Item 1. Business
Item 1: Business
General
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, 2020, our leasehold acreage positions totaled 104,455 gross (76,745 net) acres and we held interests in 610 gross (441 net) producing wells. Proved reserves as of December 31, 2020 were approximately 76.5 million BOE (barrel of oil equivalent), of which we are the operator of approximately 97.7%. 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 87% consisting of oil and 13% consisting of natural gas. Of those reserves, approximately 57.5% are classified as proved developed or “PD” and 42.5% are classified as proved undeveloped, or “PUD.” For the calculation of BOE, oil is weighted on a 6 to 1 ratio against natural gas.
Our Mission
Ring’s mission is to deliver competitive and sustainable returns to its shareholders by developing, acquiring, exploring for, and commercializing oil and natural-gas resources vital to the world’s health and welfare.
Our Business Strategy
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:
● ensure health, safety, and environmental excellence and a strong commitment to Ring’s employees and the communities in which we work and operate;
● continue our focus on generating free cash flow to improve and build a sustainable financial foundation;
● pursue rigorous capital discipline focused on Ring’s highest returning opportunities;
● improve margins and drive value by targeting additional operating cost reductions and capital efficiencies; and
● strengthen 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. 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. 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. Ring incurred long-term indebtedness in
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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.
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. 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 and Departure of Certain Officers and Directors
On September 30, 2020, the Company announced the appointment of Mr. Paul D. 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. Mr. Rochford and Mr. Hoffman also resigned from the Board on October 1, 2020. Mr. 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. Thomas L. 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. John A. Crum and Mr. Richard E. Harris to the Company’s Board and determined that Mr. Crum and Mr. Harris are “independent directors” as such term is defined under the NYSE American Company Guide. In connection with the appointment of Mr. Crum and Mr. Harris, 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. Stephen D. 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. David A. 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.
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
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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.
● Northwest Shelf – Yoakum, Runnels and Coke Counties, Texas and Lea County, New Mexico – As of December 31, 2020, Ring owned interests in a total of 11,723 gross (8,085 net) developed acres and 35,249 gross (24,830 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.
● Central Basin Platform – Andrews and Gaines Counties, Texas – As of December 31, 2020, Ring owned interests in a total of 23,668 gross (18,712 net) developed acres and 15,046 gross (6,650 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.
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.
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;
● 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;
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● history of attracting technical personnel with experience in our core area of operations;
● 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. 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
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. We believe there is little risk in our ability to sell our production at prevailing prices. We view potential declines in oil and gas prices to a level which could render our current production uneconomical as our primary pricing risk.
We are presently committed to use the services of the existing gathering systems of the companies that purchase our natural gas production. This commitment is tied to existing natural gas purchase contracts associated with our production, which potentially gives such gathering companies certain short-term relative monopolistic powers to set gathering and transportation costs. Obtaining the services of an alternative gathering company would require substantial additional costs (since an alternative gathering company would be required to lay new pipeline and/or obtain new rights of way to any lease from which we are selling production).
We are not subject to third-party gathering systems with respect to our oil production. Some of our oil production is sold through 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.
Major Customers
We principally sell our oil and natural gas production to end users, marketers and other purchasers that have access to nearby pipeline facilities. In areas where there is no practical access to pipelines, oil is trucked to storage facilities.
For the 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. 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, 2020, we were not committed to providing a fixed quantity of oil or gas under any existing contracts.
Governmental Regulations
Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, can affect our profitability.
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Regulation of Drilling and Production
The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. The trend in oil and natural gas regulation has been to increase regulatory restrictions and limitations on such activities. Any changes in, or more stringent enforcement of, these laws and regulations may result in delays or restrictions in permitting or development of projects or more stringent or costly construction, drilling, water management or completion activities or waste handling, storage, transport, remediation, or disposal emission or discharge requirements which could have a material adverse effect on the Company. For example, 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. 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.
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. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, both Texas and New Mexico impose a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within their jurisdictions.
The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
Regulation of Transportation of Oil
Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices, however, Congress could reenact price controls in the future.
Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The Federal Energy Regulatory Commission, or the FERC, regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors. Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by pro-rationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.
Regulation of Transportation and Sale of Natural Gas
Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those Acts by the FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.
Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct
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contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.
We cannot accurately predict whether the FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. Therefore, we cannot provide any assurance that the less stringent regulatory approach established by the FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.
Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors.
Environmental Compliance and Risks
Our oil and natural gas exploration, development and production operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. At the federal level, among the more significant laws that may affect our business and the oil and natural gas industry generally are: the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”); the Oil Pollution Act of 1990; the Resource Conservation and Recovery Act (“RCRA”); the Clean Air Act (“CAA”); Federal Water Pollution Control Act of 1972, or the Clean Water Act (“CWA”); and the Safe Drinking Water Act of 1974. These federal laws are administered by the United States Environmental Protection Agency (“EPA”). Generally, these laws (i) regulate air and water quality, impose limitations on the discharge of pollutants and establish standards for the handling of solid and hazardous wastes; (ii) subject our operations to certain permitting and registration requirements; (iii) require remedial measures to mitigate pollution from former or ongoing operations; and (iv) may result in the assessment of administrative, civil and criminal penalties for failure to comply with such laws. In addition, there is environmental regulation of oil and gas production by state and local governments in the jurisdictions where we operate. As described below, there are various regulations issued by the EPA and other governmental agencies pursuant to these federal statutes that govern our operations.
In Texas 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. There are also procedures incident to the plugging and abandonment of dry holes or other non-operational wells, all as governed by the applicable governing state agency.
At the federal level, among the more significant laws and regulations that may affect our business and the oil and natural gas industry are:
Hazardous Substances and Wastes
CERCLA, also known as the Superfund law, and analogous state laws impose liability on certain classes of persons, known as “potentially responsible parties,” for the disposal or release of a regulated hazardous substance into the environment. These potentially responsible parties include (1) the current owners and operators of a facility, (2) the past owners and operators of a facility at the time the disposal or release of a hazardous substance occurred, (3) parties that arranged for the offsite disposal or treatment of a hazardous substance, and (4) transporters of hazardous substances to off-site disposal or treatment facilities. While petroleum and natural gas liquids are not designated as a “hazardous substance” under CERCLA, other chemicals used in or generated by our operations may be regulated as hazardous substances. Potentially responsible parties under CERCLA may be subject to strict, joint and several liability for the costs of investigating and cleaning up environmental contamination, for damages to natural resources and for the costs of certain health studies. In addition to statutory liability under CERCLA, common law claims for personal injury or property damage can also be brought by neighboring landowners and other third parties related to contaminated sites.
RCRA, and comparable state statutes and their implementing regulations, regulate the generation, transportation, treatment, storage, disposal and cleanup of solid and hazardous wastes. Under a delegation of authority from the EPA, most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Federal and state regulatory
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agencies can seek to impose administrative, civil and criminal penalties for alleged non-compliance with RCRA and analogous state requirements. Certain wastes associated with the production of oil and natural gas, as well as certain types of petroleum-contaminated media and debris, are excluded from regulation as hazardous waste under Subtitle C of RCRA. These wastes, instead, are regulated as solid waste (i.e., non-hazardous waste) under the less stringent provisions of Subtitle D of RCRA. It is possible, however, that certain wastes now classified as non-hazardous could be classified as hazardous wastes in the future and therefore be subject to more rigorous and costly disposal requirements. Legislation has been proposed from time to time in Congress to regulate certain oil and natural gas wastes as hazardous waste under RCRA. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our consolidated results of operations and financial position.
Under CERCLA, RCRA and analogous state laws, we could be required to remove or remediate environmental impacts on properties we currently own and lease or formerly owned or leased (including hazardous substances or wastes disposed of or released by prior owners or operators), to clean up contaminated off-site disposal facilities where our wastes have come to be located or to implement remedial measures to prevent or mitigate future contamination. Compliance with these laws may constitute a significant cost and effort for us. No specific accounting for environmental compliance has been maintained or projected by us at this time. We are not presently aware of any environmental demands, claims, or adverse actions, litigation or administrative proceedings in which either we or our acquired properties are involved in or subject to, or arising out of any predecessor operations.
Air Emissions
Our operations are subject to the 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. 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.
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. In 1973, the EPA adopted oil pollution prevention regulations under the CWA. These oil pollution prevention regulations require the preparation of a Spill Prevention Control and Countermeasure (“SPCC”) plan for facilities engaged in drilling, producing, gathering, storing, processing, refining, transferring, distributing, using, or consuming crude oil and oil products, and which due to their location, could reasonably be expected to discharge oil in harmful quantities into or upon the navigable waters of the United States. SPCC requirements under the CWA require appropriate containment berms and similar structures to help prevent the discharge of pollutants into regulated waters in the event of a crude oil or other constituent tank spill, rupture or leak. The SPCC regulations require affected facilities to prepare a written, site-specific SPCC plan, which details how a facility’s operations comply with the requirements of the pollution prevention regulations. To be in compliance, the facility’s SPCC plan must satisfy all of the applicable
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requirements for drainage, bulk storage tanks, tank car and truck loading and unloading, transfer operations (intra-facility piping), inspections and records, security, and training. Most importantly, the facility must fully implement the SPCC plan and train personnel in its execution. Where applicable, we maintain and implement SPCC plans for our facilities.
Water Discharges
The CWA and analogous state laws and regulations impose restrictions and strict controls regarding the discharge of pollutants into navigable waters, defined as waters of the United States (“WOTUS”), as well as state waters. The CWA prohibits the placement of dredge or fill material in wetlands or other WOTUS unless authorized by a permit issued by the U.S. Army Corps of Engineers (“Corps”) or a delegated state agency pursuant to Section 404. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Also, in June 2016, the EPA issued a final rule implementing wastewater pretreatment standards that prohibit onshore unconventional oil and natural gas extraction facilities from sending wastewater to publicly owned treatment works. This restriction of disposal options for hydraulic fracturing waste and other changes to CWA requirements may result in increased costs. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.
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 . 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 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. 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.
Hydraulic Fracturing
Hydraulic fracturing is a practice in the oil and natural gas industry used to stimulate production of natural gas and/or oil from low permeability subsurface rock formations by injecting water, sand and chemicals under pressure. Oil and natural gas may be recovered from certain of our oil and natural gas properties through the use of hydraulic fracturing. Hydraulic fracturing is subject to regulation by state regulatory authorities, and several federal agencies have asserted federal regulatory authority over certain aspects of
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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. 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. However, a Wyoming federal court struck down this rule in June 2016. The June 2016 decision was appealed by the BLM to the U.S. Circuit Court of Appeals for the Tenth Circuit. However, following issuance of a presidential executive order to review rules related to the energy industry, in July 2017, the BLM published a notice of proposed rulemaking to rescind the 2015 final rule. In September 2017, the Tenth Circuit issued a ruling to vacate the Wyoming trial court decision and dismiss the lawsuit challenging the 2015 rule in light of the BLM’s proposed rulemaking. The BLM issued a final rule repealing the 2015 hydraulic fracturing rule in December 2017. The current administration has announced that it intends to review the repeal of the 2015 hydraulic fracturing rule under the Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis .
Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process but, at this time, federal legislation related to hydraulic fracturing appears uncertain. In Texas 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 salt water. 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. The rules also allow the RRC to modify, suspend, or terminate permits if a disposal well is determined to be causing seismic activity. Determinations by the RRC under these rules may adversely affect our operations. In New Mexico, the Produced Water Act, effective July 1, 2019, governs the discharge, handling, transport, storage, and recycling or treatment of produced water. 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. State Senator Sedillo introduced another bill for the 2021 legislative session seeking to prevent the New Mexico Energy, Minerals and Natural Resources Department from issuing new fracking permits until 2025. Similar legislation was unsuccessful in the 2019 and 2020 legislative sessions. However, if enacted, this legislation would have a material adverse effect on our business and prospects.
Local governments may also seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. In Texas, however, local governments are expressly preempted from regulating oil and gas operations with limited exceptions, under Texas Natural Resources Code Section 81.0523. If new laws or regulations that significantly restrict hydraulic fracturing are adopted at the local, state or federal level, our fracturing activities could become subject to additional permit and financial assurance requirements, more stringent construction requirements, increased reporting or plugging and abandoning requirements or operational restrictions and associated permitting delays and potential increases in costs. These delays or additional costs could adversely affect the determination of whether a well is commercially viable and could cause us to incur substantial compliance costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce in commercial quantities.
Climate Change
Continuing political and social attention to the issue of global climate change has resulted in both existing and pending international agreements and national, regional or local legislation and regulatory measures to limit or reduce emissions of so-called greenhouse gases (“GHGs”), such as cap and trade regimes, carbon taxes, restrictive permitting, increased fuel efficiency standards and incentives or mandates for renewable energy. In December 2009, the EPA published an endangerment finding concluding that emissions of CO 2 , methane and certain other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on its findings, the EPA has adopted and implemented regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit requirements for GHG emissions from certain large stationary sources that already are major sources of criteria pollutants under the CAA. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that typically are GHG emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities that exceed GHG emission thresholds. In addition, the EPA has adopted rules requiring the reporting of GHG emissions from oil and natural gas production
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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. Part 60, Subpart OOOOa (“GHG NSPS”). On April 18, 2017, the EPA announced its intention to reconsider certain aspects of those regulations, and in June 2017, the EPA proposed a two-year stay of certain requirements of the GHG NSPS regulations. In October 2018 the EPA proposed revisions to the GHG NSPS, such as changes to the frequency for monitoring fugitive emissions at well sites and changes to requirements that a professional engineer certify when meeting certain GHG NSPS requirements is technically infeasible. EPA proposed further revisions to the GHG NSPS on September 24, 2019, including rescinding the methane requirements in the GHG NSPS that apply to sources in the production and processing segments of the industry. In September 2020, the EPA finalized amendments to the GHG NSPS that rescind requirements for the transmission and storage segment of the oil and natural gas industry and rescind methane-specific limits that apply to the industry’s production and processing segments, among other things. The current administration has announced that it intends to review the September 2020 rules under the Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis , which review may result in the reinstatement of the now-rescinded standards or promulgation of more stringent standards. 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. 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. Both the 2016 and the 2018 rule were challenged in federal court. On July 21, 2020, a Wyoming federal court vacated almost all of the 2016 rule, including all provisions relating to the loss of gas through venting, flaring, and leaks, and on July 15, 2020, a California federal court vacated the 2018 rule. As a result of these decisions, the 1979 regulations concerning venting, flaring and lost production on federal land have been reinstated. The current administration is likely to impose new regulations on GHG emissions from oil and natural gas production operations on federal land, given the long-term trend towards increasing regulation in this area. Moreover, several states have already adopted rules requiring operators of both new and existing sources to develop and implement an LDAR program and to install devices on certain equipment to capture methane emissions. Compliance with these rules could require us to purchase pollution control and leak detection equipment, and to hire additional personnel to assist with inspection and reporting requirements.
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. 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. 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. The adoption and implementation of any laws or regulations imposing reporting obligations on, or limiting emissions of GHG from, our equipment and operations could require additional expenditures to reduce emissions of GHGs associated with its operations or could adversely affect demand for the oil and natural gas we produce, and thus possibly have a material adverse effect on our revenues, as well as having the potential effect of lowering the value of our reserves. Recently, stakeholders concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities. Finally, to the extent increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events, such events could have a material adverse effect on the Company and potentially subject the Company to further regulation. The trend of more expansive and stringent environmental legislation and regulations,
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including greenhouse gas regulation, could continue, resulting in increased costs of conducting business and consequently affecting our profitability.
Operational Hazards and Insurance
The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, well blow-outs, pipe failures, industrial accidents, and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil releases, chemical releases, natural gas leaks and the discharge of toxic gases.
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us, for example, as a result of damage to our property or equipment or injury to our personnel. These operational risks could also result in the spill or release of hazardous materials such as drilling fluids or other chemicals, which may result in pollution, natural resource damages, or other environmental damage and necessitate investigation and remediation costs. As a result, we could be subject to liability under environmental law or common law theories. In addition, these operational risks could result in the suspension or delay of our operations, which could have significant adverse consequences on our business.
In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. Under certain circumstances, we may be liable for environmental damage caused by previous owners or operators of properties that we own, lease or operate. As a result, we may incur substantial liabilities to third parties or governmental entities for environmental matters for which we do not have insurance coverage, which could reduce or eliminate funds available for exploration, development or acquisitions or cause us to incur losses.
Human Capital Management
Key to our mission is our employees upon which the foundation of our company is built. We seek to employ 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. Our employees are extremely valuable to the success of the company and we encourage their collaboration and respect their diverse points of view and opinions. In addition to our full-time employees, the Company also employs a diverse group of independent contractors who assist our full-time staff in a range of areas including geology, engineering, land, accounting, and field operations, as needed. None are represented by labor unions or covered by any collective bargaining agreements.
Diversity and inclusion: The unique backgrounds and experiences of our employees help to develop a wide range of perspectives that lead to better solutions. Our staff’s diversity is reflected in our full-time employees where 22% are women and nearly one third represent minorities. The majority of our employees are citizens of the United States, with a few retaining dual citizenships in other countries. The employees who are not US citizens, are legally registered to live and work here and the Company is committed to helping those employees retain their ability to remain in the US and continue their employment. The Company is also committed to continuously providing an inclusive work environment where all of our employees can be respected, valued, and successful in achieving their goals, all while contributing to the Company’s success.
We recognize that attracting, retaining and developing our employees is critical for our future success. Our Executive Vice President of Land, Legal, Human Resources and Marketing, together with our Chief Executive Officer are responsible for developing and executing our human capital strategy, with oversight by the Board of Directors and the Board committees. Some of our key human capital areas of focus include:
Building a Safe Workforce Starts with Our Culture: Ring is committed to building a safety culture that empowers employees and contractors to act as needed to work safely and to stop the job, without retribution, if conditions are deemed unsafe. We strive to be incident-free every day across our operations. We are focused on building and maintaining a safe workplace for all employees and contractors. The oil and gas industry has a number of inherent risks and our workers are often outdoors, in all seasons and all types of weather. In addition, our field personnel spend significant time driving on a daily basis, putting them at risk for driving incidents. A strong safety culture is essential to the Company’s success, and we emphasize the important role that all personnel play in creating and maintaining a safe work environment.
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Health and Safety Training and Education: We offer a wide range of training opportunities for employees and contractors to help them develop their skills and understanding of our health and safety policy and programs. In addition to teaching specific skills, these training opportunities encourage personal responsibility for safe operating conditions and help to build a culture of individual accountability for conducting job tasks in a safe and responsible manner.
Ring 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’s support comes in the form of full or partial funding of educational programs and opportunities, including time off work to attend and/or prepare for such programs.
COVID-19 Response : Our COVID-19 management plan was built around the need to support all employees in managing their personal and professional challenges. Frequent and transparent communications were the focus at every level of the organization from those on the front lines to those in our corporate offices. During the early stages of the pandemic, Ring’s management team directed the Company's overall COVID-19 pandemic response by implementing all relevant county, state and local government guidelines, directives and regulations, and developed and adopted work-from-home provisions and procedures, implemented safe working protocols for production teams, assessed and implemented appropriate return-to-office protocols, and provided timely and transparent communications to employees and key stakeholders.
In response to the COVID-19 pandemic, Ring began providing the following benefits to its employees:
● covering the cost of COVID-19 testing through expanded insurance coverage;
● promoting telehealth benefits;
● promoting mental health and well-being plans;
● providing additional paid sick leave for quarantined employees.
Seasonal Nature of Business
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. 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. 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.