What changed in this filing

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Item 1. Business

2023-03-09 compared with 2022-03-16 · 154 added, 108 removed, 298 unchanged (47% 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 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 Texas and New Mexico.

Our primary drilling operations target the oil and liquids rich producing formations in the Northwest Shelf, the Central Basin Platform, and the Delaware Basin all of which are part of the Permian Basin in Texas and New Mexico.

As of December 31, 2022, our leasehold acreage positions totaled 124,217 gross (102,175 net) acres and we held interests in 1,056 gross (888 net) producing wells.

Proved reserves as of December 31, 2022 were approximately 138.1 million Boe (barrel of oil equivalent), of which we are the operator of approximately 98%.

All of our properties are located in the Permian Basin in Texas and New Mexico.

The Company’s proved reserves are oil-weighted with approximately 85% consisting of oil and 15% consisting of natural gas.

Of those reserves, approximately 56% are classified as proved developed or “PD” and 44% are classified as proved undeveloped, or “PUD.” For the calculation of BOE, oil is weighted on a 6 to 1 ratio against natural gas.

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 vital to the world’s health and welfare.

Our Business Strategy

All of our properties are located in the Permian Basin.

Our proved reserves are oil-weighted with approximately 64% consisting of oil, 19% consisting of natural gas, and 17% consisting of natural gas liquids.

Of those reserves, approximately 65% are classified as proved developed or “PD” and 35% are classified as proved undeveloped, or “PUD.” Within the "PD" reserve category, 235 re-completion and re-activation opportunities are classified as proved developed not producing "PDNP" and within the "PUD" reserve category, we have a total of 214 proved locations (43% horizontal and 57% vertical) based on the reserve report as of December 31, 2022.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.

2022 Highlights and Major Developments

• Amended our revolving credit facility “RBL” with an initial borrowing base of $600.0 million

• Closed the Stronghold Acquisition on August 31, 2022

• Increased liquidity position at year-end 2022 to approximately $188.0 million which was a 205% increase versus year-end 2021 of $61.6 million

• Improved RBL available balance at year-end 2022 to $184.2 million or 31% of undrawn capacity on the RBL versus year-end 2021 of $59.2 million or 17% of undrawn capacity

• Achieved record full year production of 12,364 Boepd (77% Oil), a year-over-year increase of 45%

• Executed a continuous drilling program in 2022 which included drilling 32.00 gross / 31.35 net operated wells consisting of 27.00 gross horizontal wells and 5.00 gross vertical wells

• Increased total Proved Reserves to 138.1 MMBoe at year-end 2022, a year-over-year increase of 78%

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 it believes are vital to the world’s health and welfare.

Our Key Principles

Successfully achieving Ring’s mission requires a firm commitment to operating safely in a socially responsible and environmentally friendly manner.

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

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

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, 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.

Invest in high-margin, high rate-of-return projects - Another key to achieving our mission will be to prioritize our work programs and allocate capital to the highest return opportunities in our inventory.

This objective is key to profitably growing our production and reserve levels and generating the excess cash from operations to pay down debt.

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.

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

Our Business Strategy

Our business strategy is guided by the above key principles and implemented by pursuing the following five strategic objectives, which are foundational aspects of our culture and success.

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

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

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

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

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

This objective is key to profitably growing our production and reserve levels and generating the excess cash from operations.

Focus on generating free cash flow and strengthen our balance sheet - We seek to continuously reduce long-term debt using excess cash from operations and potentially through the sale of non-core assets.

Continuing to generate 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 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 capital program is funded by operational cash flow and limited to balance our production and reserve growth versus paying down debt.

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

Our commodity hedges are designed to help ensure the necessary cash flow to adhere to these plans while retaining the flexibility to participate in prevailing commodity markets.

Pursue strategic acquisitions that maintain or reduce our break-even costs - We will actively pursue accretive acquisitions, mergers and dispositions that improve our margins, returns, and break-even costs of our investment portfolio.

Pursue strategic acquisitions that maintain or reduce our break-even costs - We actively pursue accretive acquisitions, mergers and dispositions in seeking to improve our margins, returns, and break-even costs.

Financial strategies associated with these efforts will focus on delivering competitive debt-adjusted per share returns.

This objective is key to delivering competitive returns to our shareholders on a sustainable basis.

2019 Acquisition

In 2019, a significant portion of the increase in acreage and reserves was the result of our acquisition of properties from Wishbone Energy Partners, LLC, Wishbone Texas Operating Company LLC and WB WaterWorks LLC on the Northwest Shelf in Gaines, Yoakum, Runnels and Coke Counties, Texas and Lea County, New Mexico that was completed in April 2019.

This acquisition contributed all of the acreage we have on the Northwest Shelf.

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

Appointment of Certain Officers and Directors

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

Stronghold Acquisition

On July 1, 2022, Ring and Stronghold Energy II Operating, LLC, a Delaware limited liability company (“Stronghold OpCo”) and Stronghold Energy II Royalties, LP, a Delaware limited partnership (“Stronghold RoyaltyCo”, together with Stronghold OpCo, collectively, “Stronghold”), entered into a purchase and sale agreement (the “Purchase Agreement"), under which Ring acquired (the “Stronghold Acquisition”) interests in oil and gas leases and related property of Stronghold consisting of approximately 37,000 net acres in the Central Basin Platform of the Texas Permian Basin.

On August 31, 2022, we completed the Stronghold Acquisition.

Upon closing of the Stronghold Acquisition, Stronghold exercised its right to designate two directors to our Board of Directors (the "Board").

On September 1, 2022, Roy I.

Ben-Dor and David S.

Habachy were appointed to the Board.

Primary Business Operations

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.

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 2022 primarily in the Northwest Shelf and Central Basin Platform.

● 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 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 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.

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

In the first quarter of 2022, we contracted a rig for our horizontal drilling program and began operations on January 31st.

We drilled and completed three 1-mile horizontal wells and one 1.5-mile horizontal well in the Central Basin Platform.

We then moved the rig to the Northwest Shelf and drilled two 1-mile horizontal wells.

All wells drilled in the first quarter had a working interest of 100%.

In the second quarter of 2022, we drilled a total of nine wells, completed seven wells, and began the completion process on four wells, all in the Northwest Shelf.

The first wells completed were the two 1-mile horizontal wells, which were drilled in the first quarter.

Next, we drilled and completed two 1-mile horizontal wells with a working interest of 100%, two 1.5-mile horizontal wells with a working interest of approximately 98.7% and one 1-mile horizontal well with a working interest of approximately 75.4%.

We also drilled and began the completion process on an additional four 1-mile horizontal wells.

Two of the wells have a working interest of 100%, one has a working interest of approximately 87.9%, and the fourth has a working interest of 75%.

In the third quarter of 2022, we completed and placed on production the four aforementioned 1-mile horizontal wells in the Northwest Shelf, which were drilled in the second quarter.

Next, we drilled and completed two 1.5-mile horizontal wells and one 1-mile horizontal well in the Central Basin Platform and two 1-mile horizontal wells in the Northwest Shelf, each with a working interest of 100%.

During the last month of the quarter, we drilled and began the completion process on three 1-mile horizontal wells in the Northwest Shelf, two with a working interest of 99.7% and one with a working interest of 100%.

In total, during the third quarter of 2022, we drilled eight, completed nine, and began the completion process on three horizontal wells.

With the addition of the Stronghold Acquisition assets in the Central Basin Platform, we also performed three vertical well re-completions.

In the fourth quarter of 2022, we completed and placed on production the three aforementioned 1-mile horizontal wells in the Northwest Shelf.

Next, we drilled and completed two 1-mile horizontal wells with a working interest of 100%, also in the Northwest Shelf.

To complete the 2022 horizontal drilling program, we drilled and completed two 1.5-mile horizontal wells in the Central Basin Platform.

In addition to the horizontal wells, we performed nine more vertical well re-completions and drilled and completed five new vertical wells on the Stronghold Acquisition assets located in Crane County, Texas, of the Central Basin Platform, all with a working interest of 100%.

In summary, for 2022, we drilled and completed 27 horizontal wells and 5 vertical wells, along with 12 vertical well re-completions on the Stronghold Acquisition assets.

The table below sets forth our drilling and completion activities for 2022 by quarter through December 31, 2022.

Quarter Area Wells Drilled Wells Completed Recompletions

1Q 2022 Central Basin Platform (Horizontal) 4 4 —

Central Basin Platform (Vertical) — — —

Northwest Shelf 2 — —

2Q 2022 Central Basin Platform (Horizontal) — — —

Central Basin Platform (Vertical) — — —

Northwest Shelf 9 7 —

3Q 2022 Central Basin Platform (Horizontal) 3 3 —

Central Basin Platform (Vertical) — — 3

Northwest Shelf 5 6 —

4Q 2022 Central Basin Platform (Horizontal) 2 2 —

Central Basin Platform (Vertical) 5 5 9

Northwest Shelf 2 5 —

Ring Energy’s Strengths

● high quality asset base in one of North America’s leading oil and gas producing regions characterized by low declines and attractive margins;

Our strengths include:

• high quality asset base in one of North America’s leading oil and gas producing regions characterized by relatively low declines and attractive margins;

• de-risked Permian Basin acreage position with multi-year drilling inventory of horizontal and vertical development potential;

• concentrated acreage position with high degree of operational control;

● experienced and proven management team focused on the Permian Basin;

● history of attracting technical personnel with experience in our core area of operations;

• experienced and proven management team with substantive technical and operational expertise;

• operating control over most of our production and development activities;

• commitment to cost efficient operations, health, safety, protecting the environment, our employees, and the communities in which we work and operate.

Competitive Business Conditions

We operate in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel.

We operate in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing competent personnel.

Some of our competitors possess and employ financial resources substantially greater than ours and some of our competitors employ more technical personnel.

These factors can be particularly important in the areas in which we operate.

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

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

Marketing and Pricing

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.

Marketing, Pricing, and Transportation

The actual price range of crude oil is largely established by major crude oil purchasers and commodities trading.

Pricing for natural gas is based on regional supply and demand conditions.

To this extent, we believe we receive oil and natural gas prices comparable to other producers.

To this extent, we believe we receive oil and natural gas prices comparable to other producers in our areas of operation.

We believe there is little risk in our ability to sell our production at prevailing prices.

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

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

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

Our natural gas is transported from the wellhead to the purchaser’s meter and pipeline interconnection point through our gathering systems.

We have implemented a Leak Detection and Repair program, or LDAR, to locate and repair leaking components including valves, pumps and connectors in order to minimize the emission of fugitive volatile organic compounds and hazardous air pollutants.

In addition, we install vapor recovery units in our newly installed tank batteries which also reduces emissions.

Our produced salt water is generally moved by pipeline connected to our operated salt water disposal wells or by pipeline 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 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.

For the year ended December 31, 2022, sales to three customers, Phillips 66 Company ("Phillips"), NGL Crude Partners ("NGL Crude"), and Enterprise Crude Oil LLC ("Enterprise") represented 68%, 13% and 5%, respectively, of our oil, natural gas, and natural gas liquids revenues.

As of December 31, 2022, Phillips represented 69% of our accounts receivable, NGL Crude represented 7% of our accounts receivable and Enterprise represented 10% 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.

Delivery Commitments

As of December 31, 2021, we were not committed to providing a fixed quantity of oil or gas under any existing contracts.

As of December 31, 2022, we were not committed to providing a fixed quantity of oil or natural gas under any existing contracts.

Commodity Hedging

We have an active commodity hedging program through which we seek to hedge a meaningful portion of our expected oil and gas production, reducing our exposure to downside commodity prices and enabling us to protect cash flows to meet our debt obligations under our credit facility and maintain liquidity to fund our capital expenditures needs.

Governmental Regulations

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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.

This ruling has caused federal agencies to delay issuing new oil and gas leases and permits on federal lands and waters.

While we do not have a significant federal lands acreage position (240 net acres as of December 31, 2022), these actions could have a material adverse effect on our industry and the Company.

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Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions.

The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state.

The basis for intrastate oil pipeline regulation, and the

degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state.

Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors.

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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 (“SWDA”).

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

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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As described below, there are various regulations issued by the EPA and other governmental agencies pursuant to these federal statutes that govern our operations.

In Texas and New Mexico, 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 saltwater.

In Texas and New Mexico, specific oil and natural gas regulations apply to oil and natural gas operations, including the drilling, completion and operations of wells, and the disposal of waste oil and saltwater.

There are also procedures incident to the plugging and abandonment of dry holes or other non-operational wells, all as governed by the applicable governing state agency.

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In addition to statutory liability under CERCLA, common law claims for personal injury or property damage can also be brought by neighboring landowners and other third parties related to contaminated sites.

RCRA, and comparable state statutes and their implementing regulations, regulate the generation, transportation, treatment, storage, disposal and cleanup of solid and hazardous wastes.

RCRA, and comparable state statutes and their implementing regulations, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and solid (non-hazardous) wastes.

Under a delegation of authority from the EPA, most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements.

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Legislation has been proposed from time to time in Congress to regulate certain oil and natural gas wastes as hazardous waste under RCRA.

Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our consolidated results of operations and financial position.

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.

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

We are not presently aware of any 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.

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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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.

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.

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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.

In November 2022, the EPA issued a Supplemental Proposal regarding the proposed new source performance standards and emissions guidelines for reducing methane and VOCs in the oil and natural gas sector.

The Supplemental Proposal expands the November 2021 proposal to include more comprehensive requirements to reduce emissions, including application of methane monitoring obligations to wellhead-only sites and well sites with low emissions.

It also would create a new third-party monitoring program to flag large emissions events known as the “Super-Emitter Response Program.” The EPA expects to finalize its new methane rules in 2023.

The foregoing laws, regulations, and 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.

On August 16, 2022, President Biden signed the Inflation Reduction Act of 2022 (“IRA”).

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

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

The methane charge goes into effect in 2024 at $900 per metric ton of methane and increases to $1,500 per metric ton of methane by 2026.

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

In November 2022, the Department of the Interior announced a proposed rule from the Bureau of Land Management (“BLM”) that would impose additional requirements on oil and natural gas production on federal and Tribal lands, including the use of “low bleed” pneumatic equipment and vapor recovery for oil storage tanks, implementation of leak detection plans, implementation of waste minimization plans, and monthly limits on royalty-free flaring.

If adopted, these rules could affect our adversely affect our production of oil and gas pursuant to federal leases in New Mexico.

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.

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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.

In mid-2022, the Biden Administration announced that it was considering designating the Permian Basin in Texas as a “non-attainment zone,” which, if designated, would result in increased permitting and compliance requirements for drilling operations in the state to decrease ozone levels.

The Biden Administration has since omitted the potential designation from an agenda of planned regulations, indicating that it is not expected to be finalized in the next year.

The EPA, however, could revive the effort in the future.

In 2022, the New Mexico Environment Department (“NMED”) adopted “ozone precursor rules.” The ozone precursor rules went into effect on August 5, 2022 and apply to oil and gas sources in New Mexico that would cause or contribute to ambient ozone concentrations that exceed 95% of the NAAQs for ozone.

As of the effective date, these rules apply to oil and natural gas production in the following counties in New Mexico:

Chaves, Dona Ana, Eddy, Lea, Rio Arriba, Sandoval, San Juan, and Valencia.

The rules apply to certain crude oil and natural gas production and processing equipment associated with operations.

Reclassification of areas of state implementation of NAAQS, or designation of areas in which we operate as non-attainment zones, 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 methane waste by the end of 2026.

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

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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.

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

The flyovers used infrared cameras to survey oil and gas operations to identify large emitters of methane and 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.

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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.

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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.

The scope of EPA’s and the Corps’ regulatory authority under Section 404 of the CWA has been the subject of extensive litigation and frequently changing regulations.

The EPA issued a final rule in September 2015 that attempted to clarify the federal jurisdictional reach over WOTUS under Section 404 of the CWA.

The EPA and the Corps issued a final rule in January 2018 staying implementation of the 2015 WOTUS rule for two years.

On October 22, 2019, EPA and the Corps published a final rule repealing the 2015 WOTUS rule.

The EPA and the Corps replaced the 2015 WOTUS rule by promulgating the Navigable Waters Protection Rule on April 21, 2020, which provides a revised definition of WOTUS and became effective on June 22, 2020.

These regulations have been challenged in federal court, however, and the scope of the CWA’s jurisdiction may remain fluid until all litigation is concluded.

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.

In January2023, the EPA and the Corps issued a final rule that revises the definition of WOTUS.

The final rule has been challenged by several states and industry groups.

As a result of these developments, the scope of federal jurisdiction under the CWA 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.

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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 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.

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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.

The EPA also issued an Advance Notice of Proposed Rulemaking under the Toxic Substances Control Act (“TSCA”) in 2014 regarding reporting of the chemical substances and mixtures used in hydraulic fracturing but, to date, has taken no further action.

Separately, the BLM published a final rule in March 2015 that establishes new or more stringent standards for performing hydraulic fracturing on federal and Indian lands.

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Our Company has taken measures to control methane leaks, but it is possible that these rules and future revisions thereto will require us to take further methane emission reduction measures, which may require us to expend material sums.

In addition, in November 2016, the U.S.

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.

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 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.

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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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”).

However, the Paris Agreement does not impose any binding obligations on the United States.

In June 2017, President Trump announced that the United States would withdraw from the Paris Agreement, which became effective November 4, 2020.

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

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”).

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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”).

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.

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.

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.

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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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.

Nevertheless, we are monitoring listings and proposed listings by the FWS to ensure continued compliance.

In November 2022, FWS listed the southern distinct population segments of the lesser prairie-chicken that occupy habitats in eastern New Mexico and the southwest Texas Panhandle.

In January 2023, FWS listed the Sacramento Mountains checkerspot butterfly in New Mexico.

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.

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 MBTA.

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

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.

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

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

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

As of December 31, 2022, we had 98 full-time employees.

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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 26% are women and approximately one third represent minorities.

Our staff’s diversity is reflected in our full-time employees where 24% are women and approximately 49% 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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In addition, our field personnel spend significant time driving on a daily basis, putting them at risk for driving incidents.

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

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

Health and Safety Training and Education:

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In addition to teaching specific skills, these training opportunities encourage personal responsibility for safe operating conditions and help to build a culture of individual accountability for conducting job tasks in a safe and responsible manner.

Ring Energy supports both company identified and employee identified educational opportunities for employees to advance in their technical and managerial skills and to help provide opportunities to advance throughout our company.

Ring supports both Company identified and employee identified educational opportunities for employees to advance in their technical and managerial skills and to help provide opportunities to advance throughout our company.

Ring’s support comes in the form of full or partial funding of educational programs and opportunities, including time off work to attend and/or prepare for such programs.

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Seasonal Nature of Business

Weather conditions often affect the demand for, and prices of, natural gas and can also delay oil and natural gas drilling, completion and production activities, disrupting our overall business plans.

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

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

Demand for natural gas is typically higher during the winter, resulting in higher natural gas prices for our natural gas production during our first and fourth fiscal quarters.

Further, pipelines, utilities, local distribution companies, and industrial end users utilize oil and natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can also lessen seasonal demand.

Due to these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of the results that we may realize on an annual basis.

Available Information

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

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed pursuant to Section 13(a) or 15(d) of the Exchange Act 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.

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

The information on, or that can be accessed through, our website is not incorporated by reference into this Annual Report and should not be considered part of this Annual Report.

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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