Ring Energy, Inc.: Form 10-K for the period ended Dec 31, 2023

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 and is 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, 2023, our leasehold acreage positions totaled 96,127 gross (80,535 net) acres and we held interests in 1,043 gross (864 net) producing wells. Proved reserves as of December 31, 2023 (based upon the report of our independent petroleum engineer of that date) were approximately 129.8 million Boe, of which we are the operator of approximately 98%. All of our properties are located in the Permian Basin and our proved reserves are oil-weighted, with approximately 63% consisting of oil, 19% consisting of natural gas, and 18% consisting of NGLs. Approximately 68% of the reserves are classified as PD and 32% are classified as PUD. Within the PD reserve category, 242 recompletion and re-activation opportunities are classified as PDNP and within the PUD reserve category, we have a total of 211 proved locations (33% horizontal and 67% vertical) based on the reserve report as of December 31, 2023. We believe our core leasehold in the Northwest Shelf and Central Basin Platform contain additional potential drilling locations. For the calculation of Boe, a barrel of oil is weighted on a 6 to 1 ratio to one thousand cubic feet ("Mcf") of natural gas.

2023 Highlights and Major Developments

• Closed the Founders Acquisition on August 15, 2023
• Achieved record full year production of 18,119 Boepd (69% oil), a year-over-year increase of 47%
• Executed a phased drilling program in 2023 that included drilling 31.00 gross / 29.75 net operated wells consisting of 20.00 horizontal and 11.00 vertical wells (gross). In addition, the Company participated in 5.00 non-operated wells.
• Maintained our revolving credit facility borrowing base of $600 million
• Total Proved Reserves were 129.8 MMBoe at year-end 2023

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, and 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 steadily 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, apply advanced technologies, and continuously seek 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 seeks 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.

Founders Acquisition

On August 15, 2023, the Company, as buyer, and Founders Oil & Gas IV, LLC (“Founders”), as seller, closed the Asset Purchase Agreement (the “Founders Purchase Agreement”) under which the Company acquired (the “Founders Acquisition”) interests in oil and gas leases and related property of Founders in the Central Basin Platform of the Permian Basin in Ector County, Texas.

Common Warrants Exercised

During 2023, the Company reduced its dilutive shares through the exercise of 19,029,593 of the Company's outstanding common warrants, bringing the total outstanding to 78,200 common warrants as of December 31, 2023. This was accomplished by the exercise of 4,517,427 common warrants at an exercise price of $0.80 per share and the exercise of 14,512,166 common warrants at an exercise price of $0.62 per share, through amendments to certain warrant agreements. These exercises resulted in $12,301,596 of net proceeds to the Company after payment of $309,888 in advisory fees.

Primary Business Operations

We seek to rigorously manage our asset portfolio to optimize shareholder value over the long term.

In the first quarter of 2023, in the Northwest Shelf, the Company drilled and completed two 1-mile horizontal wells (each with a working interest of 100%), and two 1.5-mile horizontal wells (one with a working interest of approximately 99.8% and the other with a working interest of approximately 75.4%). Next, in its Crane County acreage within the Central Basin Platform, the Company drilled and completed three vertical wells (each with a working interest of 100%) and performed six vertical well recompletions (each with a working interest of 100%).

In the second quarter of 2023, in the Northwest Shelf, the Company drilled and completed two 1.5-mile horizontal wells (one with a working interest of 100% and the other with a working interest of approximately 75.4%) and two 1-mile horizontal wells (both with a working interest of approximately 91.1%). Additionally, in its Crane County acreage within the Central Basin Platform, the Company drilled and completed two vertical wells (each with a working interest of 100%) and performed three vertical well recompletions (each with a working interest of 100%).

During the third quarter of 2023, the Company drilled and completed two 1-mile horizontal wells (one with a working interest of 100% and the other with a working interest of 75%) in the Northwest Shelf, and three 1.5-mile horizontal wells (each with a working interest of 100%) in the Central Basin Platform. Additionally, in its Crane County acreage within the Central Basin Platform, the Company drilled and completed three vertical wells (each with a working interest of 100%). Lastly, the Company drilled and began the completion process on three 1-mile horizontal wells in the Northwest Shelf (each with a working interest of 100%).

In the fourth quarter of 2023, the Company completed and placed on production the three aforementioned 1-mile horizontal wells in the Northwest Shelf. Additionally, the Company drilled and completed one saltwater disposal (SWD) well in the Northwest Shelf (with a working interest of 100%), and completed the 2023 horizontal drilling program with one 1.5-mile horizontal well in the Northwest Shelf (with a working interest of approximately 97.7%), as well as two 1-mile horizontal wells and one 1.5-mile horizontal well (each with a working interest of 100%) in the Central Basin Platform. In its Crane County acreage within the Central Basin Platform, the Company drilled and completed three vertical wells (each with a working interest of 100%).

In summary, for 2023, the Company drilled and completed 20 horizontal wells, 11 vertical wells, and 1 SWD well. In addition, the Company performed 9 vertical well recompletions. The table below sets forth our drilling and completion activities for 2023 by quarter, and full year total through December 31, 2023.

(1) Fourth quarter total and full year total do not include one SWD well completed in the Northwest Shelf.

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. These factors can be particularly important in the areas in which we operate. In addition, those companies may be able to pay more for productive 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 which 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 flow-lines 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. In addition, as an ongoing practice, we install vapor recovery units in our newly installed tank batteries which also reduces emissions. Our produced saltwater is generally moved by pipeline connected to our operated saltwater disposal wells or by pipeline 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, 2023, sales to three customers, Phillips 66 Company ("Phillips"), Enterprise Crude Oil LLC ("Enterprise"), and NGL Crude Partners ("NGL Crude"), and represented 66%, 12%, and 10%, respectively, of our oil, natural gas, and natural gas liquids revenues. As of December 31, 2023, Phillips represented 65% of our accounts receivable, Enterprise represented 11% of our accounts receivable and NGL Crude represented 8% of our accounts receivable. 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.

Delivery Commitments

As of December 31, 2023, 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 expenditures needs.

Governmental Regulations

Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by 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. The trend in oil and natural gas regulation has been 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. For example, in January 2021, President Biden signed an Executive Order directing the Department of Interior (the “DOI”) to temporarily pause new oil and gas leases on federal lands and waters pending completion of a comprehensive review of the federal government’s existing oil and gas leasing and permitting program. In June 2021, a federal district court enjoined the DOI from implementing the pause and leasing resumed, although litigation over the leasing pause remains ongoing. In February 2022, another judge ruled that the Biden Administration’s efforts to raise the cost of climate change in its environmental assessments, would increase energy costs and damage state revenues from energy production. This ruling has caused federal agencies to delay issuing new oil and gas leases and permits on federal lands and waters.

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, condensate, 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 the 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, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The 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 the 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 the FERC’s actions will achieve 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 the 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 any states in which we operate and ship natural gas on an intrastate basis 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 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 own and 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. We are not presently aware of any material environmental demands, claims, or adverse actions, litigation or administrative proceedings in which either we or our acquired properties are involved in or subject to, or arising out of any predecessor operations.

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 would 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 would 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 removes 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 gives states two years to develop and submit their plans for reducing methane emissions from existing sources. The final emissions guidelines under Subpart OOOOc provide three years from the plan submission deadline for existing sources to comply. Compliance with these or any new regulations could result in stricter permitting requirements, which in turn could delay or impair our ability to obtain air emission permits and could result in increased expenditures for pollution control equipment, the costs of which could be significant.

On August 16, 2022, President Biden signed the Inflation Reduction Act of 2022 (“IRA”). 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 on methane emitted from applicable oil and gas facilities that exceed certain thresholds. The methane charge goes into effect in 2024 at $900 per metric ton of methane and increases to $1,500 per metric ton of methane by 2026. On January 12, 2024, the EPA announced a proposed rule to implement the methane emissions charge.The charge will act as an incentive for operators to reduce emissions by minimizing leaks and replacing equipment rather than paying for excessive emissions.

While the State of Texas has not formally conducted a 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. 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 may result in increased costs. 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 revises 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. 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. To the extent the rule or any future rule or court decision expands the scope of the CWA’s jurisdiction, we could face increased permitting costs and project delays.

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 are 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.

Local governments may also seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. In Texas, however, local governments are expressly preempted from regulating oil and gas operations with limited exceptions, under Texas Natural Resources Code Section 81.0523. 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 requirements 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 could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities that exceed GHG emission thresholds. 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”). Further, several states and local governments remain committed to the principles of the Paris Agreement in their effectuation of policy and regulations. Although it is not possible at this time to predict what additional domestic legislation may be adopted in light of the Paris Agreement or the

Glasgow Climate Pact, or how legislation or new regulations that may be adopted based on the Paris Agreement or the Glasgow Climate Pact to address GHG emissions would impact our business, 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.

In September 2023, the Biden Administration directed federal agencies to consider the Social Cost of GHGs metric in budgeting, procurement and other agency decisions, including in environmental reviews, where appropriate. Several states, though none in the areas where we operate, have implemented, of their own accord or in coordination with their neighbor states, regional initiatives and programs limiting, monitoring or otherwise regulating GHG emissions.

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. We also are aware that the SEC intends to propose new and additional rules regarding company disclosure of climate change risk. We will monitor and comply with any such promulgated rules.

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 Clean Water Act. 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 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, 2023, we had 108 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.

Diversity and Inclusion: The unique backgrounds and experiences of our employees help to develop a wide range of perspectives that lead to better solutions. Our staff’s diversity is reflected in our full-time employees where 23% are women and approximately 50% represent minorities. The majority of our employees are citizens of the United States, with a few retaining dual citizenship in other countries. The employees who are not US citizens, are legally registered to live and work here and the Company is committed to helping those employees retain their ability to remain in the US and continue their employment. The Company is also committed to continuously providing an inclusive work environment where all of our employees can be respected, valued, and successful in achieving their goals, all while contributing to the Company’s success.

We recognize that attracting, retaining and developing our employees is critical for our future success. Our Executive Vice President of Land, Legal, Human Resources and Marketing, 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:

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 the 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 incidents. 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.

COVID-19 Response: Our COVID-19 management plan was built around the need to support all employees in managing their personal and professional challenges. Frequent and transparent communications are the focus at every level of the organization from those on the front lines to those in our corporate offices. During the early stages of the pandemic, Ring’s management team directed the Company’s overall COVID-19 pandemic response by implementing all relevant county, state and local government guidelines, directives, and regulations, and developed and adopted work-from-home provisions and procedures, implemented safe working protocols for production teams, assessed and implemented appropriate return-to-office protocols, and provided timely and transparent communications to employees and key stakeholders.

In response to the COVID-19 pandemic, Ring began providing the following benefits to its employees:

• covering the cost of COVID-19 testing through expanded insurance coverage;
• promoting telehealth benefits;
• promoting mental health and well-being plans; and
• providing additional paid sick leave for quarantined employees.

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 (http://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.

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 wells include, but are not limited to, the following:

• the ability to fracture or stimulate the planned number of stages in a horizontal or lateral 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 will 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 32%), 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 and thunderstorms), 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 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 likely 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. For example, in January 2021, President Biden signed an Executive Order directing the Department of Interior (the “DOI”) to temporarily pause new oil and gas leases on federal lands and waters pending completion of a comprehensive review of the federal government’s existing oil and gas leasing and permitting program. In June 2021, a federal district court enjoined the DOI from implementing the pause and leasing resumed, although litigation over the leasing pause remains ongoing. In February 2022, another judge ruled that the Biden Administration’s efforts to raise the cost of climate change in its environmental assessments, would increase energy costs and damage state revenues from energy production. This ruling has cause federal agencies to delay issuing new oil and gas leases and permits on federal lands and waters. While we do not have any federal lands acreage at this time, these actions could have a material adverse effect on our industry, the public perception of oil and gas companies such as ours and the willingness of the public and financial institutions to provide capital for our industry.

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 are often 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 take write-downs of the financial carrying values of our oil and natural gas properties which could negatively impact the trading value 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, 2023, 2022, and 2021 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 predict with 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 trading value 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 most likely will 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 properties. All of these factors would have a negative impact on earnings and net income, and most likely the trading 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 to our Company. 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, then 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 sustaining commercial production.

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 may 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 reserves 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.

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 and 2023 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. Wastewaters 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, local, and international 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 frequently, 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 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. However, President Biden has highlighted addressing climate change as a priority of his administration, which includes certain potential initiatives for climate change legislation to be proposed and passed into law. 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. For example, in response to findings that emissions of carbon dioxide, methane, and other GHGs endanger public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish PSD construction and Title V operating permit reviews for certain large stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA for those emissions. These EPA rules could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations.

The federal regulation of methane from oil and gas facilities has been subject to substantial uncertainty in recent years. In June 2016, the EPA finalized NSPS, known as Subpart OOOOa, that establish emission standards for methane and VOCs from new and modified oil and natural gas production and natural gas processing and transmission facilities. In September 2020, the EPA finalized amendments to the 2016 standards that removed the transmission and storage segment from the oil and natural gas source category and rescinded the methane-specific requirements for production and processing facilities. However, President Biden signed an executive order on his first day in office calling for the suspension, revision, or rescission of the September 2020 rule and the reinstatement or issuance of methane emission standards for new, modified and existing oil and gas facilities. Subsequently, the U.S. Congress approved, and President Biden has signed into law, a resolution under the Congressional Review Act to repeal the September 2020 revisions to the methane standards, effectively reinstating the prior standards. In response to President Biden’s executive order calling on the EPA to revisit federal regulations regarding methane, the EPA finalized more stringent methane rules for new, modified, and reconstructed facilities, known as OOOOb, as well as standards for existing sources for the first time ever, known as OOOOc, in December 2023. Under the final rules, states have two years to prepare and submit their plans to impose methane emission controls on existing sources. The presumptive standards established under the final rule are generally the same for both new and existing sources. The requirements include enhanced leak detection survey requirements using optical gas imaging and other advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions, reduction of emissions by 95% through capture and control systems and zero-emission requirements for certain devices. The rule also establishes a “super emitter” response program that would allow third parties to make reports to EPA of large methane emission events, triggering certain investigation and repair requirements. Fines and penalties for violations of these rules can be substantial. It is likely, however, that the final rule and its requirements will be subject to legal challenges. Moreover, compliance with the new rules may affect the amount we owe under the IRA 2022’s methane fee described above because compliance with EPA’s methane rules would exempt an otherwise covered facility from the requirement to pay the methane fee. The requirements of the EPA’s final methane rules have the potential to increase our operating costs and thus may adversely affect our financial results and cash flows. Moreover, failure to comply with these CAA requirements can result in the imposition of substantial fines and penalties as well as costly injunctive relief. However, given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry remain a significant possibility.

Internationally, the United Nations-sponsored “Paris Agreement” requires member states to individually determine and submit non-binding emissions reduction targets every five years after 2020. President Biden has recommitted the United States to the Paris Agreement and, in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. In November 2021, the international community gathered again at COP26, during which multiple announcements were made, including a call for parties to eliminate certain oil and natural gas subsidies and pursue further action on non-CO2 GHGs. These goals were reaffirmed at COP27 in November 2022. 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. At COP28 in December 2023, the parties signed onto an agreement to transition away from fossil fuels in energy systems and increase renewable energy capacity, though no timeline for doing so was set. While non-binding, the agreements coming out of COP28 could result in increased pressure among financial institutions and various stakeholders to reduce or otherwise impose more stringent limitations on funding for and increase potential opposition to the exploration and production of fossil fuels. The impacts of these orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, COP26, COP28 or other international conventions cannot be predicted at this time. Concern over the threat of climate change has also resulted in increasing political risks in the United States, including climate-change related pledges made by President Biden and other public office representatives. On January 27, 2021, President Biden signed an executive order calling for substantial action on climate change, including, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the oil and natural gas industry, and increased emphasis on climate-related risks across agencies and economic sectors. Additionally, in November 2021, the Biden Administration released “The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which establishes a roadmap to net zero emissions in the United States by 2050 through, among other things, improving energy efficiency; decarbonizing energy sources via electricity, hydrogen, and sustainable biofuels; and reducing non-CO2 GHG emissions, such as methane and nitrous oxide.

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. 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. In addition, at COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing and/or underwriting activities to net zero emissions by 2050. These and other developments in the financial sector could lead to some lenders restricting access to capital for or divesting from certain industries or companies, including the oil and natural gas sector, or requiring that borrowers take additional steps to reduce their GHG emissions. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the oil and natural gas industry. For example, the Federal Reserve has joined the Network for Greening the Financial System (“NGFS”), a consortium of financial regulators focused on addressing climate-related risks in the financial sector and, in November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. 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.

New climate disclosure rules proposed by the SEC may increase our costs of compliance and adversely impact our

business.

On March 6, 2024, the SEC adopted new rules relating to the disclosure of a range of climate-related risks. We are currently assessing the final rule, but at this time we cannot predict the costs of implementation or any potential adverse impacts resulting from the rule. As a result of this rule, we could incur increased costs relating to the assessment and disclosure of climate-related risks, including increased legal, accounting and financial compliance costs, as well as making some activities more difficult, time-consuming and costly, and placing strain on our personnel, systems, and resources. We may also face increased litigation risks related to disclosures made pursuant to the rule. In addition, enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon-intensive sectors.

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, 2023, $425.0 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 2023, 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 2024, 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 has become increasingly 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. 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 information security vulnerabilities.

Risks Relating to Our Common Stock

We have recently 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 46.1 million shares of our common stock. This represents approximately 23% 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.

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 director’s 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.

Cybersecurity Risk Management

We have developed and implemented a cybersecurity risk management program intended to protect the confidentiality, integrity, and availability of our critical systems and information. We design and assess our cybersecurity risk management program based on the National Institute of Standards and Technology Cybersecurity Framework (“NIST”). This does not imply that we meet any particular technical standards, specifications, or requirements, only that we use the NIST as a guide to help us identify, assess, and manage cybersecurity risks relevant to our business.

Our cybersecurity risk management program is integrated into our overall enterprise risk management program, and shares common methodologies, reporting channels and governance processes that apply across the enterprise risk management program to other legal, compliance, strategic, operational, and financial risk areas.

Our cybersecurity risk management program includes, but is not limited to, the following key elements:

• risk assessments designed to help identify material cybersecurity risks to our critical systems and information;
• a Manager of Information Technologies (“IT Manager”) responsible for managing our cybersecurity risk assessment processes, our security controls, and our response to cybersecurity incidents;
• the use of external service providers, where appropriate, to assess, test or otherwise assist with aspects of our security processes;
• systems for protecting information technology systems and monitoring for suspicious events, such as threat protection, firewall and anti-virus software; and
• cybersecurity awareness training of our employees, including incident response personnel, and senior management.

Governance

Our board of directors (the “Board”) considers oversight of our risks and risk management activities, including those related to cybersecurity threats, to be a responsibility of the entire Board. The Board also delegates certain risk oversight responsibilities to certain of its committees, and oversight of our cybersecurity risk is delegated by the Board to its Audit Committee. The Audit Committee receives regular reports, typically on a quarterly basis, from management and our internal auditors regarding information technology, cybersecurity risk, and efforts to prevent and mitigate such risks. The Chairperson of the Audit Committee subsequently reports on the Company’s cybersecurity risk, monitoring, and mitigation activities to the full Board, which equips the Board and its committees to fulfill their risk oversight role.

The Board and Audit Committee are supported in their oversight capacity by our Management Cybersecurity Committee (the “MC Committee”) and our internal auditors. The MC Committee consists of our CEO, CFO, EVP of Engineering and Corporate Planning, and our IT Manager.

Our internal auditors perform audit engagements to assess our strategies, policies, procedures, and controls to reduce the risk of a cybersecurity incident.

Our IT Manager is responsible for assessing and managing risks from cybersecurity threats, our overall cybersecurity risk management program and supervises both our internal cybersecurity personnel and our retained external cybersecurity consultants. Our IT Manager is responsible for reporting material incidents to our MC Committee. Our IT Manager has a Bachelor of Science in Computer Science from Texas A&M University and a Master of Business Administration from Rice University. He has over fifteen years of information technology experience in the energy industry.

Our MC Committee stays informed about and monitors efforts to prevent, detect, mitigate, and remediate cybersecurity risks and incidents through various means, including, as appropriate, briefings from internal security personnel, threat intelligence and other information obtained from governmental, public or private sources, such as external consultants engaged by us, and alerts and reports produced by security tools deployed in the information technology environment.

Engagement of Third Parties

The MC Committee, internal auditors, our IT Manager and various other groups each occasionally engage third-party service providers to assist in their management of cybersecurity threats, including but not limited to cybersecurity vendors, assessors, consultants, auditors, and other third parties. Our IT Manager oversees third party vendors to identify cyber risks associated with our use of third-party service providers who may have access to sensitive Company data and systems.

Impact of Risks from Cybersecurity Threats

As of the date of this Annual Report, we are not aware of any cybersecurity threats, including as a result of any previous cybersecurity incidents, that have materially affected or are reasonably likely to materially affect us, including our operations, business strategy, results of operations or financial condition. However, we acknowledge that cybersecurity threats are continually evolving, and the possibility of future discovery of cybersecurity incidents remains. Please see “Part I, Item 1A. Risk Factors – Risks Related to Technology and Cybersecurity” for additional information about our cybersecurity risks. There can be no assurance that our cybersecurity risk management program, including our controls, procedures and processes, will be fully complied with or that our program will be fully effective in protecting the confidentiality, integrity and availability of our information systems. While we devote resources to our security measures to protect our systems and information, these measures cannot provide absolute security that they will not be subject to cybersecurity attacks and any damages to us from such attacks.

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, 2023, we owned interests in a total of 76,484 gross (65,462 net) developed acres and operate the vast majority of our acreage position. In addition, as of December 31, 2023, we owned interests in approximately 19,643 gross (15,073 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 48 proved undeveloped locations (100% horizontal) and 4 PDNP opportunities based on the reserve report as of December 31, 2023. Our reserve estimates account for the capital costs required to develop these wells and the future plugging and abandonment cost. We believe the Northwest Shelf leases contain additional potential drilling locations. Within the Central Basin Platform, we had a total of 163 proved undeveloped locations (13% horizontal and 87% vertical) and 238 PDNP opportunities based on the reserve report as of December 31, 2023. Our reserve estimates account for the capital costs required to develop these wells. 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, 2023, we owned interests in a total of 12,572 gross (8,751 net) developed acres and 16,258 gross (12,405 net) undeveloped acres with an average proved operated working interest of 89% and net revenue interest of 67%. As of December 31, 2023, the Company had interests in approximately five gross vertical and 146 gross horizontal producing wells, of which we operate five vertical and 111 horizontal wells. The horizontal wells predominately produce from the San Andres conventional reservoir and the verticals produce from Wolfcamp and Devonian reservoirs.

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 and Gaines counties. 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, 2023, we owned interests in a total of 63,912 gross (56,711 net) developed acres and 3,385 gross (2,668 net) undeveloped acres with an average proved operated working interest of 97% and net revenue interest of 82% in the area. As of December 31, 2023, the Company had interests in approximately 695 gross vertical and 197 gross horizontal producing wells, of which we operate 587 vertical and 195 horizontal wells. The horizontal wells predominately produce from the San Andres conventional reservoir and the verticals 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, 2023, our estimated proved reserves had a pre-tax PV-10 value (present value discounted at 10%) of approximately $1,647.0 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $1,399.2 million, over 99.6% of which relates to our properties in the Permian Basin in Texas. We spent approximately $544.2 million on acquisitions and capital projects during 2023 and 2022. 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, 2023. Approximately 99.8% of our proved reserves are in the Permian Basin in Texas.

(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 (in thousands):

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.

(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, five year rule 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, 2023 included the following:

• Extensions. In 2023, extensions of 4.8 MMBoe were primarily the result of the successful operated drilling program and non-operated activity in the Northwest Shelf and Central Basin Platform.
• Purchase of minerals in place. In 2023, the Company completed the acquisition of Founders oil and gas leases and related property within Ector County that resulted in 8.2 MMBoe in additional reserves.
• Sales of minerals in place. In 2023, the Company sold 5.7 MMBoe from the divestiture of the Delaware Basin assets (30%), the New Mexico operated assets (57%), and part of the Company's assets in Gaines County (13%).
• Revision of previous estimates. In 2023, the negative revisions of prior reserves of 9.0 MMBoe consisted of 5.3 MMBoe (59%) related to changes in price and 3.7 MMBoe (41%) related to changes in performance and other economic factors.

Our proved oil, natural gas and natural gas liquid reserves are shown below.

(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, 2023 and 2022 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, 2023 and 2022, respectively, in accordance with SEC guidelines. 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 of Henry Hub natural gas. As of December 31, 2022, our reserves were based on an SEC average price of $90.15 per Bbl of WTI oil posted and $6.358 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

(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

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Our proved reserves by state as of December 31, 2023 are summarized in the table below.

Proved Reserves

As of December 31, 2023, we had approximately 129.8 MMBoe (one million Boe) of proved reserves, consisting of approximately 63% oil, 19% natural gas, and 18% 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, 2023, approximately 68% of the proved reserves have been classified as PD and the remaining 32% are PUD.

As of December 31, 2023, our total proved reserves had a net pre-tax PV-10 value of approximately $1,647.0 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $1,399.2 million. Approximately $1,262.7 million and $1,072.7 million, 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 $384.4 million and $326.5 million, respectively, are associated with PUD reserves.

Proved Undeveloped Reserves

Our reserve estimates as of December 31, 2023 include approximately 41.6 MMBoe as PUDs. As of December 31, 2022, our reserve estimates included approximately 48.0 MMBoe as proved undeveloped reserves. In accordance with our December 31, 2023 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, 2022 to December 31, 2023.

Notable changes in proved undeveloped reserves for the year ended December 31, 2023 included the following:

• Conversions to developed. During the year ended December 31, 2023, we incurred costs of approximately $90.3 million to convert 27 properties from PUD to PD through development. These 27 properties produced 573 MBoe during the year ended December 31, 2023, and have reserves of 7,068 MBoe as of December 31, 2023.
• Extensions. In 2023, extensions of 3.7 MMBoe were primarily the result of the successful operated drilling program and non-operated activity in the Northwest Shelf and Central Basin Platform.
• Purchase of minerals in place. In 2023, we completed the acquisition of Founders oil and gas leases and related property within Ector county that resulted in 3.7 MMBoe in additional reserves.
• Sales of minerals in place. In 2023, we sold 1.3 MMBoe from the divestiture of the New Mexico operated assets (81%), and a subset of our assets in Gaines County (19%).
• Revision of previous estimates. In 2023, the negative revisions of prior reserves of 4.9 MMBoe consisted of 0.8 MMBoe (16%) related to changes in price and 4.1 MMBoe (84%) 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, 2023, no material amount of proved undeveloped reserves were not scheduled to be converted to proved developed status within five years they were initially disclosed.

Estimated Costs Related to Conversion of Proved Undeveloped Reserves to Proved Developed Reserves

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. F-693. Within CGA, the technical person primarily responsible for preparing the estimates set forth in the CGA letter dated January 26, 2024, 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 36 years of practical experience in petroleum engineering, with over 34 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 judiciously 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 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 17 years of practical industry experience, including over 13 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 Operations, and the Executive Vice President of Land, Legal, Human Resources, and Marketing.

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 periodically meets with the independent reserve engineers that prepare estimates of proved reserves.

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, 2023 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.

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, 2023, 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:

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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, 2023, 2022, and 2021:

(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, 2023, 2022, and 2021.

(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.

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, 2023 in productive oil and natural gas wells (a net well is our percentage ownership of a gross well). Over 99.8% of such wells are in the Permian Basin in Texas.

Drilling Activity

During 2023, as operator, we drilled a total of 31.00 gross (29.75 net) wells. Of this, 14.00 gross (12.75 net) horizontal San Andres wells were in the Northwest Shelf (nine 1.0-mile laterals and five 1.5-mile laterals.) and 17.00 gross (17.00 net) wells were in the Central Basin Platform, of which six were horizontal San Andres wells in Andrews County, Texas (two 1.0-mile laterals and four 1.5-mile laterals) and 11.00 were vertical wells in Crane County, Texas. In addition, we also participated in five gross (0.59 net) non-operated wells of which three were Northwest Shelf and two in Central Basin Platform. These wells were successful and there were no dry wells.

The table below contains information regarding the number of operated wells drilled and/or participated in during the periods indicated.

The table below contains information regarding the number of non-operated wells drilled and participated in during the periods indicated.

Present Activities

We had no operated wells in the process of being drilled or completed as of December 31, 2023.

Cost Information

We conduct our oil and natural gas activities entirely in the United States. As noted in the table under “Production Prices and Production Costs”, our average production costs including lease operating expenses, gathering, processing and transportation ("GPT") and ad valorem, per Boe, were $11.70 and $12.02 for the years ended December 31, 2023 and 2022, respectively, and our average production taxes, per Boe, were $2.74 and $3.80 for the years ended December 31, 2023 and 2022, 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, 2023, 2022 and 2021 are shown below:

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. Our office space lease in Tulsa, Oklahoma was terminated as of March 31, 2021.

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 begun taking depositions and are conducting discovery.

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 and is 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, 2023, the Company made net paydowns of $3 million on its revolving line of credit, resulting in the outstanding long-term debt balance of $425 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.

2023 Developments and Highlights

Drilling, Completion, and Recompletion

In the first quarter of 2023, in the Northwest Shelf, the Company drilled and completed two 1-mile horizontal wells (each with a working interest of 100%), and two 1.5-mile horizontal wells (one with a working interest of approximately 99.8% and the other with a working interest of approximately 75.4%). Next, in its Crane County acreage within the Central Basin Platform, the Company drilled and completed three vertical wells (each with a working interest of 100%) and performed six vertical well recompletions (each with a working interest of 100%).

In the second quarter of 2023, in the Northwest Shelf, the Company drilled and completed two 1.5-mile horizontal wells (one with a working interest of 100% and the other with a working interest of approximately 75.4%) and two 1-mile horizontal wells (both with a working interest of approximately 91.1%). Additionally, in its Crane County acreage within the Central Basin Platform, the Company drilled and completed two vertical wells (each with a working interest of 100%) and performed three vertical well recompletions (each with a working interest of 100%).

During the third quarter of 2023, the Company drilled and completed two 1-mile horizontal wells (one with a working interest of 100% and the other with a working interest of 75%) in the Northwest Shelf, and three 1.5-mile horizontal wells (each with a working interest of 100%) in the Central Basin Platform. Additionally, in its Crane County acreage within the Central Basin Platform, the Company drilled and completed three vertical wells (each with a working interest of 100%). Lastly, the Company drilled and began the completion process on three 1-mile horizontal wells in the Northwest Shelf (each with a working interest of 100%).

In the fourth quarter of 2023, the Company completed and placed on production the three aforementioned 1-mile horizontal wells in the Northwest Shelf. Additionally, the Company drilled and completed one saltwater disposal (SWD) well in the Northwest Shelf (with a working interest of 100%), and completed the 2023 horizontal drilling program with one 1.5-mile horizontal well in the Northwest Shelf (with a working interest of approximately 97.7%), as well as two 1-mile horizontal wells and one 1.5-mile horizontal well (each with a working interest of 100%) in the Central Basin Platform. In its Crane County acreage within the Central Basin Platform, the Company drilled and completed three vertical wells (each with a working interest of 100%).

In summary, for 2023, the Company drilled and completed 20 horizontal wells, 11 vertical wells, and 1 SWD well. In addition, the Company performed 9 vertical well recompletions. The table below sets forth our drilling and completion activities for 2023 by quarter, and full year total through December 31, 2023.

(1) Fourth quarter total and full year total do not include one SWD well completed in the Northwest Shelf.

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 2022 and 2023 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 continue in 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:

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 2023from 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 gathering, transportation and processing costs (“GTP”) 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.

Year Ended December 31, 2022 Compared to Year Ended December 31, 2021

Oil sales. Oil sales increased approximately $139.5 million from $181.5 million in 2021 to $321.1 million in 2022 due to an increase in the average realized per barrel oil price from $67.56 in 2021 to $92.80 in 2022 and an increase in sales volume from 2,686,940 barrels of oil in 2021 to 3,459,840 barrels of oil in 2022. The increased average realized per barrel oil price was a result of the significantly higher oil price during the first eight months of 2022. The increased sales volumes were a direct result of assets acquired in the Stronghold Acquisition, which resulted in higher volumes for the last four months of 2022, as well as organic growth from capital expenditures that were $78.0 million greater in 2022 than in 2021.

Natural gas sales. Natural gas sales increased approximately $3.9 million from $14.8 million in 2021 to $18.7 million in 2022. The natural gas sales volume increased from 2,535,188 Mcf in 2021 to 4,088,642 Mcf in 2022 and the average realized per Mcf gas price decreased from $5.83 in 2021 to $4.57 in 2022. The sales volume increase was due to the aforementioned increase in capital expenditures as well as the Stronghold Acquisition, which closed August 31, 2022. The price decrease was driven by the Company's change in reporting presentation from two-stream (oil and natural gas) to three-stream (oil, natural gas and NGLs) beginning July 1, 2022.

NGL sales. NGL sales increased approximately $7.5 million from $0.0 million in 2021 to $7.5 million in 2022. NGL sales volumes in were 371,329 barrels compared to zero barrels in 2021, due to the Company’s change in reporting presentation for its natural gas products, which were presented on a three-stream basis beginning July 1, 2022. The average realized price per barrel of NGLs was $20.18 in 2022.

Lease operating expenses. Our total LOE increased from $30,312,399 in 2021 to $47,695,351 in 2022 and increased on a Boe basis from $9.75 in 2021 to $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 45% increase in production of 1,403,502 Boe year-over-year, as well as increased costs for goods and services due to increased Permian activity.

Gathering, transportation and processing costs. Our total GTP decreased from $4,333,232 in 2021 to $1,830,024 in 2022 and decreased on a Boe basis from $1.39 in 2021 to $0.41 in 2022. GTP costs decreased due to costs classified as a reduction to oil and natural gas sales revenues, due to a natural gas processing entity beginning to take control of transportation at the wellhead beginning May 1, 2022.

Ad valorem taxes. Our total ad valorem taxes increased from $2,276,463 in 2021 to $4,670,617 in 2022 and increased on a Boe basis from $0.73 in 2021 to $1.04 in 2022. Ad valorem taxes increased primarily due to the increase in taxed commodity prices from the prior year, as well as $783,159 for the properties acquired in the Stronghold Acquisition.

Oil and natural gas production taxes. Oil and natural gas production taxes as a percentage of oil and natural gas sales were 4.65% during 2021 and increased to 4.93% in 2022. Overall, the percentage was consistent year over year, with a slight increase due to proportionately higher gas revenues which are taxed at a higher rate. Production taxes vary from state to state. Therefore, these taxes are likely to vary in the future depending on the mix of production we generate from various states (currently only Texas and New Mexico), and on the possibility that any state may raise its production tax rates.

Depreciation, depletion and amortization. Our depreciation, depletion and amortization expense increased from $37,167,967 in 2021 to $55,740,767 in 2022 due to an increase in our total estimated costs of property as well as an increase of 1,403,502 in Boe produced. Our average depreciation, depletion and amortization per Boe increased from $11.95 per Boe during 2021 to $12.35 per Boe during 2022. These per Boe amounts are calculated by dividing our total depreciation, depletion and amortization expense by our total Boe volumes sold.

Asset retirement obligation accretion. Our ARO accretion increased from $744,045 in 2021 to $983,432 in 2022. This was a result of the 32 additional wells added from 2022 drilling activities as well as ARO accretion associated with the properties acquired in the Stronghold Acquisition, offset by wells plugged and abandoned during 2022.

Operating lease expense. Our operating lease expense decreased from $523,487 in 2021 to $363,908 in 2022 due to the month to month leases for office equipment and compressors used in operations on which the Company had previously elected to apply ASU 2016-02. The office equipment and compressors are not subject to ASU 2016-02 based on the agreement and nature of use. The costs have been recorded as short-term lease costs and amounts included in lease operating expenses beginning in the second quarter of 2021.

General and administrative expenses (including share-based compensation). General and administrative expenses increased from $16,068,105 in 2021 to $27,095,323 in 2022. The increase was primarily related to a $4,743,908 increase in share-based compensation, as well as increases in salaries and bonuses, all attributed to a nearly doubled headcount from 2021 to 2022 to support our growth. Other cost increases include software maintenance, rent, insurance, and environmental sustainability. The 2022 expenses also included non-recurring acquisition-related costs of $2.1 million.

Interest expense. Interest expense increased from $14,490,474 in 2021 to $23,167,729 in 2022. The increase was the result of a combination of higher interest rates during the second half of 2022, with a weighted average interest rate of 5.8% in 2022 and 4.4% in 2021, and having higher amounts outstanding on our credit facility throughout 2022, with a weighted average daily debt of approximately $308.7 million in 2021 compared to approximately $344.0 million in 2022, particularly due to the additional debt incurred for the Stronghold Acquisition.

Gain (loss) on derivative contracts. During 2022, the Company incurred a loss on derivative contracts of $21,532,659. During 2021, the Company recorded a loss on derivative contracts of $77,853,141. For the derivative contract settlements, the Company recorded a realized loss of $52,768,154 during 2021 and a realized loss of $62,525,954 during 2022, The increase of $9,757,800 in the realized loss was a result of the rise of crude oil prices during 2022, which was above the fixed prices of the derivative contracts. For the marked-to-market contracts, the Company recorded an unrealized gain of $40,993,295 during 2022 and an unrealized loss of $25,084,987 during 2021. This change in unrealized derivatives was due to the roll off of unfavorable contracts during 2022, as well as the Company's purchase of more favorable contracts during 2022.

Provision for income taxes. The provision for income taxes changed from a provision of $90,342 for 2021 to a provision of $8,408,724 for 2022. The current year federal tax expense was the result of certain existing deferred tax assets that will not be offset by existing deferred tax liabilities as a result of the 80% limitation on the utilization of net operating losses incurred after 2017.

Net income. The Company achieved net income of $3,322,892 in 2021 compared to net income of $138,635,025 in 2022. The increase in net income was due primarily to the increase in oil, natural gas, and NGL revenues, as well as the reduction in derivative contract losses, offset by increases in lease operating expenses, depletion, general and administrative expenses, and interest expense.

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 2023 was from funds generated from the sale of oil and natural gas production. These cash flows were primarily used to fund our capital expenditures. 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), 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 “Credit Facility”).

On August 31, 2022, the Company modified its Credit Facility through a 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. In conjunction with the Stronghold Acquisition, with the newly acquired assets put up for collateral, the Company established a borrowing base of $600 million. The borrowing base 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 or its subsidiaries and cancellation of certain hedging positions.

Rather than Eurodollar loans, the reference rate on 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, 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, 2023, $425 million was outstanding on the Credit Facility and the Company was in compliance with all covenants contained 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 Statements 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); as shown in our Statements 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 2023, 2022, and 2021 we had net cash provided by operating activities of $198.2 million, $197.0 million, and $72.7 million, respectively. During the three years ended December 31, 2023, we financed $20.9 million through proceeds from the sale of common stock. During 2023, 2022, and 2021, the Company had a net draw of $10.0 million, a net draw of $125.0 million, and a net repayment of $23.0 million on the Credit Facility, respectively. We primarily used this cash to fund our capital expenditures and development aggregating $596.9 million over the three years ended December 31, 2023. Additionally, during 2023, 2022 and 2021, we used cash of $215.0 million, $511.0 million and $83.2 million, respectively, to reduce the outstanding balance on our Credit Facility. As of December 31, 2023, we had cash on hand of $0.3 million and negative working capital of $57.9 million, compared to cash on hand of $3.7 million and negative working capital of $78.6 million as of December 31, 2022 and cash on hand of $2.4 million and negative working capital of $46.9 million as of December 31, 2021.

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, 2023 was $425.0 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 2026. Future lease payments for financing leases aggregate $2,006,453.

Subsequent Events

Surety Bonds - On January 10, 2024, two insurance companies issued surety bonds on behalf of the Company, one for $250,000, an RRC required blanket performance bond to operate 100 wells or more in the State of Texas, and one for $2,000,000, an RRC required blanket plugging extension bond, each with zero collateral requirements. The term for these two surety bonds ends on July 1, 2025 and can be renewed at that time.

First Amendment to Second Amended and Restated Credit Agreement - On February 12, 2024, the Company, Truist Bank ("Truist") as the Administrative Agent and Issuing Bank, and the lenders party thereto (the "Lenders") entered into an amendment (the "Amendment") to the Second Amended and Restated Credit Agreement dated August 31, 2022, by and among the Company, as Borrower, Truist as Administrative Agent and Issuing Bank, and the Lenders (together with all amendments or other modifications, the "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.

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, 2023, 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.

Revenue Recognition. In January 2018, the Company adopted Accounting Standards Update (“ASU”) 2014-09 *Revenues from Contracts with Customers (Topic 606) (“*ASU 2014-09”). The timing of recognizing revenue from the sale of produced crude oil and natural gas was not changed as a result of adopting ASU 2014-09. The Company predominantly derives its revenue from the sale of produced crude oil and natural gas. The contractual performance obligation is satisfied when the product is delivered to the purchaser. Revenue is recorded in the month the product is delivered to the purchaser.

The Company receives payment from one to three months after delivery. The transaction price includes variable consideration as product pricing is based on published market prices and reduced for contract specified differentials (quality, transportation and other variables from benchmark prices). The guidance regarding ASU 2014-09 does not require that the transaction price be fixed or stated in the contract. Estimating the variable consideration does not require significant judgment and Ring engages third party sources to validate the estimates. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration the Company expects to receive in exchange for those products. See "Note 2 — REVENUE RECOGNITION" of our financial statements for additional information.

Full Cost Method of Accounting. The Company uses the full cost method of accounting for oil and natural gas properties. Under this method, all costs (direct and indirect) associated with acquisition, exploration, and development of oil and natural gas properties are capitalized. Costs capitalized include acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties and costs of drilling and equipping productive and non-productive wells. Drilling costs include directly related overhead costs. All of our properties are located within the continental United States.

Write-down 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, 2023, 2022, or 2021.

Our estimates of reserves and future cash flow as of December 31, 2023 and 2022 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, 2023 and 2022, respectively, in accordance with SEC guidelines. 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. As of December 31, 2022, our reserves were based on an SEC average price of $90.15 per Bbl of WTI oil posted and $6.358 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.

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.

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 operation 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.

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 2023 ranged from a monthly average low of $68.72 per barrel to a monthly average high of $89.13 per barrel. Natural gas prices realized during 2023 ranged from a monthly average low of $(0.94) per Mcf to a monthly average high of $1.52 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 $0.76 per Mcf to a monthly average high of $2.78 per Mcf. Fees ranged from a monthly average low of $(2.07) per Mcf to a monthly average high of $(0.87) per Mcf. NGL prices received during 2023 ranged from a monthly average low of $7.07 per barrel to a monthly average high of $14.71 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.

Customer Credit Risk

Our principal exposure to credit risk is through receivables from the sale of our oil and natural gas production (approximately $37.9 million as of December 31, 2023). 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, 2023. 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.

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, 2023, we had $425.0 million outstanding on our Credit Facility with a weighted average annual interest rate for the year then ended of 8.8%. A 1% change in the interest rate on our Credit Facility would result in an estimated $4.3 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.

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, 2023, 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, 2023, 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, 2023 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 and Report of Independent Accounting Firm

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, 2023, 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, 2023. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting at December 31, 2023, is set forth below.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

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, 2023, 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, 2023, 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, 2023, and our report dated March 7, 2024 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 7, 2024