What changed in this filing

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Item 1. Business

2022-03-16 compared with 2021-03-16 · 137 added, 109 removed, 269 unchanged (48% of the section changed)

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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 new strategic vision are to:

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;

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

Our new strategic vision is guided by these key principles and implemented by pursuing the following five strategic objectives.

Attract and retain the best people - Achieving our mission will only be possible through our employees.

Our strategic vision is guided by these key principles and implemented by pursuing the following five strategic objectives.

Attract and retain highly qualified people - Achieving our mission will only be possible through our employees.

It is critical to have compensation, development, and human resource programs that attract, retain and motivate the types of people we need to succeed.

Pursue operational excellence with a sense of urgency - We plan to deliver low cost, consistent, timely and efficient execution of our drilling campaigns, work programs and operations.

We will execute our operations in a safe and environmentally responsible manner, apply advanced technologies, and continuously seek ways to reduce our operating cash costs on a per barrel basis.

We will 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.

This objective is a foundational aspect of our culture and future success.

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Focus on generating free cash flow and strengthen our balance sheet - Ring intends to reduce its long-term debt through the use of excess cash from operations and potentially through the sale of non-core assets.

Ring incurred long-term indebtedness in

connection with the acquisition of core assets from Wishbone Energy Partners, LLC and its related entities in 2019.

Continuing to generate 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 will be funded by operational cash flow, limited to maintain or minimally grow our production and reserve levels, and have returns sufficient to provide excess cash from operations to pay down debt.

Remaining focused and disciplined in this regard will lead to meaningful returns for our shareholders once our financial position improves and additional financial flexibility to manage swings in the business cycle.

Our commodity hedges are designed to ensure the necessary cash flow to adhere to these plans.

Our capital program will be funded by operational cash flow and limited to balance our production and reserve growth versus paying down debt.

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 the business cycle.

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 will actively pursue accretive acquisitions, mergers and dispositions that improve our margins, returns, and break-even costs of our investment portfolio.

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It also contributed approximately 45.3 million BOE of our 81.1 million BOE of proved reserves as of December 31, 2019.

Appointment and Departure of Certain Officers and Directors

On September 30, 2020, the Company announced the appointment of Mr.

McKinney as Chief Executive Officer (“CEO”) and Chairman of the Board of Directors (the “Board”), effective October 1, 2020.

In connection with the appointment of Mr.

McKinney, Lloyd T.

Rochford, Chairman of the Board, and Kelly Hoffman, CEO, resigned from their respective positions, effective as of October 1, 2020.

Rochford and Mr.

Hoffman also resigned from the Board on October 1, 2020.

Rochford remains with the Company in a consulting capacity as an advisor to the CEO and Chairman of the Board.

On October 22, 2020, the Company appointed Mr.

Mitchell to the Company’s Board and determined that Mr.

Mitchell is an “independent director” as such term is defined under the NYSE American Company Guide.

On October 29, 2020, the Company appointed Mr.

Harris to the Company’s Board and determined that Mr.

Harris are “independent directors” as such term is defined under the NYSE American Company Guide.

In connection with the appointment of Mr.

Stanley McCabe and Mr.

David Fowler resigned from the Board on and effective October 29, 2020.

On November 30, 2020, the Company announced the promotion of Mr.

Brooks to Executive Vice President of Land, Legal, Human Resources and Marketing, assuming roles previously held by Mr.

Matt Garner who served as General counsel and Vice President of land for the company.

On December 16, 2020, Company issued a press release announcing several executive management changes, effective December 31, 2020.

The Company announced the promotion of Mr.

Alexander Dyes to Executive Vice President of Engineering and Corporate Strategy, the promotion of Mr.

Marinos Baghdati to Executive Vice President of Operations, and the promotion of Ms.

Hollie Lamb to Vice President of Compliance and General Manager of the Company’s Midland, Texas office.

In connection with these changes, Mr.

Fowler resigned from his position as President but remains with the Company in a consulting capacity and manages Investor Relations and Mr.

Danny Wilson resigned from his position as Executive Vice President and Chief Operating Officer.

Appointment of Certain Officers and Directors

On March 24, 2021, the Company’s board of directors appointed Travis Thomas as Chief Financial Officer.

Primary Business Operations

The Company seeks to exploit its acreage position through the drilling of highly economic vertical and horizontal wells using the most recent drilling and completion techniques.

Our focus is drilling and developing our oil and gas properties through use of cash flow generated by our operations and reducing our long-term debt through the sale of non-core assets or through our excess cash flow

while still working towards maintaining or providing annual production growth.

We continue to evaluate potential transactions to acquire attractive acreage positions within our core areas of interest.

Ring’s original plan for 2020 included drilling 18 horizontal wells on the Northwest Shelf and performing workovers and extensive infrastructure projects on its Northwest Shelf, Central Basin Platform and Delaware Basin assets.

Due to the drop in the price of oil, Ring re-evaluated its capital expenditure budget for 2020 and made changes that the Company believed were in the best interest of its stockholders, including ceasing any further drilling until oil prices stabilized.

Of the 18 new wells originally planned, the Company drilled four new horizontal San Andres wells on its Northwest Shelf asset in the first quarter of 2020 and two more new horizontal San Andres wells in the same asset area in December 2020.

All four new wells drilled in the first quarter were completed, tested and had Initial Potentials (“IP”) filed.

In addition to the four new wells drilled in the first quarter which had IPs filed, the Company completed testing and filed IPs on two additional horizontal wells drilled in 2019.

The Company performed nine conversions from electrical submersible pumps to rod pumps in the first quarter 2020, four conversions in the second quarter 2020, eight conversions in the third quarter 2020 and eight conversions in the fourth quarter 2020.

Starting the last week of April, the Company shut-in or curtailed essentially all production, other than that associated with Ring’s Delaware Basin property.

The curtailments continued until early June, when, with commodity prices improving and price differentials decreasing, the Company began to bring wells back on-line, returning to near April levels by the end of the second quarter.

In the third quarter 2020, we restored production to 9,549 net barrels of oil equivalent per day (“BOEPD”).

In the fourth quarter 2020, the Company performed capital workovers and re-activations that stabilized production at 9,307 BOEPD.

In view of the uncertainty of the extent of the contraction in oil demand and the volatility of oil futures contracts due to the COVID-19 pandemic, combined with the generally weaker commodity price environment, the Company turned its strategic focus in 2020 to reducing costs, generating free cash flow, and paying down debt.

Ring believes that there is significant value to be created by drilling the identified undeveloped opportunities on its Texas and New Mexico properties and intends to focus its drilling efforts in 2021 primarily in the Northwest Shelf.

The Company seeks to rigorously manage its asset portfolio to optimize shareholder value over the long term.

As the weak commodity price environment began to recover and the contraction in oil demand seen from the COVID-19 pandemic began to ease, Ring initiated its Phase I four well program in the Northwest Shelf Asset by drilling two wells in December 2020 and two wells in January 2021.

All four wells were completed and placed on production during first quarter 2021.

During that quarter, the Company also performed nine conversions from electrical submersible pumps to rod pumps (such conversions, “CTRs”) with seven performed in the Northwest Shelf and two in the Central Basin Platform.

New wells were added throughout the year by drilling in phases, to ensure the Company would continue operating within cash flow.

In the second quarter of 2021, the Company completed its Phase II drilling program and placed on production three new horizontal San Andres wells in the Northwest Shelf, along with four additional CTRs in the Northwest Shelf and one CTR in the Central Basin Platform.

In third quarter 2021, the Phase III drilling program resulted in two horizontal San Andres wells in Northwest Shelf and two horizontal San Andres wells in the Central Basin Platform.

During the third quarter of 2021, the Company also performed seven CTRs in the Northwest Shelf and three CTRs in the Central Basin Platform.

In the fourth quarter of 2021, the Company drilled one new well and performed one CTR in the Northwest Shelf and drilled one new well in the Central Basin Platform.

Lastly, during 2021 the Company participated with offset operators in two wells in the Northwest Shelf Asset as a non-operating working interest owner.

● Northwest Shelf – Yoakum, Runnels and Coke Counties, Texas and Lea County, New Mexico – As of December 31, 2021, Ring owned interests in a total of 17,950 gross (13,662 net) developed acres and 17,860 gross (11,993 net) undeveloped acres.

In these counties, the Company has 72 identified proved horizontal drilling locations and 11 proved vertical drilling locations based on the reserve reports as of December 31, 2020 and an additional 70 potential vertical drilling locations based on 20-acre downspacing and 135 potential horizontal drilling locations based on 4-8 wells per section or 80-160 acres per well.

In these counties, the Company has 79 identified proved horizontal drilling locations and 11 proved vertical drilling locations based on the reserve reports as of December 31, 2021.

We believe the Northwest Shelf leases contain additional potential drilling locations.

● Central Basin Platform – Andrews and Gaines Counties, Texas – As of December 31, 2021, Ring owned interests in a total of 24,203 gross (18,882 net) developed acres and 4,862 gross (1,406 net) undeveloped acres.

In these counties, the Company has 2 identified proved vertical drilling locations and 32 identified proved horizontal locations based on the reserve reports as of December 31, 2020, and an additional 105 potential vertical drilling locations based on 10-acre downspacing and 179 potential horizontal drilling locations based on 6 wells per section or 106 acres per well.

● Delaware Basin – Culberson and Reeves Counties, Texas – As of December 31, 2020, Ring owned interests in a total of 18,521 gross (18,256 net) developed acres and 248 gross (212 net) undeveloped acres.

In these counties, the Company has 26 identified proved vertical drilling locations and 4 identified proved horizontal locations based on the reserve reports as of December 31, 2020 and an additional 17 potential vertical drilling locations based on 10-acre spacing and 59 potential horizontal drilling locations based on 4 wells per section or 160 acres per well.

In these counties, the Company has two identified proved vertical drilling locations and 38 identified proved horizontal locations based on the reserve reports as of December 31, 2021.

We believe the Central Basin Platform leases contain additional potential drilling locations.

● Delaware Basin – Culberson and Reeves Counties, Texas – As of December 31, 2021, Ring owned interests in a total of 18,729 gross (18,437 net) developed acres.

In these counties, the Company has five identified proved vertical drilling locations and four identified proved horizontal locations based on the reserve reports as of December 31, 2021.

We believe the Delaware Basin leases contain additional potential drilling locations.

Ring intends to grow its reserves and production through development, drilling, exploitation and exploration activities on this multi-year project inventory of identified potential drilling locations and through acquisitions that meet the Company’s strategic and financial objectives, targeting oil-weighted reserves.

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

For the fiscal year ended December 31, 2020, sales to three customers, Phillips 66 (“Phillips”), Occidental Energy Marketing (“Oxy”) and NGL Crude Partners (“NGL Crude”) represented 68%, 10% and 8%, respectively, of our oil and natural gas revenues.

As of December 31, 2020, Phillips represented 80% of our accounts receivable, Oxy represented 0% of our accounts receivable and NGL Crude represented 5% of our accounts receivable.

For the fiscal year ended December 31, 2021, sales to three customers, Phillips 66 Company (“Phillips”), NGL Crude Partners (“NGL Crude”), and BP Energy Company (“BP”) represented 76%, 7% and 6%, respectively, of our oil and natural gas revenues.

As of December 31, 2021, Phillips represented 75% of our accounts receivable, NGL Crude represented 8% of our accounts receivable and BP represented 4% of our accounts receivable.

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

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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, on January 20, 2021, the Biden Administration placed a 60-day moratorium on new oil and gas leasing and drilling permits on federal land, and on January 27, 2021, the Department of Interior acting pursuant to a Presidential Executive Order suspended the federal oil and gas leasing program indefinitely.

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.

The Biden Administration has also announced that it intends to review the Trump Administration’s 2017 repeal of the 2015 rule regulating hydraulic fracturing activities in federal land under the Presidential Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis.

While we do not have a significant federal lands acreage position at 240 net acres, these actions could have a material adverse effect on the Company and our industry.

While we do not have a significant federal lands acreage position (240 net acres as of December 31, 2021), these actions could have a material adverse effect on our industry and the Company.

Currently, all of our properties and operations are in Texas and New Mexico, which have 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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The transportation of oil in common carrier pipelines is also subject to rate regulation.

The Federal Energy Regulatory Commission, or the FERC, regulates interstate oil pipeline transportation rates under the Interstate Commerce Act.

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.

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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, the Natural Gas Policy Act of 1978 and regulations issued under those Acts by the FERC.

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.

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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.

contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services.

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.

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the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”);

the Oil Pollution Act of 1990;

the Oil Pollution Act of 1990 (“OPA”);

the Resource Conservation and Recovery Act (“RCRA”);

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Federal Water Pollution Control Act of 1972, or the Clean Water Act (“CWA”);

and the Safe Drinking Water Act of 1974.

and the Safe Drinking Water Act of 1974 (“SWDA”).

These federal laws are administered by the United States Environmental Protection Agency (“EPA”).

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(ii) subject our operations to certain permitting and registration requirements;

(iii) require remedial measures to mitigate pollution from former or ongoing operations;

(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.

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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.

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.

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.

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Air Emissions

Our operations are subject to the federal 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.

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.

We note that in June 2016, the EPA finalized rules regarding criteria for aggregating multiple small sites into a single source for air permitting purposes applicable to the oil and natural gas industry.

This rule could cause small facilities to be aggregated for permitting purposes, resulting in treatment as a major source, and thereby triggering more stringent air permitting requirements.

Violation of CAA requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions.

Furthermore, future capital expenditures may be required for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.

The trend under CAA regulations has been to increase the stringency of air quality standards, which may require us to incur capital expenditures for air pollution control equipment or other costs.

For example, in October 2015, the EPA lowered the National Ambient Air Quality Standards for ozone to 70 parts per billion, which was a significant decrease from the prior standards.

On December 31, 2020, EPA published in the Federal Register its decision to retain the 2015 ozone standards;

however, the current administration has announced that it intends to review this rule under the January 20, 2021 Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis .

Further reductions in the ozone National Ambient Air Quality Standards could affect our operations and result in the need to install new emissions controls, longer permitting timelines and significant increases in our capital or operating expenditures.

Compliance with these and any future air pollution control and permitting requirements has the potential to delay the development of our oil and natural gas projects and increase our costs of development and production, which costs could be significant.

In 2012 and 2016, the EPA issued New Source Performance Standards to regulate emissions of sources of volatile organic compounds (“VOCs”), sulfur dioxide, air toxics and methane from various oil and natural gas exploration, production, processing and transportation facilities.

On May 12, 2016, the EPA amended its regulations to impose new standards for methane and volatile organic compounds emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and natural gas sector.

However, in a March 28, 2017 executive order, the Trump Administration directed the EPA to review the 2016 regulations and, if appropriate, to initiate a rule making to rescind or revise them consistent with the stated policy of promoting clean and safe development of the nation’s energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production.

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.

Given the long-term trend toward increasing regulation, future federal Greenhouse Gas (“GHG”) regulations of the oil and gas industry remain a possibility, and several states have separately imposed their own regulations on methane emissions from oil and gas production activities.

In November 2021, the EPA proposed new source performance standards and emissions guidelines to reduce methane and other pollution from new and existing sources in the oil and gas industry.

The proposed rule would include, among other things, a comprehensive monitoring program for new and existing well sites, zero-emissions standards for new and existing pneumatic controls, and standards to eliminate venting of associated gas and requirements for the capture and sale of natural gas where a sales line is available.

If adopted, these requirements could increase our costs to operate and control pollution.

These standards, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions.

Until these rules are formally adopted, we cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty.

In October 2015, the EPA announced that it was lowering the primary National Ambient Air Quality Standards (“NAAQS”) for ozone from 75 parts per billion to 70 parts per billion.

Since that time, the EPA has issued area designations with respect to ground-level ozone.

In December 2020, the EPA announced its intention to leave the ozone NAAQS unchanged at 70 parts per billion rather than lower them further.

However, as discussed above, that action could be subject to reversal following the Biden Administration’s January 2021 executive order.

In 2022, the New Mexico Environment Department is expected to issue final rules imposing more stringent limits on ozone pollution from the oil and gas industry operating in the state.

Reclassification of areas of state implementation of the revised NAAQS could result in stricter permitting requirements, delay, or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant.

Moreover, the NMOCD recently adopted new rules, which require oil and gas operators to capture 98 percent of their natural gas waste by the end of 2026.

The new rules went into effect on May 25, 2021.

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 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 Oil Pollution Act of 1990 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 Oil Pollution Act.

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.

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.

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.

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Further regulatory changes are likely, as the current administration has announced that it intends to review the Navigable Waters Protection Rule under the January 20, 2021 Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis .

In November 2021, the EPA and the Corps issued a proposed rule to broaden the applicability of the definition of WOTUS.

The agencies did not announce a date for official publication in the Federal Register of the new rule.

However, future rulemakings regarding the definition of WOTUS will likely be subject to litigation.

As a result of these developments, the scope of federal jurisdiction under the Clean Water Act is uncertain at this time.

The pending litigation and future regulations concerning the definition of WOTUS may result in an expansion of the scope of the CWA’s jurisdiction, and we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in WOTUS in connection with our operations.

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 Safe Drinking Water Act, as well as by state programs.

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 Safe Drinking Water Act 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.

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.

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 New Mexico, the New Mexico Oil Conservation Division (“NMOCD”) administers the UIC program for all injection wells that are related to oil and natural gas production.

In Texas, the Texas Railroad Commission (“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 salt water 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.

In 2021, the NMOCD announced a new plan for responding to increased seismic activity in the Permian Basin.

Under the new plan, pending permits for wastewater injection in certain areas will be subject to additional reporting and monitoring requirements.

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 proposed 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

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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.

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.

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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 Texas Railroad Commission (“RRC”) adopted rules in 2014 requiring companies seeking permits for disposal wells to provide seismic activity data in permit applications.

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.

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In New Mexico, the Produced Water Act, effective July 1, 2019, governs the discharge, handling, transport, storage, and recycling or treatment of produced water.

Additionally, New Mexico has adopted regulations that require the disclosure of information regarding the substances used in the hydraulic fracturing process.

In January 2021, State Senator Antoinette Sedillo Lopez of New Mexico, introduced a bill which would prohibit certain uses of fresh water in fracking operations, require the disclosure of the chemical composition of produced water from spills, and increase penalties for produced water spills by the oil and gas industry.

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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, 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 June 2016, the EPA finalized rules to reduce methane emissions from new, modified or reconstructed sources in the oil and natural gas sector, including implementation of a leak detection and repair (“LDAR”) program to minimize methane emissions, under the CAA’s New Source Performance Standards in 40 C.F.R.

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Department of the Interior Bureau of Land Management (“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 GHG NSPS requirements.

However, in December 2017, the BLM published a final rule to temporarily suspend or delay certain requirements contained in the November 2016 final rule until January 17, 2019, including those requirements relating to venting, flaring and leakage from oil and gas production activities.

However, in December 2017, the BLM published a final rule to temporarily suspend or delay

certain requirements contained in the November 2016 final rule until January 17, 2019, including those requirements relating to venting, flaring and leakage from oil and gas production activities.

Further, 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.

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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.

In addition, 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.

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.

On an international level, the United States is one of almost 200 nations that agreed in December 2015 to an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measure each country will use to achieve its GHG emissions targets, (the “Paris Agreement”).

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President Biden announced on January 20, 2021 that the United States will rejoin the Paris Agreement.

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.

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

It is not possible at this time to predict how or when the United States might impose further restrictions on GHG emissions as a result of the Paris Agreement.

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, or limiting emissions of GHGs from, our equipment and operations 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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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.

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, migratory birds and natural resources

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.

Fish and Wildlife Service (“FWS”) may designate critical habitat areas that it believes are necessary for survival of threatened or endangered species.

As a result of a 2011 settlement agreement, the FWS was required to determine whether to identify more than 250 species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year.

The FWS missed the deadline but reportedly continues to review new species for protected status under the ESA pursuant to the settlement agreement.

A critical habitat designation could result in further material restrictions on federal land use or on private land use and could delay or prohibit land access or development.

Where takings of or harm to species or damages to wetlands, habitat, or natural resources occur or may occur, government entities or at times private parties may act to prevent or restrict oil and natural gas exploration activities or seek damages for any injury, whether resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and in some cases, criminal penalties may result.

Similar protections are offered to migratory birds under the MBTA.

Recently, there have been renewed calls to review protections currently in place for the dunes sagebrush lizard, whose habitat includes portions of the Permian Basin, and to reconsider listing the species under the ESA.

While some of our operations may be located in areas that are designated as habitats for endangered or threatened species or that may attract migratory birds, we believe that we are in substantial compliance with the ESA and the MBTA, and we are not aware of any proposed ESA listings that will materially affect our operations.

Nevertheless, we are monitoring proposed listings by the FWS, such as the January 2022 proposal to list the Sacramento Mountains checkerspot butterfly in New Mexico, to ensure continued compliance.

The federal government in the past has issued indictments under the MBTA to several oil and natural gas companies after dead migratory birds were found near reserve pits associated with drilling activities.

In January 2020, a new DOI rule went into effect clarifying that only the intentional taking of protected migratory birds is subject to prosecution under the MTBA.

In December 2021, however, that rule was revoked, and a new rule took effect reinstating the prohibition on incidental takes under the MTBA.

The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our development activities that could have an adverse impact on our ability to develop and produce our oil and natural gas reserves.

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

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Key to our mission is our employees upon which the foundation of our company is built.

We seek to employ the best people who exemplify our core values of honesty and integrity, and are diligent, hard-working individuals who deliver results, and who are good neighbors and contribute to the communities in which they live.

As of December 31, 2020, we had forty-one (41) full-time employees.

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 and contribute to the communities in which they live.

As of December 31, 2021, we had 53 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.

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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 22% are women and nearly one third represent minorities.

Our staff’s diversity is reflected in our full-time employees where 26% are women and approximately one third represent minorities.

The majority of our employees are citizens of the United States, with a few retaining dual citizenships in other countries.

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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 were the focus at every level of the organization from those on the front lines to those in our corporate offices.

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.

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Generally, the demand for oil and natural gas fluctuates depending on the time of year.

Seasonal anomalies such as mild winters or hot summers may sometimes lessen this fluctuation.

Seasonal anomalies such as mild winters and summers may sometimes lessen this fluctuation.

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.

Available Information

Our Internet website can be found at www.ringenergy.com.

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed pursuant to Section 13(a) or 15(d) of the Exchange Act of 1934 will be available through our Internet website free of charge as soon as reasonably practical after we electronically file such material with, or furnish it to, the SEC.

Our website can be found at www.ringenergy.com.

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed pursuant to Section 13(a) or 15(d) of the Exchange Act of 1934 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 an Internet website (http://www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.

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.

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