inc. 2021 Omnibus Incentive Plan
DEF 14A 001-36057 4/22/21
10.12*
Amendment No. 1 to the Ring Energy, Inc. 2021 Omnibus Incentive Plan
8-K
001-36057
10.1 5/26/23
10.13*
Form of Performance Stock Unit Agreement
8-K 001-36057 10.1 11/30/21
10.14*
Form Restricted Stock Unit Agreement (employees)
8-K 001-36057 10.1 2/23/23
10.15*
Form of Restricted Stock Unit Agreement (non-employee directors)
8-K 001-36057 10.2 2/23/23
10.16 Form of Warrant Amendment and Exercise Agreement.
8-K
001-36057
10.1 4/12/23
10.17 First Amendment to Second Amended and Restated Credit Agreement dated as of February 12, 2024, by and among Ring Energy, Inc., Truist Bank, as administrative agent, and the Lenders party thereto.
8-K
001-36057
10.1 2/16/24
10.18 Change in Control and Severance Benefit Plan
10-K
001-36057 10.25 3/7/24
14.1 Code of Ethics
8-K 000-53920 14.1 1/24/13
19.1 Insider Trading Policy
X
Incorporated by Reference
Exhibit
Number Exhibit Description Form File No. Exhibit Filing Date Filed
Here-with Furn-ished Here-with
23.1 Consent of Cawley, Gillespie & Associates, Inc.
X
23.2 Consent of Grant Thornton LLP
X
24.1 Power of Attorney (included as part of the signature pages of this report)
X
31.1 Rule 13a-14(a) Certification by Chief Executive Officer
X
31.2 Rule 13a-14(a) Certification by Chief Financial Officer
X
32.1 Section 1350 Certification of Chief Executive Officer
X
32.2 Section 1350 Certification Chief Financial Officer
X
97.1 Ring Energy, Inc. Clawback Policy
10-K
001-36057 97.1 3/7/24
99.1 Reserve Report of Cawley, Gillespie & Associates, Inc.
X
101.INS Inline XBRL Instance Document X
101.SCH Inline XBRL Taxonomy Extension Schema Document X
101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document X
101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document X
101.LAB Inline XBRL Taxonomy Extension Label Linkbase Document X
101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase Document X
104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
*Management contract