What changed in this filing

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Item 1. Business

2026-03-04 compared with 2025-03-05 · 56 added, 81 removed, 289 unchanged (32% of the section changed)

8 unchanged sentences

2025 Highlights and Major Developments

• Closed the Lime Rock Acquisition on March 31, 2025.

• Achieved record full year production of 20,253 Boepd (65% oil), a year-over-year increase in total Boe of 3%.

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

• Maintained our revolving credit facility borrowing base of $600 million

• Lowered lifting costs to $10.73 per Boe, or 1% year over year including 9 months of the LRR acquisition assets.

• Responded to lower commodity price environment by pulling back on capital expenditures, executing a phased drilling program in 2025 that included drilling 18 gross, 17 net operated wells consisting of 12 horizontal and six vertical wells (gross).

• Total proved reserves were 153.3 MMBoe at year-end 2025, which increased 19.1 MMBoe, or 14% from year-end 2024.

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.

Total proved developed reserves were 103.8 MMBoe at year-end 2025, which increased 11.2 MMBoe, or 12% from year-end 2024.

• Maintained our revolving credit facility borrowing base of $585 million.

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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In areas where there is no practical access to pipelines, oil is trucked to storage facilities.

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

For the year ended December 31, 2025, sales to three customers represented 89% of our oil, natural gas, and NGL revenues.

As of December 31, 2025, accounts receivable from these three customers represented 82% 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.

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

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Concord Energy LLC ("Concord") 13% 10%

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

NGL Crude Partners ("NGL Crude") 9% 6%

Total of top three customers

7 unchanged sentences

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.

The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects 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.

These statutes and regulations require permits for drilling operations, drilling bonds, and reports concerning operations.

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

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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;

(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.

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.

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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.

However, in March 2025, the EPA announced its intention to reconsider the March 2024 rule, including Subparts OOOOb and OOOOc, with a final rule expected in or around July 2026.

A subsequent rule, finalized on November 26, 2025, gives states, along with federal tribes that wish to regulate existing sources, until January 2027 to develop and submit their plans for reducing methane emissions from existing sources.

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.

2 unchanged sentences

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

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

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

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

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

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

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

In February 2025, however, the U.S.

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

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

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

In August 2022, for example, the EPA announced that it would be conducting helicopter flyovers of the Permian Basin region in Texas.

The flyovers used infrared cameras to survey oil and gas operations to identify large emitters of methane and volatile organic compounds ("VOCs").

Based on data obtained during flyovers, EPA intends to initiate enforcement follow up actions with facilities operators.

In addition, the RRC has increased oversight related to flaring, with reporting reviews and site inspections.

While none of these activities increases our compliance obligations, they signal the potential for increased enforcement and possible rulemaking in the future.

In August 2022, the Inflation Reduction Act of 2022 (“IRA”) was signed into law, which amended the CAA to establish the first ever federal fee on excess methane emissions from sources required to report their GHG emissions to the EPA, including certain oil and gas operations.

In November 2024, the EPA issued a final rule implementing the methane emissions charge, although in February 2025, Congress repealed the rule under the Congressional Review Act.

Additionally, under the One Big Beautiful Bill Act, enacted in July 2025 (“OBBBA”), Congress delayed the implementation of the methane emissions fee until 2034.

Additionally, in March 2025, the EPA announced formal reconsideration of the 2009 “Endangerment Finding”, a declaration that various greenhouse gases endanger public health and welfare and the basis for the majority of the EPA’s GHG-related regulations.

In February 2026, the current administration finalized a rule repealing the Endangerment Finding.

It is uncertain at this time what impact the repeal of the Endangerment Finding will have on such regulations.

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.

The OPA amends and augments the oil spill provisions of the CWA and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening WOTUS or adjoining shorelines.

In 1973, the EPA adopted oil pollution prevention regulations under the CWA.

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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.

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

3 unchanged sentences

The CWA prohibits the placement of dredge or fill material in wetlands or other WOTUS unless authorized by a permit issued by the U.S.

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

Army Corps of Engineers (“Corps”) or a delegated state agency.

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

Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.

Also, in June 2016, the EPA issued a final rule implementing wastewater pretreatment standards that prohibit onshore unconventional oil and natural gas extraction facilities from sending wastewater to publicly owned treatment works.

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

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

8 unchanged sentences

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.

The Corps is currently pursuing a new post- Sackett rulemaking, the ultimate consequence of which cannot be predicted at this time.

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.

NWP 12 is expected to be reissued by the Corps in 2026.

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.

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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.

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.

9 unchanged sentences

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.

The RRC adopted rules that 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.

In December 2024, the RRC adopted a significant overhaul of its rules regulating oil and natural gas waste management facilities in Texas.

The new rules went into effect on July 1, 2025.

The new rules cover waste from oil and natural gas operations, such as rock and other material pulled up from the ground during drilling, as well as waste from other operations.

The rules impose requirements related to waste management practices and production methods, such as recycling produced water.

The rules also update requirements on the design, construction, operation, monitoring, and closure of waste management units

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 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.

The EPA has adopted and implemented regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration (“PSD”) pre-construction permits, and Title V operating permits for GHG emissions from certain large stationary sources that already are major sources of criteria pollutants under the CAA.

Under these regulations, facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards for their GHG emissions established by the states or, in some cases, by the EPA, for those emissions.

If we are required to meet "best available control technology," our operations could be adversely affected and our ability to obtain air

permits for new or modified facilities that exceed GHG emission thresholds could be restricted or delayed.

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

In addition, in November 2016, the BLM issued final rules to reduce methane emissions from venting, flaring, and leaks during oil and natural gas operations on federal lands that are substantially similar to the CAA’s New Source Performance Standards in 40 C.F.R.

Part 60, Subpart OOOOa (“GHG NSPS”) requirements.

In September 2018, the BLM published a final rule revising or rescinding certain provisions of the 2016 rule, which became effective on November 27, 2018.

Both the 2016 and the 2018 rule were challenged in federal court resulting in the rescission of both rules.

Appeals to those decisions are ongoing, but with little activity in the last several years.

Although the EPA has proposed to delay GHG reporting for the oil and natural gas sector until 2034, and to otherwise repeal GHG reporting requirements for other sectors, we cannot predict whether these efforts will ultimately be successful or that GHG reporting will not be required again in the future.

The BLM has also, from time to time, considered or adopted rules regulating GHG emissions from oil and natural gas operations on federal lands.

Nevertheless, there continues to be uncertainty surrounding the federal regulation of methane and other GHG emissions.

Federal policy towards GHG emissions, and regulation thereunder, has varied significantly between the past several Presidential administrations.

The current administration has expressed a policy preference of limiting or rescinding regulations concerning GHG emissions and promulgated a final rule, in February 2026, repealing the EPA’s 2009 “Endangerment Finding” that forms the basis for most of the EPA’s GHG-related rules.

However, whether or how such policies and the EPA’s rescission of its “Endangerment Finding” will be implemented and if they will survive any potential legal challenges, or whether future administrations or Congress may pursue new GHG emissions regulations, cannot be predicted at this time.

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.

While Congress has, from time to time, considered legislation to reduce emissions of GHGs, including proposals adopting cap-and-trade programs, carbon taxes, climate-related mitigation funds, and regulations that directly limit GHG emissions from select sources, no significant legislation has been adopted at the federal level.

While Congress previously enacted the Inflation Reduction Act of 2022 (the “IRA”) to advance climate-related objectives and provide financial support for alternative or lower GHG-emitting energy production, many of these incentives were repealed or otherwise modified following the change in Presidential administrations and the enactment of OBBBA.

However, any similar or future climate-related legislation and accompanying policy initiatives could increase operating costs within the oil and gas industry or accelerate a transition away from fossil fuels, which could in turn reduce demand for our products and adversely affect our business and results of operations.

Additionally, a number of state and regional efforts are aimed at tracking and/or reducing GHG emissions by means of cap-and-trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs.

At the international level, there is an agreement, the United Nations-sponsored "Paris Agreement," for nations to limit their GHG emissions through non-binding, individually determined reduction goals every five years after 2020.

The United States rejoined the Paris Agreement in February 2021.

In early 2021, the Biden Administration issued a moratorium on oil and gas leasing on federal lands and waters to reduce emissions.

Since then, the moratorium has been the subject of litigation and, in August 2022, a federal judge entered an injunction against the moratorium.

In November 2021, the United States participated in the United Nations Climate Change Conference in Glasgow, Scotland, United Kingdom (“COP26”).

COP26 resulted in a pact among approximately 200 countries, including the United States, called the Glasgow Climate Pact.

Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector.

In conjunction with COP26, the United States committed to an economy-wide target of reducing net greenhouse gas emissions by 50-52 percent below 2005 levels by 2030.

Also in November 2021, President Biden signed a $1 trillion dollar infrastructure bill into law.

The new infrastructure law includes several climate-focused investments, including upgrades to power grids to accommodate increased use of renewable energy and expansion of electric vehicle infrastructure.

The above-referenced IRA allocated $369 billion to energy and climate initiatives.

In November 2022, the United States participated in the United Nations Climate Change Conference in Egypt (“COP27”).

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

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

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

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

State, regional and local governments may also elect to continue to participate in international climate change initiatives, despite the current administration finalizing the United States’ withdrawal from such initiatives in 2026.

The participation in, or support for, climate-related policies and initiatives by politicians, regulators, financial institutions, consumers, and other stakeholders could increase opposition against, reduce funding for or lead to new limitations on, fossil fuel exploration and production activities.

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

1 unchanged sentence

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.

Although it appears unlikely in the near term, more expansive and stringent environmental legislation and regulations, including greenhouse gas regulation, could continue, resulting in increased costs of conducting business and consequently affecting our profitability.

Threatened and Endangered Species

1 unchanged sentence

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.

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.

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As of December 31, 2025, we had 111 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.

Our employees are extremely valuable to the success of the Company, and we encourage their collaboration and respect their points of view and opinions.

In addition to our full-time employees, the Company also employs independent contractors who assist our full-time staff in a range of areas including geology, engineering, land, accounting, and field operations, as needed.

None are represented by labor unions or covered by any collective bargaining agreements.

We recognize that attracting, retaining and developing our employees is critical for our future success.

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

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

Our Senior 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.

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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