What changed in this filing

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Item 1. Business

2025-03-05 compared with 2024-03-07 · 102 added, 129 removed, 268 unchanged (46% of the section changed)

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.

Ring Energy, Inc., a Nevada corporation (“Ring,” “Ring Energy,” the “Company,” “we,” “us,” “our,” or similar terms), is a growth oriented independent oil and natural gas exploration and production company based in The Woodlands, Texas engaged in oil and natural gas development, production, acquisition, and exploration activities currently focused in the Permian Basin of Texas.

Our drilling operations target the oil and liquids rich producing formations in the Northwest Shelf and the Central Basin Platform, in the Permian Basin in Texas.

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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.

2024 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%

• Achieved record full year production of 19,648 Boepd (68% oil), a year-over-year increase in total Boe of 9%

• Executed a phased drilling program in 2024 that included drilling 44.00 gross / 43.94 net operated wells consisting of 22.00 horizontal and 22.00 vertical wells (gross).

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

• Total proved reserves were 134.2 MMBoe at year-end 2024, which increased 4.4 MMBoe, or 3% from year-end 2023.

Lime Rock Purchase and Sale Agreement

On February 25, 2025, the Company, as buyer, and Lime Rock Resources IV-A, L.P.

("LRRA") and Lime Rock Resources IV-C, L.P.

("LRRC" and with LRRA, "Lime Rock"), as seller, entered into a purchase and sale agreement (the "Purchase Agreement").

The Purchase Agreement provides that the Company will acquire (the "Lime Rock Acquisition") interests in oil and gas leases and related property of Lime Rock located in the Central Basin Platform of Texas for a purchase price (the "Purchase Price") of approximately $90 million in cash with $80 million due at closing and $10 million due on the nine months anniversary of closing, and 7,388,799 shares of our common stock.

The Purchase Price is subject to customary purchase price adjustments with an effective date of October 1, 2024.

On February 26, 2025, in connection with the Purchase Agreement, the Company deposited $5.0 million in cash into a third party escrow account as a deposit pursuant to the Purchase Agreement, which will be credited against the Purchase Price upon the closing of the Lime Rock Acquisition.

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.

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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;

• Ensure health, safety, and environmental excellence with a strong commitment to Ring’s employees and the communities in which we work and operate;

• Continue our focus on generating adjusted free cash flow to improve and build a sustainable financial foundation;

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• Improve margins and drive value by targeting additional operating cost reductions and capital efficiencies;

• strengthen our balance sheet by steadily paying down debt, divesting of non-core assets and becoming a peer leader in Debt/EBITDA metrics.

• Strengthen our balance sheet by paying down debt, divesting of non-core assets and becoming a peer leader in Debt/EBITDA metrics.

Our Business Strategy

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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.

We execute our operations in a safe and environmentally responsible manner, focus on reducing our emissions, applying advanced technologies, and continuously seeking ways to reduce our operating cash costs on a per barrel basis.

Invest in high-margin, high rate-of-return projects - We prioritize our work programs and allocate capital to the highest return opportunities in our inventory on an ongoing basis.

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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.

Our capital program is funded by operational cash flow and we seek to balance our production and reserve growth with paying down debt.

We believe that remaining focused and disciplined in this regard will lead to meaningful returns for our shareholders and provide additional financial flexibility to manage potential future swings in business cycles.

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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.

Quarter Area Wells Drilled Wells Completed Recompletions

1Q 2023 Northwest Shelf (Horizontal) 4 4 —

Central Basin Platform (Horizontal) — — —

Central Basin Platform (Vertical) 3 3 6

2Q 2023 Northwest Shelf (Horizontal) 4 4 —

Central Basin Platform (Horizontal) — — —

Central Basin Platform (Vertical) 2 2 3

3Q 2023 Northwest Shelf (Horizontal) 5 2 —

Central Basin Platform (Horizontal) 3 3 —

Central Basin Platform (Vertical) 3 3 —

4Q 2023 Northwest Shelf (Horizontal) 1 4 —

Central Basin Platform (Horizontal) 3 3 —

Central Basin Platform (Vertical) 3 3 —

Northwest Shelf (Horizontal) 14 14 —

Central Basin Platform (Horizontal) 6 6 —

Central Basin Platform (Vertical) 11 11 9

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

Refer to Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations, Drilling and Completion, for details of our 2024 operations.

Ring Energy’s Strengths

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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.

In addition, those companies may be able to pay more for producing oil and natural gas properties and exploratory prospects, and to evaluate, bid for, and purchase a greater number of properties and prospects than what our financial or technical resources permit.

Our ability to acquire additional properties and to find and develop reserves in the future will depend on our ability to identify, evaluate, and select suitable properties and to consummate transactions in this highly competitive environment.

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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.

Some of our oil production is sold through third-party pipelines that have no regional competition and all other oil production is transported by the oil purchaser by trucks with competitive trucking costs in the area.

Our oil is transported from the wellhead to tank batteries or delivery points through our flowlines or gathering systems.

Purchasers of our oil take delivery (i) at a pipeline delivery point or (ii) at our tank batteries for transport by truck.

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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.

Our produced saltwater is generally moved by pipeline connected to our operated saltwater disposal wells or by truck to commercial disposal facilities.

Major Customers

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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.

For the year ended December 31, 2024, sales to three customers represented 88% of our oil, natural gas, and natural gas liquids revenues.

As of December 31, 2024, accounts receivable from these three customers represented 86% of our total accounts receivable.

Refer to the table below for the details of these percentages, respectively.

We believe that the

loss of any of these purchasers would not materially impact our business because we could readily find other purchasers for our oil and natural gas.

For the Year Ended

December 31, 2024

Percentage of Oil, Natural Gas, and Natural Gas Liquids Revenues

Percentage of accounts receivables from the sale of our Oil, Natural Gas and NGL production

Phillips 66 Company ("Phillips")

Concord Energy LLC ("Concord") 14% 11%

LPC Crude III, LLC ("LPC") 13% 11%

Total of top three customers

Delivery Commitments

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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.

Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements of governmental authorities.

This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion.

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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.

Until recently, the trend in oil and natural gas regulation was to increase regulatory restrictions and limitations on such activities.

Any changes in, or more stringent enforcement of, these laws and regulations may result in delays or restrictions in permitting or development of projects or more stringent or costly construction, drilling, water management, or completion activities or waste handling, storage, transport, remediation, or disposal emission or discharge requirements which could have a material adverse effect on the Company.

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.

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Regulation of Transportation of Oil

Sales of crude oil, condensate, and NGLs are not currently regulated and are made at negotiated prices;

Sales of crude oil, natural gas, and NGLs are not currently regulated and are made at negotiated prices;

however, Congress could reenact price controls in the future.

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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.

Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis.

FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services.

Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

We cannot accurately predict whether FERC’s actions have achieved the goal of increasing competition in markets in which our natural gas is sold.

Therefore, we cannot provide any assurance that the less stringent regulatory approach established by FERC will continue.

However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.

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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.

Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in Texas will not affect our operations in any way that is of material difference from those of our competitors.

Environmental Compliance and Risks

Our oil and natural gas exploration, development, and production operations are subject to stringent federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection.

Our oil and natural gas exploration, development, and production operations are subject to numerous stringent federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection.

At the federal level, among the more significant laws that may affect our business and the oil and natural gas industry generally are:

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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;

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;

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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.

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.

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.

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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.

Under CERCLA, RCRA and analogous state laws, we could be required to remove or remediate environmental impacts on properties we currently lease or formerly owned or leased (including hazardous substances or wastes disposed of or released by prior owners or operators), to clean up contaminated off-site disposal facilities where our wastes have come to be located or to implement remedial measures to prevent or mitigate future contamination.

Compliance with these laws may constitute a significant cost and effort for us.

No specific accounting for environmental compliance has been maintained or projected by us at this time.

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

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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.

The proposed rule sought to make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the CAA (including intermittent vent pneumatic controllers, associated gas, and liquids unloading facilities).

In addition, the proposed rule sought to establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by the EPA.

In November 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule.

Among other things, the November 2022 supplemental proposed rule 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.

Among other things, the November 2022 supplemental proposed rule sought to remove an emissions monitoring exemption for small wellhead-only sites and creates a new third-party monitoring program to flag large emissions events, referred to in the proposed rule as “super emitters.” In December 2023, the EPA announced a final rule, which, among other things, requires the phase out of routine flaring of natural gas from newly constructed wells (with some exceptions) and routine leak monitoring at all well sites and compressor stations.

Notably, the EPA updated the applicability date for Subparts OOOOb and OOOOc to December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with later compliance deadlines under state plans.

The final rule 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 final rule gave states until March 2026 to develop and submit their plans for reducing methane emissions from existing sources.

The final emissions guidelines under Subpart OOOOc provides until 2029 for existing sources to comply.

As a result of these regulatory changes, the scope of any final air emissions regulations or the costs for complying with such regulations are uncertain.

We may incur costs as necessary to remain in compliance with these regulations.

Obtaining or renewing permits also has the potential to delay the development of oil and natural gas projects.

Federal and state regulatory agencies can impose administrative, civil and criminal penalties and seek injunctive relief for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations.

In August 2022, the Inflation Reduction Act of 2022 (“IRA”) was signed into law.

The IRA allocated $1.55 billion to the Methane Emissions and Waste Reduction Incentive Program.

The IRA also required the EPA to

implement a waste emission charge 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.

The IRA also required the EPA to implement a waste emission charge ("WEC") on methane emitted from applicable oil and gas facilities that exceed certain thresholds.

The WEC for 2024 was $900 per metric ton of methane and increases to $1,200 in 2025 and $1,500 in 2026.

In November 2024, the EPA finalized a rule implementing the WEC that took effect in January 2025.

The charge is designed to act as an incentive for operators to reduce emissions by minimizing leaks and replacing equipment rather than paying for excessive emissions.

In February 2025, however, the U.S.

House and Senate approved a joint resolution of disapproval under the Congressional Review Act to repeal the methane emissions charge, which President Trump is expected to sign into law.

While the State of Texas has not formally conducted recent rulemaking related to air emissions, scrutiny of oil and natural gas operations and the rules affecting them have increased in recent years.

For example, the EPA and environmental non-governmental organizations have conducted flyovers with optical gas imaging cameras to survey emissions from oil and natural gas production facilities and transmission infrastructure.

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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.

piping), inspections and records, security, and training.

Most importantly, the facility must fully implement the SPCC plan and train personnel in its execution.

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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.

Army Corps of Engineers (“Corps”) or a delegated state agency pursuant to Section 404 of the CWA.

In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities.

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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.

This restriction of disposal options for hydraulic fracturing waste and other changes to CWA requirements have resulted in increased costs to operators, including us.

Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

In January 2023, the EPA and the Corps issued a final rule that revises the definition of WOTUS.

In January 2023, the EPA and the Corps issued a final rule that revised the definition of WOTUS.

Separately, in May 2023, the U.S.

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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.

Following legal actions, implementation of the most recent rule is currently split across the country.

The rule is subject to an injunction in 27 states, including Texas, resulting in implementation of the pre-2015 rule adjusted to take into account jurisdictional limitations decided by the Supreme Court in Sackett v.

The other 23 states are subject to the WOTUS-defining rule published in September 2023.

Additionally, the Trump administration may pursue a new rulemaking to further revise or clarify the extent of federal jurisdiction under the CWA, though the substance and timing of such action cannot be predicted.

As such, uncertainty remains with respect to future implementation of the rule and the outcome of the pending litigation.

Many of our customers and service providers rely on permits obtained under the CWA for their oil and gas pipeline projects, the most common of which is Nationwide Permit 12 (“NWP 12”), which, from time to time, is renewed or modified by the Corps, whose actions in turn may be subject to litigation.

To the extent any action expands the scope of the CWA in areas where we or our suppliers, customers or service providers operate or imposes new or enhanced permitting requirements, our operations could be adversely impacted by increased compliance costs and energy infrastructure project delays or cancellations.

Underground Injection Control

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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.

Consequently, state regulators implementing both the federal UIC program and state corollaries have been heavily scrutinizing the location of injection facilities relative to faulting and are limiting both the density and injection facilities as well as the rate of injection.

In Texas, the RRC regulates the disposal of produced water by injection well.

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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.

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.

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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.

The EPA has adopted and implemented regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant

Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that already are major sources of criteria pollutants under the CAA.

Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that typically are GHG emissions.

If we are required to meet "best available control technology," our operations could be adversely affected and our ability to obtain air permits for new or modified facilities that exceed GHG emission thresholds could be restricted or delayed.

In addition, the EPA has adopted rules requiring the reporting of GHG emissions from oil and natural gas production and processing facilities on an annual basis, as well as reporting GHG emissions from gathering and boosting systems, oil well completions and workovers using hydraulic fracturing.

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In December 2023, the United States participated in the United Nations Climate Change Conference in the United Arab Emirates (“COP28”).

In November 2024, the United States participated in the United Nations Climate Change Conference in Baku, Azerbaijan ("COP29").

Further, several states and local governments remain committed to the principles of the Paris Agreement in their effectuation of policy and regulations.

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.

However, in January 2025, President Trump issued an executive order directing immediate notice to the United Nations of the United States’ withdrawal from the Paris Agreement and all other agreements made under the United Nations Framework Convention on Climate Change.

The full impact of these actions remains uncertain at this time;

however, any such future laws and regulations imposing reporting obligations on, limiting emissions of GHGs from, our equipment and operations, or restricting federal leases could impair our production, could require us to incur costs to reduce emissions of GHGs associated with our operations and could decrease demand for oil and natural gas.

The adoption and implementation of any laws or regulations imposing reporting obligations on, or limiting emissions of GHG from, our equipment and operations could require additional expenditures to reduce emissions of GHGs associated with its operations or could adversely affect demand for the oil and natural gas we produce, and thus possibly have a material adverse effect on our revenues, as well as having the potential effect of lowering the value of our reserves.

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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.

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.

These statutes include the Endangered Species Act (“ESA”), the Migratory Bird Treaty Act (“MBTA”) and the CWA.

Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat.

The dunes sagebrush lizard is one example of a species that was recently listed as an endangered species.

The State of Texas has filed suit challenging the listing.

The dunes sagebrush lizard is found in portions of Texas, including areas where we operate.

The listing of the dunes sagebrush lizard as an endangered species, may impact our operations in any area that is designated as the dunes sagebrush lizard’s habitat.

Depending on the locations of our operations, we may be required to comply with expensive mitigation measures intended to protect the dunes sagebrush lizard and its habitat.

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.

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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:

Our Vice President General Counsel together with our Chief Executive Officer are responsible for developing and executing our

human capital strategy, with oversight by the Board of Directors and the board committees.

Some of our key human capital areas of focus include the following.

Building a Safe Workforce Starts with Our Culture:

Ring is committed to building a safety culture that empowers employees and contractors to act as needed to work safely and to stop the job, without retribution, if conditions are deemed unsafe.

Ring is committed to building a safety culture that empowers employees and contractors to act as needed to work safely and to stop a job, without retribution, if conditions are deemed unsafe.

We strive to be incident-free every day across our operations.

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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.

In addition, our field personnel spend significant time driving on a daily basis, putting them at risk for driving accidents.

A strong safety culture is essential to our success, and we emphasize the important role that all personnel play in creating and maintaining a safe work environment.

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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;

• providing additional paid sick leave for quarantined employees.

Seasonal Nature of Business

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 1. Business