United States
Securities and Exchange Commission
Washington, D.C. 20549
Form 10-K
(Mark One)
For the fiscal year ended December 31 , 2023
Or
For the transition period from ______ to ______
Commission file number 001-36057
(Exact name of registrant as specified in its charter)
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Securities registered under Section 12(b) of the Exchange Act:
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Securities registered under Section 12(g) of the Exchange Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes o No x
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
| Large accelerated filer | o | x | ||||||||||||
| Non-accelerated filer | o | (Do not check if a smaller reporting company) | Smaller reporting company | |||||||||||
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If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. x
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is shell company (as defined in Rule 12b-2 of the Act). Yes o No x
As of June 30, 2023, the aggregate market value of the common voting stock held by non-affiliates of the registrant, based upon the closing stock price on that day on the NYSE American of $1.71 per share, was $227,493,793 .
As of March 7, 2024, the registrant had outstanding 197,934,202 shares of common stock ($0.001 par value).
DOCUMENTS INCORPORATED BY REFERENCE
The information required by Part III of this Report, to the extent not set forth herein, is incorporated herein by reference from the registrant’s definitive proxy statement relating to the Annual Meeting of Stockholders to be held in 2024, which definitive proxy statement shall be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this Report relates.
TABLE OF CONTENTS
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Forward Looking Statements
This Annual Report on Form 10-K (herein, “Annual Report”) contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Annual Report regarding our strategy, future operations, financial position, estimated revenues and expenses, projected costs, prospects, plans, and objectives of management are forward-looking statements. When used in this Annual Report, the words “may,” “will,” “could,” “would,” “should,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “plan,” “pursue,” “target,” “continue,” “potential,” “guidance,” “project,” or other similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. All forward-looking statements speak only as of the date of this Annual Report. Although we believe that our plans, intentions, and expectations reflected in or suggested by the forward-looking statements we make in this Annual Report are reasonable, we can give no assurance that these plans, intentions, or expectations will be achieved. We are making investors aware that such forward-looking statements, because they relate to future events, are by their very nature subject to many important factors that could cause actual results to differ materially from those contemplated. Such factors include:
•declines or volatility in the prices we receive for our oil and natural gas;
•our ability to raise additional capital to fund future capital expenditures;
•our ability to generate sufficient net cash provided by operating activities, borrowings, or other sources to enable us to fully develop and produce our oil and natural gas properties;
•general economic conditions, whether internationally, nationally, or in the regional and local market areas in which we do business;
•risks associated with drilling, including completion risks, cost overruns, mechanical failures, and the drilling of non-economic wells or dry holes;
•uncertainties associated with estimates of proved oil and natural gas reserves;
•the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;
•the effects of inflation on our cost structure;
•substantial declines in the estimated values of our proved oil and natural gas reserves;
•our ability to replace our oil and natural gas reserves;
•the effects of rising interest rates on our cost of capital and the actions that central banks around the world undertake to control inflation, including the impacts such actions have on general economic conditions;
•unanticipated reductions in the borrowing base under our credit agreement;
•the potential for production decline rates and associated production costs for our wells to be greater than we forecast;
•risks and liabilities associated with the acquisition and integration of companies and properties;
•cost and availability of drilling rigs, and related equipment, supplies, personnel, and oilfield services;
•geological concentration of our oil and natural gas reserves;
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•the timing and extent of our success in acquiring, discovering, developing, and producing oil and natural gas reserves;
•our dependence on the availability, use and disposal of water in our drilling, completion, and production operations;
•significant competition for oil and natural gas acreage and acquisitions;
•environmental or other governmental regulations, including legislation related to hydraulic fracture stimulation and climate change measures;
•our ability to secure reliable transportation for oil and natural gas we produce and to sell the oil and natural gas at market prices;
•future ESG compliance developments and increased attention to such matters which could adversely affect our ability to raise equity and debt capital;
•management’s ability to execute our plans to meet our optimal goals;
•the occurrence of cybersecurity incidents, attacks or other breaches to our information technology systems or on
systems and infrastructure used by the oil and gas industry;
•our ability to find and retain highly skilled personnel and our ability to retain key members of our management team on commercially reasonable terms;
•adverse weather conditions;
•costs and liabilities associated with environmental, health, and safety laws;
•the effect of our oil and natural gas derivative activities;
•social unrest, political instability, or armed conflict in major oil and natural gas producing regions outside the United States, including evolving geopolitical and military hostilities in the Middle East, Russia and Ukraine and acts of terrorism or sabotage;
•our insurance coverage may not adequately cover all losses that may be sustained in connection with our business activities;
•possible adverse results from litigation and the use of financial resources to defend ourselves;
•and the other factors discussed in Part I, Item 1A-- “Risk Factors” in this Annual Report, as well as in our financial statements, related notes, and the other financial information appearing elsewhere in this Annual Report and our other reports filed from time to time with the Securities and Exchange Commission (the “SEC”).
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date that such statements are made. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.
Unless the context otherwise requires, references in this Annual Report to “Ring,” “Ring Energy,” the “Company,” “we,” “us,” “our” or “ours” refer to Ring Energy, Inc.
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GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS
The following are abbreviations and definitions of terms commonly used in the oil and natural gas industry and within this report.
Bbl – One barrel or 42 U.S. gallons liquid volume of oil or other liquid hydrocarbons.
Boe – Barrel of oil equivalent, determined using a ratio of six Mcf of natural gas equal to one barrel of oil equivalent. The ratio does not assume price equivalency and, given price differentials, the price for a barrel of oil equivalent for natural gas differs significantly from the price for a barrel of oil. A barrel of natural gas liquids also differs significantly in price from a barrel of oil.
Boepd – Boe per day.
Btu – British thermal unit, the quantity of heat required to raise the temperature of one pound of water by one-degree Fahrenheit.
Completion – The process of treating and hydraulically fracturing a drilled well followed by the installation of permanent equipment for the production of oil and natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate regulatory agency.
Developed acreage – The number of acres which are allotted or assignable to producing wells or wells capable of production.
Development activities – Activities following exploration including the drilling and completion of additional wells and the installation of production facilities.
Dry hole or well – A well found to be incapable of producing hydrocarbons economically.
ESG – Environmental, Social and Governance.
Exploitation – A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.
Exploration – encompasses the processes and methods involved in locating potential sites for oil and natural gas drilling and extraction.
Field – An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Gross acres or gross wells – The total acres or wells, as the case may be, in which a working interest is owned.
Held by Production or HBP – A provision in an oil and gas property lease that extends a company's right to operate a property as long as the property produces a minimum amount of oil and/or gas.
Horizontal drilling – A drilling technique that permits the operator to drill horizontally within a specified targeted reservoir and thus exposes a larger portion of the producing horizon to a wellbore than would otherwise be exposed through conventional vertical drilling techniques.
Hydraulic fracturing or Fracking – A well stimulation method by which fluid, comprised largely of water and proppant (purposely sized particles used to hold open an induced fracture) is injected downhole and into the producing formation at high pressures and rates in order to exceed the rock strength and create a fracture such that the proppant material can be placed into the fracture to enhance the productive capability of the formation.
Injection well – A well which is used to inject gas, water, or liquefied petroleum gas under high pressure into a producing formation to maintain sufficient pressure to produce the recoverable reserves.
Joint Operating Agreement or JOA – Any agreement between working interest owners concerning the duties and responsibilities of the operator and rights and obligations of the non-operators.
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MBoe – One thousand barrels of oil equivalent, determined using a ratio of six Mcf of natural gas equal to one barrel of oil equivalent.
MMBoe – One million barrels of oil equivalent, determined using a ratio of six Mcf of natural gas equal to one barrel of oil equivalent.
MMBtu – One million Btu.
Mcf – One thousand cubic feet.
Natural gas liquids or NGL – Natural gas liquids measured in barrels. Natural gas liquids are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which have different uses and different pricing characteristics.
Net acres or net wells – The sum of the fractional working interests owned in gross acres or gross wells.
NYMEX – The New York Mercantile Exchange.
Overriding royalty interest or ORRI – An undivided interest in an oil, natural gas and mineral lease entitling the owner to a share of oil or natural gas production. The ORRI is carved out of the working interest or lease and cannot be fractionalized. It is an undivided, non-possessory right to a share of the production, excluding the mineral lease's drilling, production and operation costs.
Plugging and abandonment or P&A – Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another stratum or to the surface.
PV-10 – The present value of estimated future revenues, discounted at 10% annually, to be generated from the production of proved reserves determined in accordance with the SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to (i) non-property related expenses such as general and administrative expenses, debt service, and future income tax expense, and (ii) depreciation, depletion and amortization.
Productive well – A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.
Proppant – A solid material, typically treated sand or man-made ceramic materials, designed to keep an induced hydraulic fracture open, during or following a fracturing treatment.
Proved developed nonproducing reserves or PDNP – Hydrocarbons in a potentially producing horizon penetrated by a wellbore, the production of which has been postponed pending completion activities and the installation of surface equipment or gathering facilities or pending the production of hydrocarbons from another formation penetrated by the wellbore. The hydrocarbons are classified as proved developed but nonproducing reserves.
Proved developed producing reserves or PDP – Reserves that can be expected to be recovered from existing wells and completions with existing equipment and operating methods.
Proved developed reserves or PD – The estimated quantities of oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved reserves – Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.
Proved undeveloped reserves or PUD – Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
Recompletion – The completion for production of an existing well bore in another formation from that in which the well has been previously completed.
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Reservoir – A permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Royalty interest – An interest in an oil and natural gas property entitling the royalty owner to a share of oil and/or natural gas production free of costs of production.
RRC – Texas Railroad Commission.
Shut-in reserves – Those reserves expected to be recovered from completion intervals that were open at the time the reserve was estimated but were not producing due to market conditions, mechanical difficulties, or because production equipment or pipelines were not yet installed. These reserves are included in the PDNP category in our reserve report.
SOFR – Secured Overnight Financing Rate.
Standardized Measure – The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue.
Undeveloped acreage – Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Working interest or WI – The ownership interest, generally defined in a JOA, that gives the owner the right to drill, produce, and/or conduct operating activities on the leased property and share in the sale of production therefrom, subject to all royalties, overriding royalties, and other lease burdens. In addition, the owner of the working interest must share in all costs of exploration, development operations and all risks in connection therewith.
Workover – Operations on a producing well to restore or increase production.
WTI – West Texas Intermediate light sweet crude oil, a benchmark in crude oil pricing.
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PART I
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 oil and natural gas exploration and production company based in The Woodlands, Texas and is engaged in oil and natural gas development, production, acquisition, and exploration activities currently focused in the Permian Basin of Texas. Our drilling operations target the oil and liquids rich producing formations in the Northwest Shelf and the Central Basin Platform, in the Permian Basin in Texas.
As of December 31, 2023, our leasehold acreage positions totaled 96,127 gross (80,535 net) acres and we held interests in 1,043 gross (864 net) producing wells. Proved reserves as of December 31, 2023 (based upon the report of our independent petroleum engineer of that date) were approximately 129.8 million Boe, of which we are the operator of approximately 98%. All of our properties are located in the Permian Basin and our proved reserves are oil-weighted, with approximately 63% consisting of oil, 19% consisting of natural gas, and 18% consisting of NGLs. Approximately 68% of the reserves are classified as PD and 32% are classified as PUD. Within the PD reserve category, 242 recompletion and re-activation opportunities are classified as PDNP and within the PUD reserve category, we have a total of 211 proved locations (33% horizontal and 67% vertical) based on the reserve report as of December 31, 2023. 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.
2023 Highlights and Major Developments
•Closed the Founders Acquisition on August 15, 2023
•Achieved record full year production of 18,119 Boepd (69% oil), a year-over-year increase of 47%
•Executed a phased drilling program in 2023 that included drilling 31.00 gross / 29.75 net operated wells consisting of 20.00 horizontal and 11.00 vertical wells (gross). In addition, the Company participated in 5.00 non-operated wells.
•Maintained our revolving credit facility borrowing base of $600 million
•Total Proved Reserves were 129.8 MMBoe at year-end 2023
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 that 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. Key principles supporting Ring’s strategic vision are to:
•ensure health, safety, and environmental excellence, and a strong commitment to Ring’s employees and the communities in which we work and operate;
•continue our focus on generating adjusted 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 our balance sheet by steadily paying down debt, divesting of non-core assets and becoming a peer leader in Debt/EBITDA metrics.
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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 adjusted free cash flow and strengthening 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 adjusted free cash flow through a disciplined capital allocation program and reducing our operating and corporate costs are key components of this objective. Our capital program is funded by operational cash flow and seeks to balance our production and reserve growth with paying down debt. 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 actively pursue accretive acquisitions, mergers, and property dispositions in seeking to improve our margins, returns, and break-even costs. Financial strategies associated with these efforts focus on delivering competitive debt-adjusted per share returns. This objective is key to delivering competitive returns to our shareholders on a sustainable basis.
Founders Acquisition
On August 15, 2023, the Company, as buyer, and Founders Oil & Gas IV, LLC (“Founders”), as seller, closed the Asset Purchase Agreement (the “Founders Purchase Agreement”) under which the Company acquired (the “Founders Acquisition”) interests in oil and gas leases and related property of Founders in the Central Basin Platform of the Permian Basin in Ector County, Texas.
Common Warrants Exercised
During 2023, the Company reduced its dilutive shares through the exercise of 19,029,593 of the Company's outstanding common warrants, bringing the total outstanding to 78,200 common warrants as of December 31, 2023. This was accomplished by the exercise of 4,517,427 common warrants at an exercise price of $0.80 per share and the exercise of 14,512,166 common warrants at an exercise price of $0.62 per share, through amendments to certain warrant agreements. These exercises resulted in $12,301,596 of net proceeds to the Company after payment of $309,888 in advisory fees.
Primary Business Operations
We seek to rigorously manage our asset portfolio to optimize shareholder value over the long term.
In the first quarter of 2023, in the Northwest Shelf, the Company drilled and completed two 1-mile horizontal wells (each with a working interest of 100%), and two 1.5-mile horizontal wells (one with a working interest of approximately 99.8% and the other with a working interest of approximately 75.4%). Next, in its Crane County acreage within the Central Basin Platform, the Company drilled and completed three vertical wells (each with a working interest of 100%) and performed six vertical well recompletions (each with a working interest of 100%).
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In the second quarter of 2023, in the Northwest Shelf, the Company drilled and completed two 1.5-mile horizontal wells (one with a working interest of 100% and the other with a working interest of approximately 75.4%) and two 1-mile horizontal wells (both with a working interest of approximately 91.1%). Additionally, in its Crane County acreage within the Central Basin Platform, the Company drilled and completed two vertical wells (each with a working interest of 100%) and performed three vertical well recompletions (each with a working interest of 100%).
During the third quarter of 2023, the Company drilled and completed two 1-mile horizontal wells (one with a working interest of 100% and the other with a working interest of 75%) in the Northwest Shelf, and three 1.5-mile horizontal wells (each with a working interest of 100%) in the Central Basin Platform. Additionally, in its Crane County acreage within the Central Basin Platform, the Company drilled and completed three vertical wells (each with a working interest of 100%). Lastly, the Company drilled and began the completion process on three 1-mile horizontal wells in the Northwest Shelf (each with a working interest of 100%).
In the fourth quarter of 2023, the Company completed and placed on production the three aforementioned 1-mile horizontal wells in the Northwest Shelf. Additionally, the Company drilled and completed one saltwater disposal (SWD) well in the Northwest Shelf (with a working interest of 100%), and completed the 2023 horizontal drilling program with one 1.5-mile horizontal well in the Northwest Shelf (with a working interest of approximately 97.7%), as well as two 1-mile horizontal wells and one 1.5-mile horizontal well (each with a working interest of 100%) in the Central Basin Platform. In its Crane County acreage within the Central Basin Platform, the Company drilled and completed three vertical wells (each with a working interest of 100%).
In summary, for 2023, the Company drilled and completed 20 horizontal wells, 11 vertical wells, and 1 SWD well. In addition, the Company performed 9 vertical well recompletions. The table below sets forth our drilling and completion activities for 2023 by quarter, and full year total through December 31, 2023.
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| Quarter | Area | Wells Drilled | Wells Completed | Recompletions | ||||||||||||||||||||||
| 1Q 2023 | Northwest Shelf (Horizontal) | 4 | 4 | — | ||||||||||||||||||||||
| Central Basin Platform (Horizontal) | — | — | — | |||||||||||||||||||||||
| Central Basin Platform (Vertical) | 3 | 3 | 6 | |||||||||||||||||||||||
Total | 7 | 7 | 6 | |||||||||||||||||||||||
| 2Q 2023 | Northwest Shelf (Horizontal) | 4 | 4 | — | ||||||||||||||||||||||
| Central Basin Platform (Horizontal) | — | — | — | |||||||||||||||||||||||
| Central Basin Platform (Vertical) | 2 | 2 | 3 | |||||||||||||||||||||||
| Total | 6 | 6 | 3 | |||||||||||||||||||||||
| 3Q 2023 | Northwest Shelf (Horizontal) | 5 | 2 | — | ||||||||||||||||||||||
| Central Basin Platform (Horizontal) | 3 | 3 | — | |||||||||||||||||||||||
| Central Basin Platform (Vertical) | 3 | 3 | — | |||||||||||||||||||||||
| Total | 11 | 8 | — | |||||||||||||||||||||||
| 4Q 2023 | Northwest Shelf (Horizontal) | 1 | 4 | — | ||||||||||||||||||||||
| Central Basin Platform (Horizontal) | 3 | 3 | — | |||||||||||||||||||||||
| Central Basin Platform (Vertical) | 3 | 3 | — | |||||||||||||||||||||||
Total (1) | 7 | 10 | — | |||||||||||||||||||||||
FY 2023 | Northwest Shelf (Horizontal) | 14 | 14 | — | ||||||||||||||||||||||
| Central Basin Platform (Horizontal) | 6 | 6 | — | |||||||||||||||||||||||
| Central Basin Platform (Vertical) | 11 | 11 | 9 | |||||||||||||||||||||||
Total (1) | 31 | 31 | 9 | |||||||||||||||||||||||
(1) Fourth quarter total and full year total do not include one SWD well completed in the Northwest Shelf.
Ring Energy’s Strengths
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 with substantive technical and operational expertise;
•operating control over most of our production and development activities; and
•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 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. In addition, those companies may be able to pay more for productive oil and natural gas properties
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and exploratory prospects, and to evaluate, bid for, and purchase a greater number of properties and prospects than what our financial or technical resources permit. Our ability to acquire additional properties and to find and develop reserves in the future will depend on our ability to identify, evaluate, and select suitable properties and to consummate transactions in this highly competitive environment.
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 in our areas of operation. 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 is not currently realistic as it 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 third-party pipelines which have no regional competition and all other oil production is transported by the oil purchaser by trucks with competitive trucking costs in the area.
Our oil is transported from the wellhead to tank batteries or delivery points through our flow-lines or gathering systems. 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, as an ongoing practice, we install vapor recovery units in our newly installed tank batteries which also reduces emissions. Our produced saltwater is generally moved by pipeline connected to our operated saltwater disposal wells or by pipeline to commercial disposal facilities.
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 year ended December 31, 2023, sales to three customers, Phillips 66 Company ("Phillips"), Enterprise Crude Oil LLC ("Enterprise"), and NGL Crude Partners ("NGL Crude"), and represented 66%, 12%, and 10%, respectively, of our oil, natural gas, and natural gas liquids revenues. As of December 31, 2023, Phillips represented 65% of our accounts receivable, Enterprise represented 11% of our accounts receivable and NGL Crude represented 8% of our accounts receivable. We believe that the loss of any of these purchasers would not materially impact our business because we could readily find other purchasers for our oil and natural gas.
Delivery Commitments
As of December 31, 2023, 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, thereby reducing our exposure to downside commodity prices and enabling us to protect cash flows to meet our debt obligations under our credit facility and secondarily to maintain liquidity to fund our capital expenditures needs.
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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.
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, in January 2021, President Biden signed an Executive Order directing the Department of Interior (the “DOI”) to temporarily pause new oil and gas leases on federal lands and waters pending completion of a comprehensive review of the federal government’s existing oil and gas leasing and permitting program. In June 2021, a federal district court enjoined the DOI from implementing the pause and leasing resumed, although litigation over the leasing pause remains ongoing. In February 2022, another judge ruled that the Biden Administration’s efforts to raise the cost of climate change in its environmental assessments, would increase energy costs and damage state revenues from energy production. This ruling has caused federal agencies to delay issuing new oil and gas leases and permits on federal lands and waters.
Currently, all of our operated properties are in Texas, which has regulations governing conservation matters, such as the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. 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, Texas imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its 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 NGLs 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, (“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 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”) and regulations issued
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under those Acts by the FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.
Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.
We cannot accurately predict whether the FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. Therefore, we cannot provide any assurance that the less stringent regulatory approach established by the FERC will continue. 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 (“OPA”); 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 (“SDWA”). 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, 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.
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 NGLs are not designated as a “hazardous substance” under CERCLA, other chemicals used in or generated by our operations may be regulated as hazardous substances. Potentially
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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 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. Federal and state regulatory agencies can seek to impose administrative, civil, and criminal penalties for alleged non-compliance with RCRA and analogous state requirements. Certain wastes associated with the production of oil and natural gas, as well as certain types of petroleum-contaminated media and debris, are excluded from regulation as hazardous waste under Subtitle C of RCRA. These wastes, instead, are regulated as solid waste (i.e. non-hazardous waste) under the less stringent provisions of Subtitle D of RCRA. 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 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 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
Our operations are subject to the CAA and comparable state and local laws and regulations, which regulate emissions of air pollutants from various sources and mandate certain permitting, monitoring, recordkeeping, and reporting requirements. The CAA and its implementing regulations may require that we obtain permits prior to the construction, modification, or operation of certain projects or facilities expected to produce or increase air emissions above certain threshold levels and strictly comply with those permits, including emissions and operational limitations. These permits may require us to install emission control technologies to limit emissions, which can impose significant costs on our business.
In November 2021, the EPA issued a proposed rule under the CAA’s New Source Performance Standards, known as Subpart OOOOa, intended to reduce methane emissions from new and existing oil and gas sources. The proposed rule would make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the CAA (including intermittent vent pneumatic controllers, associated gas, and liquids unloading facilities). In addition, the proposed rule would establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by the EPA. In November 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule. Among other things, the November 2022 supplemental proposed rule removes an emissions monitoring exemption for small wellhead-only sites and creates a new third-party monitoring program to flag large emissions events, referred to in the proposed rule as “super emitters.” In December 2023, the EPA announced a final rule, which, among other things, requires the phase out of routine flaring of natural gas from newly constructed wells (with some exceptions) and routine leak monitoring at all well sites and compressor stations. Notably, the EPA updated the applicability date for Subparts OOOOb and OOOOc to December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with later compliance deadlines under state plans. The final rule gives states two years to develop and submit their plans for reducing methane emissions from existing sources. The final emissions guidelines under Subpart OOOOc provide three years from the plan submission deadline for existing sources to comply. Compliance with these or any new regulations could result in stricter permitting requirements, which in turn could delay or impair our ability to obtain air emission permits and could result in increased expenditures for pollution control equipment, the costs of which could be significant.
On August 16, 2022, President Biden signed the Inflation Reduction Act of 2022 (“IRA”). The IRA allocated $1.55 billion to the Methane Emissions and Waste Reduction Incentive Program. The IRA also required the EPA to
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implement a waste emission charge on methane emitted from applicable oil and gas facilities that exceed certain thresholds. The methane charge goes into effect in 2024 at $900 per metric ton of methane and increases to $1,500 per metric ton of methane by 2026. On January 12, 2024, the EPA announced a proposed rule to implement the methane emissions charge.The charge will act as an incentive for operators to reduce emissions by minimizing leaks and replacing equipment rather than paying for excessive emissions.
While the State of Texas has not formally conducted a recent rulemaking related to air emissions, scrutiny of oil and natural gas operations and the rules affecting them have increased in recent years. For example, the EPA and environmental non-governmental organizations have conducted flyovers with optical gas imaging cameras to survey emissions from oil and natural gas production facilities and transmission infrastructure. In August 2022, for example, the EPA announced that it would be conducting helicopter flyovers of the Permian Basin region in Texas. The flyovers used infrared cameras to survey oil and gas operations to identify large emitters of methane and volatile organic compounds ("VOCs"). Based on data obtained during flyovers, EPA intends to initiate enforcement follow up actions with facilities operators. In addition, the RRC has increased oversight related to flaring, with reporting reviews and site inspections. While none of these activities increases our compliance obligations, they signal the potential for increased enforcement and possible rulemaking in the future.
Oil Pollution Prevention
The OPA amended the CWA to impose liability for releases of crude oil from vessels or facilities into navigable waters. If a release of crude oil into navigable waters occurs during shipment or from an oil terminal, we could be subject to liability under the OPA. 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 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.
In January 2023, the EPA and the Corps issued a final rule that revises the definition of WOTUS. Separately, in May 2023, the U.S. Supreme Court’s decision in Sackett v. EPA narrowed federal jurisdiction over wetlands to “traditional navigable waters” and wetlands or other waters that have a “continuous surface connection” with or are otherwise indistinguishable from traditional navigable water. In September 2023, the EPA and the Corps published a direct-to-final rule that conforms the regulatory definition of “Waters of the United States” to the Supreme Court’s May 2023 decision in Sackett. However, litigation opposing the September 2023 final rule remains ongoing and substantial uncertainty exists with respect to future implementation of the September 2023 rule and the scope of CWA jurisdiction more generally. To the extent the rule or any future rule or court decision expands the scope of the CWA’s jurisdiction, we could face increased permitting costs and project delays.
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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 SDWA, as well as by state programs. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluid from the injection zone into underground sources of drinking water, as well as to prevent communication between injected fluids and zones capable of producing hydrocarbons. The SDWA establishes requirements for permitting, testing, monitoring, recordkeeping, and reporting of injection well activities, as well as a prohibition against the migration of fluid containing contaminants into underground sources of drinking water. Any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in the suspension of permits, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource, and imposition of liability by third parties for property damages and personal injuries.
Under the auspices of the federal UIC program as implemented by states with UIC primacy, regulators, particularly at the state level, are becoming increasingly sensitive to possible correlations between underground injection and seismic activity. Consequently, state regulators implementing both the federal UIC program and state corollaries are heavily scrutinizing the location of injection facilities relative to faulting and are limiting both the density and injection facilities as well as the rate of injection.
In Texas, the RRC regulates the disposal of produced water by injection well. Permits must be obtained before drilling saltwater disposal wells, and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking saltwater to groundwater. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SDWA and state laws. In response to recent seismic events near underground injection wells used for the disposal of oil and natural gas-related waste waters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or placed volumetric injection limits on existing wells or imposed moratoria on the use of such injection wells. In response to concerns related to induced seismicity, regulators in some states have already adopted or are considering additional requirements related to seismic safety. For example, the RRC has adopted rules for injection wells to address these seismic activity concerns in Texas. Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. More stringent regulation of injection wells could lead to reduced construction or the capacity of such wells, which could in turn impact the availability of injection wells for disposal of wastewater from our operations. Increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability. The costs associated with the disposal of produced water are commonly incurred by all oil and natural gas producers, however, and we do not believe that these costs will have a material adverse effect on our operations. In addition, third-party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury.
Hydraulic Fracturing
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 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.
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, specific oil and natural gas regulations apply to oil and gas operations, including the drilling, completion and operations of wells, and the disposal of waste oil and salt water. In October 2023, the RRC announced draft amendments to its water protection rules to, among other things, encourage waste recycling. There are also procedures incident to the plugging and abandonment of dry holes or other non-operational wells, all as governed by the applicable governing state agency. As an example, the RRC adopted rules in 2014 requiring companies seeking permits for disposal wells to provide seismic activity data in permit applications. The rules also allow the RRC to modify,
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suspend, or terminate permits if a disposal well is determined to be causing seismic activity. Determinations by the RRC under these rules may adversely affect our operations.
Local governments may also seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. In Texas, however, local governments are expressly preempted from regulating oil and gas operations with limited exceptions, under Texas Natural Resources Code Section 81.0523. If new laws or regulations that significantly restrict hydraulic fracturing are adopted at the local, state, or federal level, our fracturing activities could become subject to additional permit and financial assurance requirements, more stringent construction requirements, increased reporting or plugging and abandoning requirements or operational restrictions and associated permitting delays and potential increases in costs. 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. 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 and processing facilities on an annual basis, as well as reporting GHG emissions from gathering and boosting systems, oil well completions and workovers using hydraulic fracturing.
In addition, in November 2016, the BLM issued final rules to reduce methane emissions from venting, flaring, and leaks during oil and natural gas operations on federal lands that are substantially similar to the CAA’s New Source Performance Standards in 40 C.F.R. Part 60, Subpart OOOOa (“GHG NSPS”) requirements. In September 2018, the BLM published a final rule revising or rescinding certain provisions of the 2016 rule, which became effective on November 27, 2018. Both the 2016 and the 2018 rule were challenged in federal court resulting in the rescission of both rules. Appeals to those decisions are ongoing, but with little activity in the last several years. 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.
Additionally, a number of state and regional efforts are aimed at tracking and/or reducing GHG emissions by means of cap-and-trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. At the international level, there is an agreement, the United Nations-sponsored "Paris Agreement," for nations to limit their GHG emissions through non-binding, individually determined reduction goals every five years after 2020. The United States rejoined the Paris Agreement in February 2021. In early 2021, the Biden Administration issued a moratorium on oil and gas leasing on federal lands and waters to reduce emissions. Since then, the moratorium has been the subject of litigation and, in August 2022, a federal judge entered an injunction against the moratorium. In November 2021, the United States participated in the United Nations Climate Change Conference in Glasgow, Scotland, United Kingdom (“COP26”). COP26 resulted in a pact among approximately 200 countries, including the United States, called the Glasgow Climate Pact. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. In conjunction with COP26, the United States committed to an economy-wide target of reducing net greenhouse gas emissions by 50-52 percent below 2005 levels by 2030. Also in November 2021, President Biden signed a $1 trillion dollar infrastructure bill into law. The new infrastructure law includes several climate-focused investments, including upgrades to power grids to accommodate increased use of renewable energy and expansion of electric vehicle infrastructure. The above-referenced IRA allocated $369 billion to energy and climate initiatives. In November 2022, the United States participated in the United Nations Climate Change Conference in Egypt (“COP27”). In December 2023, the United States participated in the United Nations Climate Change Conference in the United Arab Emirates (“COP28”). Further, several states and local governments remain committed to the principles of the Paris Agreement in their effectuation of policy and regulations. Although it is not possible at this time to predict what additional domestic legislation may be adopted in light of the Paris Agreement or the
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Glasgow Climate Pact, or how legislation or new regulations that may be adopted based on the Paris Agreement or the Glasgow Climate Pact to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, limiting emissions of GHGs from, our equipment and operations, or restricting federal leases could impair our production, could require us to incur costs to reduce emissions of GHGs associated with our operations and could decrease demand for oil and natural gas.
In September 2023, the Biden Administration directed federal agencies to consider the Social Cost of GHGs metric in budgeting, procurement and other agency decisions, including in environmental reviews, where appropriate. Several states, though none in the areas where we operate, have implemented, of their own accord or in coordination with their neighbor states, regional initiatives and programs limiting, monitoring or otherwise regulating GHG emissions.
The adoption and implementation of any laws or regulations imposing reporting obligations on, or limiting emissions of GHG from, our equipment and operations could require additional expenditures to reduce emissions of GHGs associated with its operations or could adversely affect demand for the oil and natural gas we produce, and thus possibly have a material adverse effect on our revenues, as well as having the potential effect of lowering the value of our reserves. Recently, stakeholders concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities. Finally, to the extent increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events, such events could have a material adverse effect on the Company and potentially subject the Company to further regulation. The trend of more expansive and stringent environmental legislation and regulations, including greenhouse gas regulation, could continue, resulting in increased costs of conducting business and consequently affecting our profitability. We also are aware that the SEC intends to propose new and additional rules regarding company disclosure of climate change risk. We will monitor and comply with any such promulgated rules.
Threatened and endangered species
Various federal and state statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands, and natural resources. These statutes include the Endangered Species Act (“ESA”), the Migratory Bird Treaty Act (“MBTA”) and the Clean Water Act. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. The U.S. Fish and Wildlife Service (“FWS”) may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause increased costs arising from species protection measures or could result in limitations on development activities that could have an adverse impact on the ability to develop and produce reserves within our assets. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.
Operational Hazards and Insurance
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.
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Human Capital Management
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 that contribute to the communities in which they live.
As of December 31, 2023, we had 108 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 23% are women and approximately 50% represent minorities. The majority of our employees are citizens of the United States, with a few retaining dual citizenship in other countries. The employees who are not US citizens, are legally registered to live and work here and the Company is committed to helping those employees retain their ability to remain in the US and continue their employment. The Company is also committed to continuously providing an inclusive work environment where all of our employees can be respected, valued, and successful in achieving their goals, all while contributing to the Company’s success.
We recognize that attracting, retaining and developing our employees is critical for our future success. Our Executive Vice President of Land, Legal, Human Resources and Marketing, together with our Chief Executive Officer are responsible for developing and executing our human capital strategy, with oversight by the Board of Directors and the Board committees. Some of our key human capital areas of focus include:
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 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: 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 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 are the focus at every level of the organization from those on the front lines to those in our corporate offices. During the early stages of the pandemic, Ring’s management team directed the Company’s overall COVID-19 pandemic response by implementing all relevant county, state and local government guidelines, directives, and regulations, and developed and adopted work-from-home provisions and procedures, implemented safe working protocols for production teams, assessed and implemented appropriate return-to-office protocols, and provided timely and transparent communications to employees and key stakeholders.
In response to the COVID-19 pandemic, Ring began providing the following benefits to its employees:
•covering the cost of COVID-19 testing through expanded insurance coverage;
•promoting telehealth benefits;
•promoting mental health and well-being plans; and
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•providing additional paid sick leave for quarantined employees.
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 will be available through our website free of charge as soon as reasonably practical after we electronically file such material with, or furnish it to, the SEC. The information on, or that can be accessed through, our website is not incorporated by reference into this Annual Report and should not be considered part of this Annual Report. The SEC also maintains a website (http://www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.
Item 1A: Risk Factors
We are subject to various risks and uncertainties in the ordinary course of our business. The following summarizes significant risks and uncertainties that may adversely affect our business, financial condition, or results of operations. We cannot assure you that any of the events discussed in the risk factors below will not occur. Further, the risks and uncertainties described below are not the only ones we face. Additional risks not presently known to us or that we currently deem immaterial may also materially affect our business. Readers should carefully consider the risk factors included below as well as those matters referenced in this Report under “Forward-Looking Statements” and other information included and incorporated by reference into this Report.
Risks Relating to Our Business, Operations, and Strategy
Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve additional risks and uncertainties in their application compared to vertical drilling.
Our operations use some of the latest horizontal drilling and completion techniques as developed by us, other oil and natural gas exploration and production companies and our service providers. The additional risks that we face while drilling horizontally include, but are not limited to, the following:
•drilling wells that are significantly longer and/or deeper than vertical wells;
•landing our wellbores in the desired drilling zones;
•staying in the desired drilling zones while drilling horizontally through the formations;
•running our casing the entire length of wellbores; and
•being able to run tools and other equipment consistently through horizontal wellbores.
Risks that we face while completing our wells include, but are not limited to, the following:
•the ability to fracture or stimulate the planned number of stages in a horizontal or lateral wellbore;
•the ability to run tools and other equipment the entire length of a wellbore during completion operations; and
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•the ability to successfully clean out a wellbore after completion of the final fracture stimulation stage.
If our assessments of purchased properties are materially inaccurate, it could have a significant impact on future operations and earnings.
The successful acquisition of producing properties requires assessments of many factors, which are inherently inexact and may be inaccurate, including the following:
•unforeseen title issues;
•the amount of recoverable reserves;
•future oil and natural gas prices;
•estimates of operating costs;
•estimates of future development costs;
•estimates of the costs and timing of plugging and abandonment of wells; and
•potential environmental and other liabilities.
Our assessments will not reveal all existing or potential problems, nor will they permit us to become familiar enough with the potential properties we may acquire to assess fully their capabilities and deficiencies. We plan to undertake further development of our properties generally through the use of cash flow from existing production. Therefore, a material deviation in our assessments of these factors could result in less cash flow being available for such purposes than we presently anticipate, which could either delay future development operations (and delay the anticipated conversion of reserves into cash) or cause us to seek alternative sources to finance development activities.
Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.
Our prospects are in various stages of evaluation, ranging from prospects that are currently being drilled to prospects that will require substantial additional seismic data processing and interpretation. We are unable to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. This risk may be enhanced in our situation, due to the fact that a significant percentage of our proved reserves is currently proved undeveloped reserves. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data obtained by analyzing other wells, more fully explored prospects or producing fields will be applicable to all of our drilling prospects.
A substantial percentage of our proved properties are undeveloped; therefore, the risk associated with our success is greater than would be the case if a substantial majority of our properties were categorized as proved developed.
Because a substantial percentage of our proved properties are proved undeveloped (approximately 32%), we will require significant additional capital to develop such properties before they may become productive. Further, because of the inherent uncertainties associated with drilling for oil and gas, some of these properties may never be developed to the extent that they result in commercial quantities of oil and natural gas.
While our current business plan is to generally fund the development costs with cash flow from our other producing properties, if such cash flow is not sufficient, we may be forced to seek alternative sources for cash, through the issuance of additional equity or debt securities, increased borrowings or other means.
Hedging transactions may limit our potential gains.
To reduce our exposure to commodity price uncertainty and increase cash flow predictability, we have entered into crude oil and natural gas price hedging arrangements with respect to a significant portion of our expected production in order to economically hedge a portion of our forecasted oil and natural gas production. Additionally, our credit facility
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requires us to hedge a significant portion of our production. These derivative contracts typically limit the benefit we would otherwise receive from increases in the prices for oil and natural gas.
Hedging transactions may expose us to risk of financial loss.
While intended to reduce the effects of volatile oil and natural gas prices, derivative contracts designed as hedges expose us to risk of financial loss in some circumstances, including when there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received, or when the counterparty to the derivative contract defaults on its contractual obligations. It is also possible that sales volumes fall below the hedged volumes leaving a portion of our position uncovered.
We may be adversely affected by natural disasters, pandemics and other catastrophic events, and by man-made problems such as terrorism, that could disrupt our business operations.
Natural disasters, adverse weather conditions (particularly abnormally cold weather and thunderstorms), floods, pandemics, acts of terrorism and other catastrophic or geo-political events may cause damage or disruption to our operations and the global economy, or could result in market disruptions, any of which could have an adverse effect on our business, operating results, and financial condition.
The coronavirus outbreak impacted various businesses throughout the world, including an impact on the global demand for oil and natural gas, travel restrictions and the extended shutdown of certain businesses in impacted geographic regions. If other pandemics occur, they could have a material adverse impact on our business operations, operating results and financial condition.
The loss of key members of management or failure to attract and retain other highly qualified personnel could affect the Company’s business results.
Our success depends on our ability to attract, retain and motivate a highly-skilled management team and workforce. Failure to ensure that we have the depth and breadth of management and personnel with the necessary skill sets and experience could impede our ability to achieve growth objectives and execute our operational strategy. As we continue to expand, we will need to promote or hire additional staff, and, as a result of increased compensation and benefit packages in our industry, as well as inflationary pressures, it may be difficult to attract or retain such individuals without incurring significant additional costs.
Risks Relating to the Oil and Natural Gas Industry
A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure obligations and financial commitments.
The prices we receive for our oil and natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile and we expect these markets will likely continue to be volatile. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include, but are not limited to, the following:
•changes in global supply and demand for oil and natural gas;
•the actions of the Organization of Petroleum Exporting Countries, or OPEC;
•the actions of oil exporting countries that are not members of OPEC;
•the price and quantity of imports and exports of oil and natural gas;
•political conditions, including embargoes, in or affecting other oil-producing activities;
•acts of war and related armed conflicts;
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•the level of global oil and natural gas exploration and production activity;
•the level of global oil and natural gas inventories;
•weather conditions;
•technological advances affecting energy consumption; and
•the price and availability of alternative fuels.
Lower oil and natural gas prices may not only decrease our revenues on a per Boe basis but also may reduce the amount of oil and natural gas that we can produce economically. Lower prices also negatively impact the value of our proved reserves. A substantial or extended decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity and ability to finance planned capital expenditures.
Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations.
Our future success will depend on our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. For example, in January 2021, President Biden signed an Executive Order directing the Department of Interior (the “DOI”) to temporarily pause new oil and gas leases on federal lands and waters pending completion of a comprehensive review of the federal government’s existing oil and gas leasing and permitting program. In June 2021, a federal district court enjoined the DOI from implementing the pause and leasing resumed, although litigation over the leasing pause remains ongoing. In February 2022, another judge ruled that the Biden Administration’s efforts to raise the cost of climate change in its environmental assessments, would increase energy costs and damage state revenues from energy production. This ruling has cause federal agencies to delay issuing new oil and gas leases and permits on federal lands and waters. While we do not have any federal lands acreage at this time, these actions could have a material adverse effect on our industry, the public perception of oil and gas companies such as ours and the willingness of the public and financial institutions to provide capital for our industry.
Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Please read “—Reserve estimates depend on many assumptions that may turn out to be inaccurate.” (below) for a discussion of the uncertainty involved in these processes. Our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular well or project uneconomical. Further, many factors may curtail, delay or cancel drilling, including delays imposed by or resulting from compliance with regulatory requirements; pressure or irregularities in geological formations; shortages of or delays in obtaining equipment and qualified personnel; equipment failures or accidents; adverse weather conditions; reductions in oil and natural gas prices; title problems; and limitations in the market for oil and natural gas.
Decreases in oil and natural gas prices may require us to take write-downs of the financial carrying values of our oil and natural gas properties which could negatively impact the trading value of our common stock.
Accounting rules require that we review periodically the financial carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write-down the financial carrying value of our oil and natural gas properties. A write-down would likely constitute a non-cash charge. The cumulative effect of one or more write-downs could also negatively impact the trading price of our common stock.
We follow the full cost method of accounting for our oil and natural gas properties. Under the full cost method, the net book value of properties, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling is the estimated after tax future net revenues from proved oil and natural gas properties, discounted at 10% per year. Discounted future net revenues are estimated using oil and natural gas spot prices based on the average price during the preceding 12-month period determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, except for changes which are fixed and determinable by existing contracts. The net book value is
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compared to the ceiling on a quarterly basis. The excess, if any, of the net book value above the ceiling is required to be written off as an impairment expense. During the years ended December 31, 2023, 2022, and 2021 we did not incur any write-downs. Under SEC full cost accounting rules, any write-off recorded may not be reversed even if higher oil and natural gas prices increase the ceiling applicable to future periods. Future price decreases could result in reductions in the financial carrying value of such assets and an equivalent charge on our financial statements.
It is difficult to predict with reasonable certainty the amount of any future impairments given the many factors impacting the ceiling test calculation including, but not limited to, future pricing, operating costs, upward or downward reserve revisions, reserve adds, and tax attributes.
Decreases in oil and natural gas prices may affect our bank borrowing base, potentially requiring earlier than anticipated debt repayment, which could negatively impact our financial position, results of operations and the trading value of our common stock.
Decreases in oil and natural gas prices could result in reductions in the borrowing base under our Credit Facility, thus requiring earlier than anticipated repayment of debt or trigger a possible default under our Credit Facility in the event we are unable to make payments or repayments under the Credit Facility on a timely basis.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could negatively affect the estimated quantities and present value of our reported reserves.
In order to prepare our estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reported reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
You should not assume that the present value of future net revenues from our reported proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we generally base the estimated discounted future net cash flows from our proved reserves on prices and costs calculated on the date of the estimate. Discounted future net revenues are estimated using oil and natural gas spot prices based on the average price during the preceding 12-month period determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, except for changes which are fixed and determinable by existing contracts. Actual future prices and costs may differ materially from those used in the present value estimate. If future values decline or costs increase it could negatively impact our ability to finance operations, and individual properties could cease being commercially viable, affecting our decision to continue operations on certain producing properties or to attempt to develop properties. All of these factors would have a negative impact on earnings and net income, and most likely the trading price of our common stock. These factors could also result in the acceleration of debt repayment and a reduction in our borrowing base under our Credit Facility.
We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations.
We are not insured against all risks. Losses and liabilities arising from uninsured and under insured events could materially and adversely affect our business, financial condition and results of operations. Our oil and natural gas
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exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:
•environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater;
•abnormally pressured formations;
•mechanical difficulties, such as stuck oil field drilling and service tools and casing collapses;
•fires and explosions;
•personal injuries and death; and
•natural disasters.
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to our Company. We may elect to not obtain certain insurance coverage if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, then it could materially and adversely affect us.
Unless we replace our oil and natural gas reserves, our reserves and production will decline as reserves are produced.
Unless we conduct successful exploration and development activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and, therefore, our cash flow and income, are highly dependent on our success in efficiently developing and producing our current reserves and economically finding or acquiring additional recoverable reserves. If we are unable to develop, find or acquire additional reserves to replace our current and future production, our cash flow and income will decline as production declines, until our existing properties would be incapable of sustaining commercial production.
Competition is intense in the oil and natural gas industry.
We operate in a highly competitive environment for acquiring properties and marketing oil and natural gas. Our competitors include multinational oil and natural gas companies, major oil and natural gas companies, independent oil and natural gas companies, individual producers, financial buyers as well as participants in other industries that supply energy and fuel to consumers. Many of our competitors have greater and more diverse resources than we do. Additionally, competition for acquisitions may significantly increase the cost of available properties. We compete for the personnel and equipment required to explore, develop and operate properties. Our competitors also may have established long-term strategic positions and relationships in areas in which we may seek to enter. Consequently, our competitors may be able to address these competitive factors more effectively than we can. If we are not successful in our competition for oil and natural gas properties or in our marketing of production, then our financial condition and operation results may be adversely affected.
If our access to markets is restricted, it could negatively impact our production, our income and our ability to retain our leases.
Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business.
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Currently, some of our production is sold to marketers and other purchasers that have access to pipeline facilities. Much of our production is in areas with limited or no access to pipelines, thereby necessitating delivery by trucking. Further, much of our natural gas production is sold to companies who are the only gathering and processing facilities near most of our properties Such restrictions on our ability to sell our oil or natural gas could have several adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in increased exposure to facility breakdowns and a lower selling prices) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possibly causing us to lose a lease due to lack of production.
Many of our properties are in areas that may have been partially depleted or drained by offset wells and certain of our wells may be adversely affected by actions we or other operators may take when drilling, completing, or operating wells that we or they own.
Many of our properties are in reservoirs that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling and completing additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations by us or other operators could cause depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells by us or other operators could cause production from our wells to be shut-in for indefinite periods of time, could result in increased lease operating expenses and could adversely affect the production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators.
Multi-well pad drilling may result in volatility in our operating results.
We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production from a given pad, which may cause volatility in our operating results. In addition, problems affecting one pad could adversely affect production from all wells on such pad. As a result, multi-well pad drilling can cause delays in the scheduled commencement of production or interruptions in ongoing production.
Extreme weather conditions, which could become more frequent or severe due to multiple factors, could adversely affect our ability to conduct drilling, completion and production activities in the areas where we operate.
Our exploration and development activities and equipment can be adversely affected by extreme weather conditions, such as abnormally low temperatures, which can cause a loss of production from temporary cessation of activity from regional power outages or lost or damaged facilities and equipment. For example, we had production stoppages in 2022 and 2023 that adversely affected our revenues. Extreme weather conditions could also impact access to our drilling and production facilities for routine operations, maintenance and repairs and the availability of and our access to, necessary third-party services, such as gathering, processing, compression and transportation services. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operation and capital costs, which could have a material adverse effect on our business, financial condition, and results of operations.
Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.
Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect certain wildlife, such as those restrictions imposed under The Endangered Species Act. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration, development and production activities that could have an adverse impact on our ability to develop and produce our reserves.
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Our operations are substantially dependent on the availability, use and disposal of water. New legislation and regulatory initiatives or restrictions relating to water disposal wells could have a material adverse effect on our future business, financial condition, operating results and prospects.
Water is an essential component of our drilling and hydraulic fracturing processes. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil, natural gas and NGLs, which could have an adverse effect on our business, financial condition, and results of operations. Wastewaters from our operations typically are disposed of via underground injection. Some studies have linked earth tremors in certain areas to underground injection, which has led to greater public scrutiny of disposal wells. Any new environmental initiatives or regulations that restrict injection of fluids, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of oil and gas, or that limit the withdrawal, storage or use of surface water or ground water necessary for hydraulic fracturing of our wells, could increase our operating costs and cause delays, interruptions or cessation of our operations, the extent of which cannot be predicted, and all of which would have an adverse effect on our business, financial condition, results of operations, and cash flows.
Risks Relating to Legal, Regulatory, Privacy, and Tax Matters
We are subject to complex laws that can affect the cost, manner, or feasibility of doing business.
Exploration, development, production, and sale of oil and natural gas are subject to extensive federal, state, local, and international regulation. It is not possible to predict how or when regulations affecting our operations might change. There is ongoing controversy regarding the leasing of federal lands. We may be required to make large expenditures to comply with governmental regulations. Other matters subject to regulation include: discharge permits for drilling operations; drilling bonds; reports concerning operations; the spacing of wells; unitization and pooling of properties; and taxation.
Under these laws, we could be liable for personal injuries, property damage, and other damages. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil, and criminal penalties. Moreover, these laws could change in ways that substantially increase our costs. Any such liabilities, penalties, suspensions, terminations, or regulatory changes could materially adversely affect our financial condition and results of operations.
Our operations may incur substantial liabilities to comply with environmental laws and regulations.
Our oil and natural gas operations are subject to stringent federal, state, and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences; restrict the types, quantities, and concentration of substances that can be released into the environment in connection with drilling and production activities; limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, and other protected areas; and impose substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties; incurrence of investigatory or remedial obligations; or the imposition of injunctive relief. Changes in environmental laws and regulations and the interpretation thereof occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal, or cleanup requirements could require us to make significant expenditures to maintain compliance and may otherwise have a material adverse effect on our results of operations, competitive position, and financial condition as well as the industry in general. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or if our operations were standard in the industry at the time they were performed. The amount of additional future costs is not fully determinable due to such factors as the unknown magnitude of possible contamination, the unknown timing and extent of the corrective actions or compliance efforts that may be required, the determination of the Company’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties.
Our operations are subject to a series of risks arising out of the perceived threat of climate change that could result in increased operating costs, limit the areas in which we may conduct oil and natural gas exploration and production activities, and reduce demand for the oil and natural gas we produce.
In the United States, no comprehensive climate change legislation has been implemented at the federal level, though recently passed laws such as the IRA advance numerous climate-related objectives. However, President Biden has
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highlighted addressing climate change as a priority of his administration, which includes certain potential initiatives for climate change legislation to be proposed and passed into law. Moreover, federal regulators, state and local governments, and private parties have taken (or announced that they plan to take) actions that have or may have a significant influence on our operations. For example, in response to findings that emissions of carbon dioxide, methane, and other GHGs endanger public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish PSD construction and Title V operating permit reviews for certain large stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA for those emissions. These EPA rules could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations.
The federal regulation of methane from oil and gas facilities has been subject to substantial uncertainty in recent years. In June 2016, the EPA finalized NSPS, known as Subpart OOOOa, that establish emission standards for methane and VOCs from new and modified oil and natural gas production and natural gas processing and transmission facilities. 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. Subsequently, the U.S. Congress approved, and President Biden has signed into law, a resolution under the Congressional Review Act to repeal the September 2020 revisions to the methane standards, effectively reinstating the prior standards. In response to President Biden’s executive order calling on the EPA to revisit federal regulations regarding methane, the EPA finalized more stringent methane rules for new, modified, and reconstructed facilities, known as OOOOb, as well as standards for existing sources for the first time ever, known as OOOOc, in December 2023. Under the final rules, states have two years to prepare and submit their plans to impose methane emission controls on existing sources. The presumptive standards established under the final rule are generally the same for both new and existing sources. The requirements include enhanced leak detection survey requirements using optical gas imaging and other advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions, reduction of emissions by 95% through capture and control systems and zero-emission requirements for certain devices. The rule also establishes a “super emitter” response program that would allow third parties to make reports to EPA of large methane emission events, triggering certain investigation and repair requirements. Fines and penalties for violations of these rules can be substantial. It is likely, however, that the final rule and its requirements will be subject to legal challenges. Moreover, compliance with the new rules may affect the amount we owe under the IRA 2022’s methane fee described above because compliance with EPA’s methane rules would exempt an otherwise covered facility from the requirement to pay the methane fee. The requirements of the EPA’s final methane rules have the potential to increase our operating costs and thus may adversely affect our financial results and cash flows. Moreover, failure to comply with these CAA requirements can result in the imposition of substantial fines and penalties as well as costly injunctive relief. However, given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry remain a significant possibility.
Internationally, the United Nations-sponsored “Paris Agreement” requires member states to individually determine and submit non-binding emissions reduction targets every five years after 2020. President Biden has recommitted the United States to the Paris Agreement and, in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. In November 2021, the international community gathered again at COP26, during which multiple announcements were made, including a call for parties to eliminate certain oil and natural gas subsidies and pursue further action on non-CO2 GHGs. These goals were reaffirmed at COP27 in November 2022. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. At COP28 in December 2023, the parties signed onto an agreement to transition away from fossil fuels in energy systems and increase renewable energy capacity, though no timeline for doing so was set. While non-binding, the agreements coming out of COP28 could result in increased pressure among financial institutions and various stakeholders to reduce or otherwise impose more stringent limitations on funding for and increase potential opposition to the exploration and production of fossil fuels. The impacts of these orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, COP26, COP28 or other international conventions cannot be predicted at this time. Concern over the threat of climate change has also resulted in increasing political risks in the United States, including climate-change related pledges made by President Biden and other public office representatives. On January 27, 2021, President Biden signed an executive order calling for substantial action on climate change, including, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the oil and natural gas industry, and increased emphasis on climate-related risks across agencies and economic sectors. Additionally, in November 2021, the Biden Administration released “The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which establishes a roadmap to
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net zero emissions in the United States by 2050 through, among other things, improving energy efficiency; decarbonizing energy sources via electricity, hydrogen, and sustainable biofuels; and reducing non-CO2 GHG emissions, such as methane and nitrous oxide.
In addition, on March 6, 2024, the SEC adopted a rule requiring registrants to include certain climate-related disclosures, including Scope 1 and 2 GHG emissions, climate-related targets and goals, and certain climate-related financial statement metrics, in registration statements and annual reports. Currently, the ultimate impact of these laws on our business is uncertain. Separately, enhanced climate related disclosure requirements could lead to reputational or other harm with customers, regulators, investors or other stakeholders and could also increase our litigation risks relating to statements alleged to have been made by us or others in our industry regarding climate change risks, or in connection with any future disclosures we may make regarding reported emissions, particularly given the inherent uncertainties and estimations with respect to calculating and reporting GHG emissions. Additionally, the SEC has also from time to time applied additional scrutiny to existing climate-change related disclosures in public filings, increasing the potential for enforcement if the SEC were to allege an issuer’s existing climate disclosures misleading or deficient.
Increasingly, oil and natural gas companies are exposed to litigation risks associated with the threat of climate change. A number of parties have brought lawsuits against oil and natural gas companies in state or federal court for alleged contributions to, or failures to disclose the impacts of, climate change. We are not currently party to any such litigation, but could be named in future actions making similar claims of liability. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.
Additionally, in response to concerns related to climate change, companies in the oil and natural gas industry may be exposed to increasing financial risks. Financial institutions, including investment advisors and certain sovereign wealth, pension and endowment funds, may elect in the future to shift some or all of their investments into non-oil and natural gas related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices, and some of them may elect in the future not to provide funding for oil and natural gas companies. Many of the largest U.S. banks have made net zero commitments and have announced that they will be assessing financed emissions across their portfolios and taking steps quantify and reduce those emissions. In addition, at COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing and/or underwriting activities to net zero emissions by 2050. These and other developments in the financial sector could lead to some lenders restricting access to capital for or divesting from certain industries or companies, including the oil and natural gas sector, or requiring that borrowers take additional steps to reduce their GHG emissions. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the oil and natural gas industry. For example, the Federal Reserve has joined the Network for Greening the Financial System (“NGFS”), a consortium of financial regulators focused on addressing climate-related risks in the financial sector and, in November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. A material reduction in the capital available to the oil and natural gas industry could make it more difficult to secure funding for exploration, development, production, transportation and processing activities, which could result in decreased demand for our products or otherwise adversely impact our financial performance.
The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives related to climate change or GHG emissions from oil and natural gas facilities could result in increased costs of compliance or costs of consumption, thereby reducing demand for, oil and natural gas. Additionally, political, litigation, and financial risks may result in (i) restriction or cancellation of certain oil and natural gas production activities, (ii) incurrence of obligations for alleged damages resulting from climate change, or (iii) impairment of our ability to continue operating in an economic manner. One or more of these developments could have a material adverse effect on our business, financial condition, and results of operations.
Moreover, climate change may also result in various physical risks such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns, that could adversely impact our financial condition and operations, as well as those of our suppliers or customers. Such physical risks may result in damage to our facilities, or otherwise adversely impact our operations, such as if we become subject to water use curtailments in response to drought, or demand for our products, such as to the extent warmer winters reduce the demand for energy for heating purposes. Such physical risks may also impact the infrastructure on which we rely to produce or transport our products. One of more of these developments could have a material adverse effect on our business, financial condition and
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operations. In addition, while our consideration of changing weather conditions and inclusion of safety factors in design is intended to reduce the uncertainties that climate change and other events may potentially introduce, our ability to mitigate the adverse impacts of these events depends in part on the effectiveness of our facilities and our disaster preparedness and response and business continuity planning, which may not have considered or be prepared for every eventuality.
Changes in tax laws or the interpretation thereof or the imposition of new or increased taxes or fees may adversely
affect our operating results and cash flows.
From time to time, federal and state level legislation has been proposed that would, if enacted into law, make significant changes to tax laws, including to certain key federal and state income tax provisions currently applicable to oil and natural gas exploration and development companies. Such legislative changes have included, but have not been limited to, (i) the elimination of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) an extension of the amortization period for certain geological and geophysical expenditures, (iv) the elimination of certain other tax deductions and relief previously available to oil and natural gas companies, and (v) an increase in the federal income tax rate applicable to corporations such as us. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. Additionally, states in which we operate or own assets may impose new or increased taxes or fees on oil and natural gas extraction. The passage of any legislation as a result of these proposals and other changes in federal income tax laws or the imposition of new or increased taxes or fees on oil and natural gas extraction could adversely affect our operating results and cash flows.
In addition, the IRA, which includes, among other things, a corporate alternative minimum tax (the "CAMT"), provides for an investment tax credit for qualified biomass property and introduces a one percent excise tax on corporate stock repurchases. Under the CAMT, a 15 percent minimum tax will be imposed on certain adjusted financial statement income of "applicable corporations," which was effective beginning January 1, 2023. The CAMT generally treats a corporation as an applicable corporation in any taxable year in which the "average annual adjusted financial statement income" of the corporation and certain of its subsidiaries and affiliates for a three-taxable-year period ending prior to such taxable year exceeds $1 billion. Based on our current interpretation of the IRA and the CAMT and a number of operational, economic, accounting and regulatory assumptions, we do not anticipate the CAMT materially increasing our U.S. federal income tax liability in the near term. The foregoing analysis is based upon our current interpretation of the provisions contained in the IRA and the CAMT. In the future, the U.S. Department of Treasury and the Internal Revenue Service are expected to release regulations and interpretive guidance relating to the CAMT, and any significant variance from our current interpretation could result in a change in the expected application of the CAMT to us and adversely affect our operating results and cash flows.
Also, we are subject to unclaimed or abandoned property (escheat) laws which require us to turn over to certain government authorities the property of others held by us that has been unclaimed for a specified period. We are subject to audits by individual U.S. states regarding our escheatment practices. The legislation and regulations related to unclaimed property matters are complex and subject to varying interpretations by state governmental authorities.
New climate disclosure rules proposed by the SEC may increase our costs of compliance and adversely impact our
business.
On March 6, 2024, the SEC adopted new rules relating to the disclosure of a range of climate-related risks. We are currently assessing the final rule, but at this time we cannot predict the costs of implementation or any potential adverse impacts resulting from the rule. As a result of this rule, we could incur increased costs relating to the assessment and disclosure of climate-related risks, including increased legal, accounting and financial compliance costs, as well as making some activities more difficult, time-consuming and costly, and placing strain on our personnel, systems, and resources. We may also face increased litigation risks related to disclosures made pursuant to the rule. In addition, enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon-intensive sectors.
Risks Relating to Our Capital Structure
We have significant indebtedness.
We have a Credit Facility in place with $600 million in commitments from borrowings and letters of credit under our Second Amended and Restated Credit Agreement dated August 31, 2022 with Truist Bank as Administrative Agent (the "Second Credit Agreement"). As of December 31, 2023, $425.0 million was outstanding on our Credit Facility. If we
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further utilize this facility, the level of our indebtedness could affect our operations in several ways, including the following:
•a significant portion of our cash flow would need to be used to service the indebtedness;
•we are required to put into place derivative contracts to hedge a significant portion of our oil and gas production;
•a high level of debt would increase our vulnerability to general adverse economic and industry conditions;
•the covenants contained in our Credit Facility limit our ability to borrow additional funds, dispose of assets, pay dividends, and make certain investments, and;
•a high level of debt could impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate, or other purposes.
In addition, our bank borrowing base is subject to semi-annual redeterminations. We could be required to repay a portion of our bank borrowings due to redeterminations of our borrowing base. If we are required to do so, we may not have sufficient funds to make such repayments, and we may need to negotiate renewals of our borrowings or arrange new financing or sell significant assets. Any such actions could have a material adverse effect on our business and financial results. Further, our borrowings under our Credit Facility expose us to interest rate risks, as it bears variable interest based upon a prime rate and is therefore susceptible to interest rate fluctuations.
We may be unable to access the equity or debt capital markets to meet our obligations.
Our plans for growth may include accessing the capital markets. Recent reluctance to invest in the exploration and production sector based on market volatility, historically perceived underperformance, and ESG trends, among other things, has raised concerns regarding capital availability for the sector. If those markets are unavailable, or if we are unable to access alternative means of financing on acceptable terms, we may be unable to implement all of our development plans, make acquisitions, or otherwise carry out our business strategy, which would have a material adverse effect on our financial condition and results of operations, and impair our ability to service our indebtedness.
We continue to be impacted by inflationary pressures on our operating costs and capital expenditures.
Beginning in the second half of 2021 and continuing throughout 2023, we, similar to other companies in our industry, experienced inflationary pressures on our operating costs and capital expenditures - namely the costs of fuel, steel (i.e., wellbore tubulars), labor, and drilling and completion services. Such inflationary pressures on our operating and capital costs, which we currently expect to continue in 2024, have impacted our cash flows and results of operations. We have undertaken, and plan to continue with, certain initiatives and actions (such as agreements with service providers to secure the costs and availability of services) to mitigate such inflationary pressures. However, there can be no assurance that such efforts will offset, largely or at all, the impacts of any future inflationary pressures on our operating costs and capital expenditures and, in turn, our cash flows and results of operations.
Risks Relating to Technology and Cybersecurity
We rely on computer and telecommunications systems, and failures in our systems or cyber security attacks or breaches could result in information theft, data corruption, disruption in operations and/or financial loss.
The oil and natural gas industry has become increasingly dependent upon digital technologies to conduct day-to-day operations including certain exploration, development, and production activities. We depend on digital technology to process and record financial and operating data, estimate quantities of oil and natural gas reserves, analyze seismic and drilling information, process and store personally identifiable information on our employees and royalty owners, and communicate with our employees and other third parties. Our business partners, including vendors, service providers, purchasers of our production, and financial institutions, are also dependent on digital technology. It is possible that we could incur interruptions from cybersecurity attacks or breaches, computer viruses or malware that could result in disruption of our business operations and/or financial loss. Although we utilize various procedures and controls to monitor and protect against these threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing and causing us to suffer losses in the future. Even so, any cyber incidents or interruptions to our computing and communications infrastructure or our information systems could lead to data corruption, communication interruption, unauthorized release, gathering, monitoring, misuse, or
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destruction of proprietary or other information, or otherwise significantly disrupt our business operations. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.
Risks Relating to Our Common Stock
We have recently registered shares of our common stock for possible resale by certain of our stockholders, resulting in significant "market overhang" of our common stock.
In connection with the Stronghold Acquisition completed in 2022, Warburg Pincus & Company US, LLC and its affiliates hold approximately 46.1 million shares of our common stock. This represents approximately 23% of our presently outstanding shares of common stock and if the selling stockholders choose to sell all or a large number of their shares, from time to time, it likely would have a depressive effect on the market price of our common stock.
The market price of our common stock may be volatile, which could cause the value of your investment to decline.
The stock markets have experienced volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. The market price of our common stock may also fluctuate significantly in response to the following factors, some of which are beyond our control:
•our operating and financial performance and prospects;
•variations in our quarterly operating results and changes in our liquidity position;
•investor perceptions of us and the industry and markets in which we operate;
•future sales, or the availability for sale, of equity or equity-related securities;
•changes in securities analysts’ estimates of our financial performance;
•changes in market valuations of similar companies;
•changes in the price of oil and natural gas; and
•general financial, domestic, economic, and other market conditions.
We currently do not pay cash dividends on our common stock.
We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our business, financial condition, results of operations, capital requirements, and investment opportunities. In addition, the terms of our Second Credit Agreement have restrictions on dividend payments to our equity holders, including our common stockholders.
Our board of directors can, without stockholder approval, cause preferred stock to be issued on terms that could adversely affect common stockholders.
Under our Articles of Incorporation, our board of directors is authorized to issue up to 50,000,000 shares of preferred stock, of which none are issued and outstanding as of the date of this Annual Report. Also, our board of directors, without stockholder approval, may determine the price, rights, preferences, privileges, and restrictions, including voting rights, of those shares. If the board of directors causes shares of preferred stock to be issued, the rights of the holders of our common stock could be adversely affected. The board of director’s ability to determine the terms of preferred stock and to cause its issuance, while providing desirable flexibility in connection with possible acquisitions and other corporate purposes, could have the effect of making it more difficult for a third party to acquire a majority of our outstanding voting stock. Preferred shares issued by the board of directors could include voting rights, or even super voting rights, which could shift the ability to control the Company to the holders of the preferred stock. Preferred shares could also have conversion rights into shares of common stock at a discount to the market price of the common stock which could
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negatively affect the market for our common stock. In addition, preferred shares would typically have preference in the event of liquidation of the Company, which means that the holders of preferred shares would be entitled to receive the net assets of the Company distributed in liquidation before the common stockholders receive any distribution of the liquidated assets. We have no current plans to issue any shares of preferred stock.
Provisions under Nevada law could delay or prevent a change in control of our company, which could adversely affect the price of our common stock.
In addition to the ability of the board of directors to issue preferred stock, the existence of some provisions under Nevada law could delay or prevent a change in control of the Company, which could adversely affect the price of our common stock. Nevada law imposes some restrictions on mergers and other business combinations between us and any holder of 10% or more of our outstanding common stock.
Item 1B: Unresolved Staff Comments
None.
Item 1C: Cybersecurity
Cybersecurity Risk Management
We have developed and implemented a cybersecurity risk management program intended to protect the confidentiality, integrity, and availability of our critical systems and information. We design and assess our cybersecurity risk management program based on the National Institute of Standards and Technology Cybersecurity Framework (“NIST”). This does not imply that we meet any particular technical standards, specifications, or requirements, only that we use the NIST as a guide to help us identify, assess, and manage cybersecurity risks relevant to our business.
Our cybersecurity risk management program is integrated into our overall enterprise risk management program, and shares common methodologies, reporting channels and governance processes that apply across the enterprise risk management program to other legal, compliance, strategic, operational, and financial risk areas.
Our cybersecurity risk management program includes, but is not limited to, the following key elements:
•risk assessments designed to help identify material cybersecurity risks to our critical systems and information;
•a Manager of Information Technologies (“IT Manager”) responsible for managing our cybersecurity risk assessment processes, our security controls, and our response to cybersecurity incidents;
•the use of external service providers, where appropriate, to assess, test or otherwise assist with aspects of our security processes;
•systems for protecting information technology systems and monitoring for suspicious events, such as threat protection, firewall and anti-virus software; and
•cybersecurity awareness training of our employees, including incident response personnel, and senior management.
Governance
Our board of directors (the “Board”) considers oversight of our risks and risk management activities, including those related to cybersecurity threats, to be a responsibility of the entire Board. The Board also delegates certain risk oversight responsibilities to certain of its committees, and oversight of our cybersecurity risk is delegated by the Board to its Audit Committee. The Audit Committee receives regular reports, typically on a quarterly basis, from management and our internal auditors regarding information technology, cybersecurity risk, and efforts to prevent and mitigate such risks. The Chairperson of the Audit Committee subsequently reports on the Company’s cybersecurity risk, monitoring, and mitigation activities to the full Board, which equips the Board and its committees to fulfill their risk oversight role.
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The Board and Audit Committee are supported in their oversight capacity by our Management Cybersecurity Committee (the “MC Committee”) and our internal auditors. The MC Committee consists of our CEO, CFO, EVP of Engineering and Corporate Planning, and our IT Manager.
Our internal auditors perform audit engagements to assess our strategies, policies, procedures, and controls to reduce the risk of a cybersecurity incident.
Our IT Manager is responsible for assessing and managing risks from cybersecurity threats, our overall cybersecurity risk management program and supervises both our internal cybersecurity personnel and our retained external cybersecurity consultants. Our IT Manager is responsible for reporting material incidents to our MC Committee. Our IT Manager has a Bachelor of Science in Computer Science from Texas A&M University and a Master of Business Administration from Rice University. He has over fifteen years of information technology experience in the energy industry.
Our MC Committee stays informed about and monitors efforts to prevent, detect, mitigate, and remediate cybersecurity risks and incidents through various means, including, as appropriate, briefings from internal security personnel, threat intelligence and other information obtained from governmental, public or private sources, such as external consultants engaged by us, and alerts and reports produced by security tools deployed in the information technology environment.
Engagement of Third Parties
The MC Committee, internal auditors, our IT Manager and various other groups each occasionally engage third-party service providers to assist in their management of cybersecurity threats, including but not limited to cybersecurity vendors, assessors, consultants, auditors, and other third parties. Our IT Manager oversees third party vendors to identify cyber risks associated with our use of third-party service providers who may have access to sensitive Company data and systems.
Impact of Risks from Cybersecurity Threats
As of the date of this Annual Report, we are not aware of any cybersecurity threats, including as a result of any previous cybersecurity incidents, that have materially affected or are reasonably likely to materially affect us, including our operations, business strategy, results of operations or financial condition. However, we acknowledge that cybersecurity threats are continually evolving, and the possibility of future discovery of cybersecurity incidents remains. Please see “Part I, Item 1A. Risk Factors – Risks Related to Technology and Cybersecurity” for additional information about our cybersecurity risks. There can be no assurance that our cybersecurity risk management program, including our controls, procedures and processes, will be fully complied with or that our program will be fully effective in protecting the confidentiality, integrity and availability of our information systems. While we devote resources to our security measures to protect our systems and information, these measures cannot provide absolute security that they will not be subject to cybersecurity attacks and any damages to us from such attacks.
Item 2: Properties
General Background
Ring is engaged in oil and natural gas development, production, acquisition, and exploration activities currently focused in the Permian Basin of Texas.
Management’s Business Strategy Related to Properties
Our goal is to increase stockholder value by investing in oil and natural gas projects with attractive rates of return on capital employed. We plan to achieve this goal by developing our existing oil and natural gas properties and pursuing strategic acquisitions of additional properties.
Developing Existing Properties
We believe that there is significant value to be created by drilling the undeveloped opportunities on our properties. As of December 31, 2023, we owned interests in a total of 76,484 gross (65,462 net) developed acres and operate the vast
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majority of our acreage position. In addition, as of December 31, 2023, we owned interests in approximately 19,643 gross (15,073 net) undeveloped acres. While our near-term plans are focused on drilling wells on our existing acreage to develop the potential contained therein, our long-term plans also include continuing to evaluate acquisition and leasing opportunities that can earn attractive rates of return on capital employed. Within the Northwest Shelf, we have a total of 48 proved undeveloped locations (100% horizontal) and 4 PDNP opportunities based on the reserve report as of December 31, 2023. Our reserve estimates account for the capital costs required to develop these wells and the future plugging and abandonment cost. We believe the Northwest Shelf leases contain additional potential drilling locations. Within the Central Basin Platform, we had a total of 163 proved undeveloped locations (13% horizontal and 87% vertical) and 238 PDNP opportunities based on the reserve report as of December 31, 2023. Our reserve estimates account for the capital costs required to develop these wells. We believe the Central Basin Platform leases contain additional potential drilling locations.
Pursuing Profitable Acquisitions
We have historically pursued acquisitions of properties that we believe to have exploitation and development potential comparable to our existing inventory of drilling locations. We have an experienced team of management, engineering, geoscience, and land professionals who identify and evaluate acquisition opportunities, negotiate and close purchases and manage acquired properties.
Summary of Oil and Natural Gas Properties and Projects
Significant Operations
The Company's significant operations are in two core areas which it has actively drilled over the last several years located in the Northwest Shelf and the Central Basin Platform of the Permian Basin.
Northwest Shelf –Yoakum County, Texas and Lea County, New Mexico – In 2019, we acquired properties consisting of 49,754 gross (38,230 net) acres with an average working interest of 77% and an average net revenue interest of 58%. As of December 31, 2023, we owned interests in a total of 12,572 gross (8,751 net) developed acres and 16,258 gross (12,405 net) undeveloped acres with an average proved operated working interest of 89% and net revenue interest of 67%. As of December 31, 2023, the Company had interests in approximately five gross vertical and 146 gross horizontal producing wells, of which we operate five vertical and 111 horizontal wells. The horizontal wells predominately produce from the San Andres conventional reservoir and the verticals produce from Wolfcamp and Devonian reservoirs.
Central Basin Platform - Andrews, Gaines, Crane, Ector, Winkler, and Ward Counties, Texas – In 2011, we acquired a 100% working interest and a 75% net revenue interest in our initial leases in Andrews and Gaines counties. Since that time, we have acquired working and net revenue interests in additional producing leases and acquired additional undeveloped acreage in and around our Andrews County and Gaines County leases. In 2022, we acquired properties consisting of approximately 37,000 net acres, with an average working interest of 99% and an average net revenue interest of 88% for oil and 96% for natural gas in our initial leases in Crane, Winkler, and Ward counties. In 2023, we acquired properties in Ector County. As of December 31, 2023, we owned interests in a total of 63,912 gross (56,711 net) developed acres and 3,385 gross (2,668 net) undeveloped acres with an average proved operated working interest of 97% and net revenue interest of 82% in the area. As of December 31, 2023, the Company had interests in approximately 695 gross vertical and 197 gross horizontal producing wells, of which we operate 587 vertical and 195 horizontal wells. The horizontal wells predominately produce from the San Andres conventional reservoir and the verticals produce from a variety of conventional pay sands including Holt, Glorieta, Clear Fork, Wichita Albany, Tubb, Wolfcamp and Devonian reservoirs.
Title to Properties
We generally conduct a preliminary title examination prior to the acquisition of properties or leasehold interests. Prior to commencement of operations on such acreage, a thorough title examination is usually conducted and any significant defects are remedied before proceeding with operations. We believe the title to our leasehold properties is good, defensible and customary with practices in the oil and natural gas industry, subject to such exceptions that we believe do not materially detract from the use of such properties. With respect to our properties of which we are not the record owner, we rely on contracts with the owner or operator of the property or assignment of leases, pursuant to which, among other things, we generally have the right to have our interest placed on record.
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Our properties are generally subject to royalty, overriding royalty and other interests customary in the industry, liens incident to lending agreements, current taxes and other customary burdens, minor encumbrances, easements and restrictions. We do not believe any of these burdens materially interfere with our use of these properties.
Summary of Oil and Natural Gas Reserves
As of December 31, 2023, our estimated proved reserves had a pre-tax PV-10 value (present value discounted at 10%) of approximately $1,647.0 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $1,399.2 million, over 99.6% of which relates to our properties in the Permian Basin in Texas. We spent approximately $544.2 million on acquisitions and capital projects during 2023 and 2022. We expect to further develop these properties through additional drilling.
The following table summarizes our total net proved reserves, pre-tax PV-10 value and Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2023. Approximately 99.8% of our proved reserves are in the Permian Basin in Texas.
| Oil (Bbl) | Natural Gas (Mcf) | Natural Gas Liquids (Bbl) | Total (Boe) (1) | Pre-Tax PV-10 Value (2) | Standardized Measure of Discounted Future Net Cash Flows | |||||||||||||||||||||||||||
| 82,141,277 | 146,396,322 | 23,218,564 | 129,759,229 | $ | 1,647,031,127 | $ | 1,399,185,191 | |||||||||||||||||||||||||
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(1)Six Mcf is deemed the equivalent of one Boe.
(2)PV-10 is a non-GAAP financial measure. See below for a reconciliation.
We present the pre-tax PV-10 value, which is a non-GAAP financial measure, because it is a widely used industry standard which we believe is useful to those who may review this Report when comparing our asset base and performance to other comparable oil and natural gas exploration and production companies. PV-10 is a non-GAAP measure that differs from a measure under accounting principles generally accepted in the United States ("GAAP") known as “standardized measure of discounted future net cash flows” in that PV-10 is calculated without including future income taxes. PV-10 does not necessarily represent the fair market value of oil and natural gas properties. PV-10 is not a measure of financial or operational performance under GAAP, nor should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.
The table below provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows (in thousands):
| Present value of estimated future net revenues (PV-10) | $ | 1,647,031,127 | |||
| Future income taxes, discounted at 10% | $ | 247,845,936 | |||
| Standardized measure of discounted future net cash flows | $ | 1,399,185,191 | |||
Reserve Quantity Information
Our estimates of proved reserves and related valuations are based on reports independently determined and prepared by Cawley, Gillespie & Associates, Inc. ("CGA"), independent petroleum engineers. These reserves are
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attributable solely to properties within the United States. A summary of the changes in quantities of proved (developed and undeveloped) oil, natural gas and natural gas liquid reserves is shown below.
| Oil (Bbl) | Gas (Mcf)(2) | Natural Gas Liquids (Bbl)(2) | Boe(1) | ||||||||||||||||||||
| Balance, December 31, 2021 | 65,838,609 | 71,773,789 | — | 77,800,907 | |||||||||||||||||||
| Purchase of minerals in place | 28,086,920 | 108,456,107 | 16,715,626 | 62,878,564 | |||||||||||||||||||
| Extensions, discoveries and improved recovery | 628,978 | 522,178 | 52,810 | 768,818 | |||||||||||||||||||
| Sales of minerals in place | — | — | — | — | |||||||||||||||||||
| Production | (3,459,477) | (4,088,642) | (371,337) | (4,512,254) | |||||||||||||||||||
| Revisions of previous quantity estimates | (2,390,287) | (18,792,983) | 6,708,559 | 1,186,108 | |||||||||||||||||||
| Balance, December 31, 2022 | 88,704,743 | 157,870,449 | 23,105,658 | 138,122,143 | |||||||||||||||||||
| Purchase of minerals in place | 6,543,640 | 3,372,965 | 1,089,382 | 8,195,183 | |||||||||||||||||||
| Extensions, discoveries and improved recovery | 3,098,845 | 4,113,480 | 1,014,343 | 4,798,768 | |||||||||||||||||||
| Sales of minerals in place | (4,897,921) | (2,674,955) | (392,953) | (5,736,700) | |||||||||||||||||||
| Production | (4,579,942) | (6,339,158) | (976,852) | (6,613,320) | |||||||||||||||||||
| Revisions of previous quantity estimates | (6,728,088) | (9,946,459) | (621,014) | (9,006,845) | |||||||||||||||||||
| Balance, December 31, 2023 | 82,141,277 | 146,396,322 | 23,218,564 | 129,759,229 | |||||||||||||||||||
_____________________________
(1)Six Mcf is deemed the equivalent of one Boe.
(2)At year-end 2022, we began reporting reserves on a three-stream basis, including NGLs separately from natural gas.
Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history, five year rule and/or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.
Notable changes in proved reserves for the year ended December 31, 2023 included the following:
•Extensions. In 2023, extensions of 4.8 MMBoe were primarily the result of the successful operated drilling program and non-operated activity in the Northwest Shelf and Central Basin Platform.
•Purchase of minerals in place. In 2023, the Company completed the acquisition of Founders oil and gas leases and related property within Ector County that resulted in 8.2 MMBoe in additional reserves.
•Sales of minerals in place. In 2023, the Company sold 5.7 MMBoe from the divestiture of the Delaware Basin assets (30%), the New Mexico operated assets (57%), and part of the Company's assets in Gaines County (13%).
•Revision of previous estimates. In 2023, the negative revisions of prior reserves of 9.0 MMBoe consisted of 5.3 MMBoe (59%) related to changes in price and 3.7 MMBoe (41%) related to changes in performance and other economic factors.
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Our proved oil, natural gas and natural gas liquid reserves are shown below.
| For the years ended December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| Oil (Bbl) | |||||||||||
| Developed | 56,029,039 | 57,012,137 | |||||||||
| Undeveloped | 26,112,238 | 31,692,606 | |||||||||
| Total | 82,141,277 | 88,704,743 | |||||||||
| Natural Gas (Mcf) | |||||||||||
| Developed | 99,896,022 | 106,399,050 | |||||||||
| Undeveloped | 46,500,300 | 51,471,399 | |||||||||
| Total | 146,396,322 | 157,870,449 | |||||||||
| Natural Gas Liquids (Bbl) | |||||||||||
| Developed | 15,449,907 | 15,332,804 | |||||||||
| Undeveloped | 7,768,657 | 7,772,854 | |||||||||
| Total | 23,218,564 | 23,105,658 | |||||||||
Total (Boe) (1) | |||||||||||
| Developed | 88,128,284 | 90,078,116 | |||||||||
| Undeveloped | 41,630,945 | 48,044,027 | |||||||||
| Total | 129,759,229 | 138,122,143 | |||||||||
(1) Six Mcf is deemed the equivalent of one Boe.
Standardized Measure of Discounted Future Net Cash Flows
Our standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves and changes in the standardized measure as described below were prepared in accordance with GAAP.
Future income tax expenses are calculated by applying appropriate year-end tax rates to future pre-tax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value of our oil and natural gas properties.
Our estimates of reserves and future cash flow as of December 31, 2023 and 2022 were prepared using an average price equal to the unweighted arithmetic average of the first day of the month price for each month within the 12-month periods ended December 31, 2023 and 2022, respectively, in accordance with SEC guidelines. As of December 31, 2023, our reserves were based on an SEC average price of $74.70 per Bbl of WTI oil posted and $2.637 per MMBtu of Henry Hub natural gas. As of December 31, 2022, our reserves were based on an SEC average price of $90.15 per Bbl of WTI oil posted and $6.358 per MMBtu Henry Hub natural gas. Prices are adjusted by local field and lease level differentials and are held constant for life of reserves in accordance with SEC guidelines.
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The standardized measure of discounted future net cash flows relating to the proved oil, natural gas and NGLs reserves are shown below.
Standardized Measure of Discounted Future Net Cash Flows
| December 31, | 2023 | 2022 | 2021 | |||||||||||||||||
| Future cash inflows | $ | 6,622,410,752 | $ | 9,871,961,000 | $ | 4,853,709,000 | ||||||||||||||
| Future production costs | (2,413,303,488) | (2,751,896,250) | (1,395,437,250) | |||||||||||||||||
Future development costs (1) | (562,063,424) | (647,196,750) | (347,757,000) | |||||||||||||||||
| Future income taxes | (548,664,988) | (1,142,147,641) | (501,586,949) | |||||||||||||||||
| Future net cash flows | 3,098,378,852 | 5,330,720,359 | 2,608,927,801 | |||||||||||||||||
| 10% annual discount for estimated timing of cash flows | (1,699,193,661) | (3,058,606,841) | (1,471,562,953) | |||||||||||||||||
| Standardized Measure of Discounted Future Net Cash Flows | $ | 1,399,185,191 | $ | 2,272,113,518 | $ | 1,137,364,848 | ||||||||||||||
(1) Future development costs include not only development costs but also future asset retirement costs.
The changes in the standardized measure of discounted future net cash flows relating to the proved oil, natural gas and natural gas liquid reserves are shown below.
Changes in Standardized Measure of Discounted Future Net Cash Flows
| 2023 | 2022 | 2021 | |||||||||||||||
| Beginning of the year | $ | 2,272,113,518 | $ | 1,137,364,848 | $ | 555,871,253 | |||||||||||
| Purchase of minerals in place | 141,738,066 | 996,313,882 | 33,688,718 | ||||||||||||||
| Extensions, discoveries and improved recovery | 57,607,609 | 20,447,842 | 79,003,885 | ||||||||||||||
| Development costs incurred during the year | 70,697,664 | 67,454,522 | 17,513,180 | ||||||||||||||
| Sales of oil and gas produced, net of production costs | (266,004,598) | (283,588,498) | (154,615,685) | ||||||||||||||
| Sales of minerals in place | (59,600,128) | — | (2,523,746) | ||||||||||||||
| Accretion of discount | 277,365,650 | 133,209,763 | 63,810,764 | ||||||||||||||
| Net changes in price and production costs | (1,181,594,019) | 646,819,172 | 636,884,944 | ||||||||||||||
| Net change in estimated future development costs | 37,865,811 | (53,253,626) | (44,357,751) | ||||||||||||||
| Revisions of previous quantity estimates | (187,443,783) | 33,583,837 | (22,259,508) | ||||||||||||||
| Changes in estimated timing of cash flows | (17,257,348) | (119,428,019) | 86,845,188 | ||||||||||||||
| Net change in income taxes | 253,696,749 | (306,810,205) | (112,496,394) | ||||||||||||||
| End of the Year | $ | 1,399,185,191 | $ | 2,272,113,518 | $ | 1,137,364,848 | |||||||||||
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Our proved reserves by state as of December 31, 2023 are summarized in the table below.
| Oil (Bbl) | Gas (Mcf) | NGL (Bbl) | Total (Boe) | % of Total Proved | Pre-tax PV-10 (In thousands) | Standardized Measure of Discounted Future Net Cash Flows (In thousands) | Future Capital Expenditures (In thousands) | ||||||||||||||||||||||||||||||||||||||||
| Texas | |||||||||||||||||||||||||||||||||||||||||||||||
| PD | 55,820,275 | 99,572,221 | 15,413,055 | 87,828,701 | 68 | % | $ | 1,256,679 | $ | 1,067,574 | $ | 145,470 | |||||||||||||||||||||||||||||||||||
| PUD | 26,112,238 | 46,500,300 | 7,768,657 | 41,630,945 | 32 | % | 384,353 | 326,515 | 416,478 | ||||||||||||||||||||||||||||||||||||||
| Total Proved: | 81,932,513 | 146,072,521 | 23,181,712 | 129,459,646 | 100 | % | $ | 1,641,032 | $ | 1,394,089 | $ | 561,948 | |||||||||||||||||||||||||||||||||||
| New Mexico | |||||||||||||||||||||||||||||||||||||||||||||||
| PD | 208,764 | 323,801 | 36,852 | 299,583 | — | % | $ | 5,999 | $ | 5,097 | $ | 115 | |||||||||||||||||||||||||||||||||||
| PUD | — | — | — | — | — | % | — | — | — | ||||||||||||||||||||||||||||||||||||||
| Total Proved: | 208,764 | 323,801 | 36,852 | 299,583 | — | % | $ | 5,999 | $ | 5,097 | $ | 115 | |||||||||||||||||||||||||||||||||||
| Total | |||||||||||||||||||||||||||||||||||||||||||||||
| PD | 56,029,039 | 99,896,022 | 15,449,907 | 88,128,284 | 68 | % | $ | 1,262,679 | $ | 1,072,670 | $ | 145,586 | |||||||||||||||||||||||||||||||||||
| PUD | 26,112,238 | 46,500,300 | 7,768,657 | 41,630,945 | 32 | % | 384,353 | 326,515 | 416,478 | ||||||||||||||||||||||||||||||||||||||
| Total Proved: | 82,141,277 | 146,396,322 | 23,218,564 | 129,759,229 | 100 | % | $ | 1,647,031 | $ | 1,399,185 | $ | 562,063 | |||||||||||||||||||||||||||||||||||
Proved Reserves
As of December 31, 2023, we had approximately 129.8 MMBoe (one million Boe) of proved reserves, consisting of approximately 63% oil, 19% natural gas, and 18% NGLs, as summarized in the table above. Our reserve estimates have not been filed with any Federal authority or agency (other than the SEC).
As of December 31, 2023, approximately 68% of the proved reserves have been classified as PD and the remaining 32% are PUD.
As of December 31, 2023, our total proved reserves had a net pre-tax PV-10 value of approximately $1,647.0 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $1,399.2 million. Approximately $1,262.7 million and $1,072.7 million, respectively, of total proved reserves are associated with the PD reserves, which is approximately 77% of the total proved reserves’ pre-tax PV-10 value. The remaining $384.4 million and $326.5 million, respectively, are associated with PUD reserves.
Proved Undeveloped Reserves
Our reserve estimates as of December 31, 2023 include approximately 41.6 MMBoe as PUDs. As of December 31, 2022, our reserve estimates included approximately 48.0 MMBoe as proved undeveloped reserves. In accordance with our December 31, 2023 year-end independent engineering reserve report, we plan to drill our PUD drilling locations within five years of original classification. Below is a description of the changes in our PUD reserves from December 31, 2022 to December 31, 2023.
Notable changes in proved undeveloped reserves for the year ended December 31, 2023 included the following:
•Conversions to developed. During the year ended December 31, 2023, we incurred costs of approximately $90.3 million to convert 27 properties from PUD to PD through development. These 27 properties produced 573 MBoe during the year ended December 31, 2023, and have reserves of 7,068 MBoe as of December 31, 2023.
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•Extensions. In 2023, extensions of 3.7 MMBoe were primarily the result of the successful operated drilling program and non-operated activity in the Northwest Shelf and Central Basin Platform.
•Purchase of minerals in place. In 2023, we completed the acquisition of Founders oil and gas leases and related property within Ector county that resulted in 3.7 MMBoe in additional reserves.
•Sales of minerals in place. In 2023, we sold 1.3 MMBoe from the divestiture of the New Mexico operated assets (81%), and a subset of our assets in Gaines County (19%).
•Revision of previous estimates. In 2023, the negative revisions of prior reserves of 4.9 MMBoe consisted of 0.8 MMBoe (16%) related to changes in price and 4.1 MMBoe (84%) related to changes in performance and other economic factors.
The following table indicates projected reserves that we currently estimate will be converted from proved undeveloped to proved developed, as well as the estimated costs per year involved in such development. Our PUD reserves are part of a management adopted development plan that schedules PUD reserves to be developed within five years of initial disclosure as proved reserves. As of December 31, 2023, no material amount of proved undeveloped reserves were not scheduled to be converted to proved developed status within five years they were initially disclosed.
Estimated Costs Related to Conversion of Proved Undeveloped Reserves to Proved Developed Reserves
| Year | Estimated Oil Reserves Developed (Bbl) | Estimated Gas Reserves Developed (Mcf) | Estimated NGL Reserves Developed (Bbl) | Total Boe | Estimated Development Costs | |||||||||||||||||||||||||||
| 2024 | 10,512,071 | 8,637,030 | 1,538,117 | 13,489,693 | $ | 157,234,213 | ||||||||||||||||||||||||||
| 2025 | 8,815,136 | 7,676,596 | 1,838,167 | 11,932,736 | 126,315,450 | |||||||||||||||||||||||||||
| 2026 | 4,047,980 | 15,057,984 | 2,286,811 | 8,844,455 | 73,672,123 | |||||||||||||||||||||||||||
| 2027 | 2,737,051 | 15,128,690 | 2,105,562 | 7,364,061 | 51,012,096 | |||||||||||||||||||||||||||
Total | 26,112,238 | 46,500,300 | 7,768,657 | 41,630,945 | $ | 408,233,882 | ||||||||||||||||||||||||||
Preparation and Internal Controls Over Reserves Estimates
All the proved oil and natural gas reserves disclosed in this Report are based on reserve estimates determined and prepared by our independent reserve engineers, Cawley, Gillespie & Associates, Inc. (“CGA”), a leader of petroleum property analysis for industry and financial institutions. CGA was founded in 1960 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-693. Within CGA, the technical person primarily responsible for preparing the estimates set forth in the CGA letter dated January 26, 2024, filed as an exhibit to this Annual Report, was Mr. Zane Meekins. Mr. Meekins has been a practicing consulting petroleum engineer at CGA since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas (License No. 71055) and has over 36 years of practical experience in petroleum engineering, with over 34 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a Bachelor of Science degree in Petroleum Engineering. Mr. Meekins meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.
The proved oil and natural gas reserves disclosed in this Annual Report are based on reserve estimates determined and prepared by our independent reserve engineers primarily using decline curve analysis to determine the reserves of individual producing wells. To establish reasonable certainty with respect to our estimated proved reserves, the independent reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using volumetric estimates or performance from analogous wells in the surrounding area. These wells were considered to be analogous based on production performance from the same formation and completions using similar techniques. The technologies and economic data used to estimate our proved reserves include, but are not limited to, well logs, geological maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. This data was reviewed by various levels of management for accuracy before consultation with our
42
independent reserve engineers. This consultation included review of properties, assumptions and available data. Internal reserve estimates were compared to those prepared by CGA to test the estimates and conclusions before the reserves were included in this Annual Report. The accuracy of the reserve estimates is dependent on many factors, including the following:
•the quality and quantity of available data and the engineering and geological interpretation of that data;
•estimates regarding the amount and timing of future costs, which could vary considerably from actual costs;
•the accuracy of economic assumptions; and
•the judgment of the personnel preparing the estimates.
Our Executive Vice President of Engineering and Corporate Strategy, Mr. Alex Dyes, is the technical professional primarily responsible for overseeing the preparation of our reserves estimates. He has a Bachelor of Science degree in Petroleum Engineering from the University of Texas with over 17 years of practical industry experience, including over 13 years of estimating and evaluating reserve information. He has been a member of the Society of Petroleum Engineers since 2013 and his qualifications meet or exceed the Society of Petroleum Engineers’ standard requirements to be a professionally qualified Reserve Estimator and Auditor.
We encourage ongoing professional education for our engineers and reservoir analysts on new technologies and industry advancements as well as refresher training on basic skill sets. In order to ensure the reliability of reserves estimates, our Corporate Reserves department follows comprehensive SEC-compliant internal controls and policies to determine, estimate and report proved reserves including:
•confirming that we include reserves estimates for all properties owned and that they are based upon proper working and net revenue interests;
•ensuring the information provided by other departments within the Company, such as accounting, land, and operations is accurate;
•communicating, collaborating, and analyzing with technical personnel in our business units;
•comparing and reconciling the internally generated reserves estimates to those prepared by third parties; and
•utilizing experienced reservoir engineers or those under their direct supervision to prepare reserve estimates.
Each quarter, the Corporate Reserves team along with the Executive Vice President of Engineering and Corporate Strategy presents the status of the Company’s reserves to senior executives, and subsequently obtains approval of significant changes from key executives. Additionally, our five-year PUD development plan is reviewed and approved annually by the Company’s Chief Executive Officer, Chief Financial Officer, Executive Vice President of Operations, and the Executive Vice President of Land, Legal, Human Resources, and Marketing.
The Corporate Reserves department works closely with independent reserve engineers from CGA at each fiscal year end to ensure the integrity, accuracy and timeliness of annual independent reserves estimates. These independently developed reserves estimates are presented to the Audit Committee. In addition to reviewing the independently developed reserve reports, the Audit Committee also periodically meets with the independent reserve engineers that prepare estimates of proved reserves.
Summary of Oil and Natural Gas Properties and Projects
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Acreage
The following table summarizes our gross and net developed and undeveloped acreage as of December 31, 2023 by region (net acreage is our percentage ownership of gross acreage). Acreage in which our interest is limited to royalty and overriding royalty interests is excluded, as it is de minimis.
| Developed Acreage | Undeveloped Acreage | Total Acreage | |||||||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||||||||||||||
| Central Basin Platform | 63,912 | 56,711 | 3,385 | 2,668 | 67,297 | 59,379 | |||||||||||||||||||||||||||||
| Northwest Shelf | 12,572 | 8,751 | 16,258 | 12,405 | 28,830 | 21,156 | |||||||||||||||||||||||||||||
| Total | 76,484 | 65,462 | 19,643 | 15,073 | 96,127 | 80,535 | |||||||||||||||||||||||||||||
Leases of undeveloped acreage will generally expire at the end of their respective primary terms unless production from such leasehold acreage has been established prior to expiration of such primary terms. If production is established on the acreage, the lease will generally remain in effect until the cessation of production from the acreage and is referred to in the industry as HBP. Leases of undeveloped acreage may terminate or expire as a result of not meeting certain drilling commitments, if any, or otherwise by not complying with the terms of a lease depending on the specific terms that are negotiated between the lessor and the lessee.
The following table sets forth our gross and net undeveloped acreage, as of December 31, 2023, under lease that will expire over the next three years unless (i) production is established on the lease or within a spacing unit of which the lease is participating, or (ii) the lease is renewed or extended prior to the relevant expiration dates:
| Undeveloped Acreage | |||||||||||||||||||||||||||||||||||
| 2024 | 2025 | 2026 | |||||||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||||||||||||||
| Central Basin Platform | 1,800 | 1,046 | 1,240 | 100 | 720 | 239 | |||||||||||||||||||||||||||||
| Northwest Shelf | 8,475 | 1,481 | 8,946 | 3,496 | 3,015 | 454 | |||||||||||||||||||||||||||||
| Total | 10,275 | 2,527 | 10,186 | 3,596 | 3,735 | 693 | |||||||||||||||||||||||||||||
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Production History
The following table presents the historical information regarding our produced oil, natural gas and natural gas liquid volumes for the years ended December 31, 2023, 2022, and 2021:
| Years ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Oil (Bbls) | |||||||||||||||||
| Central Basin Platform | 2,347,068 | 1,409,211 | 867,835 | ||||||||||||||
Delaware Basin (2) | 25,743 | 81,936 | 104,129 | ||||||||||||||
| Northwest Shelf | 2,207,131 | 1,968,693 | 1,714,976 | ||||||||||||||
| Total | 4,579,942 | 3,459,840 | 2,686,940 | ||||||||||||||
Natural Gas (Mcf)(1) | |||||||||||||||||
| Central Basin Platform | 3,940,107 | 1,563,808 | 171,690 | ||||||||||||||
Delaware Basin (2) | 11,265 | 96,516 | 288,918 | ||||||||||||||
| Northwest Shelf | 2,387,786 | 2,428,318 | 2,074,580 | ||||||||||||||
| Total | 6,339,158 | 4,088,642 | 2,535,188 | ||||||||||||||
Natural Gas Liquids (Bbls)(1) | |||||||||||||||||
| Central Basin Platform | 703,818 | 227,996 | — | ||||||||||||||
Delaware Basin (2) | 2,867 | 3,718 | — | ||||||||||||||
| Northwest Shelf | 270,167 | 139,615 | — | ||||||||||||||
| Total | 976,852 | 371,329 | — | ||||||||||||||
| Total production (Boe) | |||||||||||||||||
| Central Basin Platform | 3,707,571 | 1,897,842 | 896,087 | ||||||||||||||
Delaware Basin (2) | 30,488 | 101,740 | 152,282 | ||||||||||||||
| Northwest Shelf | 2,875,262 | 2,513,028 | 2,060,739 | ||||||||||||||
| Total | 6,613,321 | 4,512,610 | 3,109,108 | ||||||||||||||
| Daily production (Boe/d) | |||||||||||||||||
| Central Basin Platform | 10,158 | 5,200 | 2,455 | ||||||||||||||
Delaware Basin (2) | 84 | 279 | 417 | ||||||||||||||
| Northwest Shelf | 7,877 | 6,885 | 5,646 | ||||||||||||||
| Total | 18,119 | 12,364 | 8,518 | ||||||||||||||
(1) Due to our acquisition of Stronghold's assets, which reported its volumes and revenues on a three-stream basis, beginning July 1, 2022, we began reporting volumes and revenues on a three-stream basis, separately reporting crude oil, natural gas, and NGL sales. For periods prior to July 1, 2022, sales and reserve volumes, prices, and revenues for NGLs were presented with natural gas.
(2) The Delaware Basin assets were sold with a closing date of May 11, 2023 and an effective date of March 1, 2023.
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Production Prices and Production Costs
The following tables provides historical pricing and costs statistics for the years ended December 31, 2023, 2022, and 2021.
| Years ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Average sales price: | |||||||||||||||||
Oil (per Bbl) | $ | 76.21 | $ | 92.80 | $ | 67.56 | |||||||||||
Natural gas (per Mcf) (1) | $ | 0.05 | $ | 4.57 | $ | 5.83 | |||||||||||
NGL (per Bbl) (1) | $ | 11.95 | $ | 20.18 | $ | — | |||||||||||
Total (per Boe) | $ | 54.60 | $ | 76.95 | $ | 63.14 | |||||||||||
(1) Due to our acquisition of Stronghold's assets, which reported its volumes and revenues on a three-stream basis, beginning July 1, 2022, we began reporting volumes and revenues on a three-stream basis, separately reporting crude oil, natural gas, and NGL sales. For periods prior to July 1, 2022, sales and reserve volumes, prices, and revenues for NGLs were presented with natural gas.
| Years ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
Average production costs (per Boe): | |||||||||||||||||
Lease operating expenses | $ | 10.61 | $ | 10.57 | $ | 9.75 | |||||||||||
Gathering, transportation and processing costs | $ | 0.07 | $ | 0.41 | $ | 1.39 | |||||||||||
Ad valorem taxes | $ | 1.02 | $ | 1.04 | $ | 0.73 | |||||||||||
Production taxes | $ | 2.74 | $ | 3.80 | $ | 2.93 | |||||||||||
The average oil sales price amounts above are calculated by dividing revenue from oil sales by the volume of oil sold, in Bbls. The average natural gas sales price amounts above are calculated by dividing revenue from natural gas sales by the volume of natural gas sold, in Mcf. The average NGL sales price amounts above are calculated by dividing revenue from NGL sales by the volume of NGLs sold, in Bbls. The total average sales price amounts are calculated by dividing total revenues by total volume sold, in Boe. The average production costs above are calculated by dividing production costs by total production in Boe.
Productive Wells
The following table presents our ownership as of December 31, 2023 in productive oil and natural gas wells (a net well is our percentage ownership of a gross well). Over 99.8% of such wells are in the Permian Basin in Texas.
| Oil Wells | Gas wells | Total Wells | ||||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||||
| 1,023 | 847 | 20 | 17 | 1,043 | 864 | |||||||||||||||||||||||||||
Drilling Activity
During 2023, as operator, we drilled a total of 31.00 gross (29.75 net) wells. Of this, 14.00 gross (12.75 net) horizontal San Andres wells were in the Northwest Shelf (nine 1.0-mile laterals and five 1.5-mile laterals.) and 17.00 gross (17.00 net) wells were in the Central Basin Platform, of which six were horizontal San Andres wells in Andrews County, Texas (two 1.0-mile laterals and four 1.5-mile laterals) and 11.00 were vertical wells in Crane County, Texas. In addition, we also participated in five gross (0.59 net) non-operated wells of which three were Northwest Shelf and two in Central Basin Platform. These wells were successful and there were no dry wells.
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The table below contains information regarding the number of operated wells drilled and/or participated in during the periods indicated.
| For the year ended December 31, | |||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||||||||||||||
| Exploratory | |||||||||||||||||||||||||||||||||||
| Productive | — | — | — | — | — | — | |||||||||||||||||||||||||||||
| Dry | — | — | — | — | — | — | |||||||||||||||||||||||||||||
| Development | |||||||||||||||||||||||||||||||||||
| Productive | 31.00 | 29.75 | 32.00 | 31.35 | 11.00 | 9.91 | |||||||||||||||||||||||||||||
| Dry | — | — | — | — | — | — | |||||||||||||||||||||||||||||
| Total | |||||||||||||||||||||||||||||||||||
| Productive | 31.00 | 29.75 | 32.00 | 31.35 | 11.00 | 9.91 | |||||||||||||||||||||||||||||
| Dry | — | — | — | — | — | — | |||||||||||||||||||||||||||||
The table below contains information regarding the number of non-operated wells drilled and participated in during the periods indicated.
| For the year ended December 31, | |||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||||||||||||||
| Exploratory | |||||||||||||||||||||||||||||||||||
| Productive | — | — | — | — | — | — | |||||||||||||||||||||||||||||
| Dry | — | — | — | — | — | — | |||||||||||||||||||||||||||||
| Development | |||||||||||||||||||||||||||||||||||
| Productive | 5.00 | 0.59 | 3.00 | 0.33 | 2.00 | 0.23 | |||||||||||||||||||||||||||||
| Dry | — | — | — | — | — | — | |||||||||||||||||||||||||||||
| Total | |||||||||||||||||||||||||||||||||||
| Productive | 5.00 | 0.59 | 3.00 | 0.33 | 2.00 | 0.23 | |||||||||||||||||||||||||||||
| Dry | — | — | — | — | — | — | |||||||||||||||||||||||||||||
Present Activities
We had no operated wells in the process of being drilled or completed as of December 31, 2023.
Cost Information
We conduct our oil and natural gas activities entirely in the United States. As noted in the table under “Production Prices and Production Costs”, our average production costs including lease operating expenses, gathering, processing and transportation ("GPT") and ad valorem, per Boe, were $11.70 and $12.02 for the years ended December 31, 2023 and 2022, respectively, and our average production taxes, per Boe, were $2.74 and $3.80 for the years ended December 31, 2023 and 2022, respectively. These amounts are calculated by dividing our total production costs or total production taxes by our total volume sold, in Boe.
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Costs incurred for property acquisition, exploration and development activities for the years ended December 31, 2023, 2022 and 2021 are shown below:
| 2023 | 2022 | 2021 | |||||||||||||||
Payments to acquire oil and natural gas properties | $ | 82,900,900 | $ | 179,387,490 | $ | 1,368,437 | |||||||||||
Payments to explore oil and natural gas properties | — | — | — | ||||||||||||||
| Payments to develop oil and natural gas properties | 152,559,314 | 129,332,155 | 51,302,131 | ||||||||||||||
Total costs incurred | $ | 235,460,214 | $ | 308,719,645 | $ | 52,670,568 | |||||||||||
Other Properties and Commitments
Effective January 1, 2021, the Company moved its corporate headquarters to The Woodlands, Texas. Prior to this, our principal offices were in Midland, Texas. Those offices now serve as an operations office. Our office space lease in Tulsa, Oklahoma was terminated as of March 31, 2021.
Item 3: Legal Proceedings
The Company is a defendant in a lawsuit in Harris County District Court, Houston, Texas, styled EPUS Permian Assets, LLC, v. Ring Energy, Inc., that was filed in July 2021. The plaintiff, EPUS Permian Assets, LLC, claims breach of contract, money had and received by fraudulent inducement, unjust enrichment and constructive trust. The plaintiff is requesting its forfeited deposit of $5,500,000 in connection with a proposed property sale by the Company plus related damages, and attorneys’ fees and costs. The action relates to a proposed property sale by the Company to the plaintiff, which was extended by the Company on several occasions with the plaintiff ultimately failing to perform on the agreement and the Company keeping the deposit. The Company believes that the claims by the plaintiff are entirely without merit and is conducting a vigorous defense and counterclaim. The Company has filed an answer and a counterclaim denying the allegations and asserting affirmative defenses that would bar or substantially limit the plaintiff’s claims, asserting breach of contract and requesting a declaratory judgment and attorneys’ fees and costs. The parties have begun taking depositions and are conducting discovery.
Item 4: Mine Safety Disclosures
Not applicable.
PART II
Item 5: Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market for our Common Stock
Our common stock is listed on the NYSE American under the trading symbol “REI.”
Performance Graph
The following graph reflects a comparison of the cumulative total stockholder return of our common stock relative to the cumulative total returns of the S&P 500 Index and the S&P Oil and Gas Exploration and Production Select Industry Index ("SPSIOP"). The graph assumes the investment of $100 on December 31, 2018 in our common stock and each index and the reinvestment of all dividends, if any. This table is not intended to forecast future performance of our common stock.
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The performance graph above is furnished and not filed for purposes of Section 18 of the Exchange Act and will not be incorporated by reference into any registration statement filed under the Securities Act unless specifically identified therein as being incorporated by reference. The performance graph is not solicitation material subject to Regulation 14A of the Exchange Act.
Record Holders
As of March 7, 2024, there were approximately 84 holders of record of our common stock. This is the number of record holders in the records of our transfer agent. It does not include holders of shares via brokerage accounts.
Dividend Policy
We do not currently anticipate paying any cash dividends on our common stock. We currently intend to retain future earnings, if any, to pay down debt and finance the expansion of our business. Our future dividend policy is within the discretion of our Board of Directors and will depend upon various factors, including our business, financial condition, results of operations, capital requirements and investment opportunities. In addition, our credit facility contains provisions limiting our ability to pay dividends unless certain conditions are met.
Recent Sales of Unregistered Securities and Use of Proceeds from Registered Securities
The information required by this item was disclosed and reported under Item 3.02, Unregistered Sales of Equity Securities, of our Form 8-K dated August 30, 2022, filed with the SEC on September 6, 2022, which disclosure is incorporated herein by reference.
Issuer Repurchases
We did not make any repurchases of our equity securities during the year ended December 31, 2023.
Item 6: Reserved
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Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our accompanying financial statements and the notes to those financial statements included elsewhere in this Annual Report. The following discussion includes forward-looking statements that reflect our plans, estimates, and beliefs and our actual results could differ materially from those discussed in these forward-looking statements as a result of many factors, including those discussed under “Risk Factors,” "Forward Looking Statements," and elsewhere in this Annual Report.
Overview
Ring Energy, Inc. (the "Company," "Ring," "we," "us," "our" and similar terms) is a growth oriented independent oil and natural gas exploration and production company based in The Woodlands, Texas and is engaged in oil and natural gas development, production, acquisition, and exploration activities currently focused in the Permian Basin of Texas. Our drilling operations target the oil and liquids rich producing formations in the Northwest Shelf and the Central Basin Platform, in the Permian Basin in Texas.
Business Description and Plan of Operation
The Company is focused on balancing the need to reduce long-term debt and further developing our oil and gas properties to maintain or grow our annual production. We intend to achieve both through proper allocation of cash flow generated by our operations and potentially through the sale of non-core assets. We intend to continue evaluating potential transactions to acquire strategic producing assets with attractive acreage positions that can provide competitive returns for our shareholders.
•Growing production and reserves by developing our oil-rich resource base through conventional and horizontal drilling. In an effort to maximize its value and resources potential, Ring intends to drill and develop its acreage base in both the Northwest Shelf and Central Basin Platform assets, allowing Ring to execute on its plan of operating within its generated cash flow.
•Reduction of long-term debt and deleveraging of asset. Ring intends to reduce its long-term debt primarily through the use of excess cash flow and potentially through the sale of non-core assets. The Company believes that with its attractive field level margins, it is positioned to maximize the value of its assets and deleverage its balance sheet. The Company also believes through potential accretive acquisitions and strategic asset dispositions, it can accelerate the strengthening of its balance sheet. During the three months ended December 31, 2023, the Company made net paydowns of $3 million on its revolving line of credit, resulting in the outstanding long-term debt balance of $425 million.
•Employ industry leading drilling and completion techniques. Ring’s executive team intends to utilize new and innovative technological advancements for completion optimization, comprehensive geological evaluation, and reservoir engineering analysis to generate value and to build future development opportunities. These technological advancements have led to a low-cost structure that helps maximize the returns generated by our drilling programs.
•Pursue strategic acquisitions with attractive upside potential. Ring has a history of acquiring leasehold positions that it believes to have additional resource potential that meet its targeted returns on invested capital and comparable to its existing inventory of drilling locations. We pursue an acquisition strategy designed to increase reserves at attractive finding costs and complement existing core properties. Management intends to continue to pursue strategic acquisitions and structure the potential transactions financially, so they improve our balance sheet metrics and are accretive to shareholders. Our executive team, with its extensive experience in the Permian Basin, has many relationships with operators and service providers in the region.
2023 Developments and Highlights
Drilling, Completion, and Recompletion
In the first quarter of 2023, in the Northwest Shelf, the Company drilled and completed two 1-mile horizontal wells (each with a working interest of 100%), and two 1.5-mile horizontal wells (one with a working interest of approximately 99.8% and the other with a working interest of approximately 75.4%). Next, in its Crane County acreage
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within the Central Basin Platform, the Company drilled and completed three vertical wells (each with a working interest of 100%) and performed six vertical well recompletions (each with a working interest of 100%).
In the second quarter of 2023, in the Northwest Shelf, the Company drilled and completed two 1.5-mile horizontal wells (one with a working interest of 100% and the other with a working interest of approximately 75.4%) and two 1-mile horizontal wells (both with a working interest of approximately 91.1%). Additionally, in its Crane County acreage within the Central Basin Platform, the Company drilled and completed two vertical wells (each with a working interest of 100%) and performed three vertical well recompletions (each with a working interest of 100%).
During the third quarter of 2023, the Company drilled and completed two 1-mile horizontal wells (one with a working interest of 100% and the other with a working interest of 75%) in the Northwest Shelf, and three 1.5-mile horizontal wells (each with a working interest of 100%) in the Central Basin Platform. Additionally, in its Crane County acreage within the Central Basin Platform, the Company drilled and completed three vertical wells (each with a working interest of 100%). Lastly, the Company drilled and began the completion process on three 1-mile horizontal wells in the Northwest Shelf (each with a working interest of 100%).
In the fourth quarter of 2023, the Company completed and placed on production the three aforementioned 1-mile horizontal wells in the Northwest Shelf. Additionally, the Company drilled and completed one saltwater disposal (SWD) well in the Northwest Shelf (with a working interest of 100%), and completed the 2023 horizontal drilling program with one 1.5-mile horizontal well in the Northwest Shelf (with a working interest of approximately 97.7%), as well as two 1-mile horizontal wells and one 1.5-mile horizontal well (each with a working interest of 100%) in the Central Basin Platform. In its Crane County acreage within the Central Basin Platform, the Company drilled and completed three vertical wells (each with a working interest of 100%).
In summary, for 2023, the Company drilled and completed 20 horizontal wells, 11 vertical wells, and 1 SWD well. In addition, the Company performed 9 vertical well recompletions. The table below sets forth our drilling and completion activities for 2023 by quarter, and full year total through December 31, 2023.
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| Quarter | Area | Wells Drilled | Wells Completed | Recompletions | ||||||||||||||||||||||
| 1Q 2023 | Northwest Shelf (Horizontal) | 4 | 4 | — | ||||||||||||||||||||||
| Central Basin Platform (Horizontal) | — | — | — | |||||||||||||||||||||||
| Central Basin Platform (Vertical) | 3 | 3 | 6 | |||||||||||||||||||||||
Total | 7 | 7 | 6 | |||||||||||||||||||||||
| 2Q 2023 | Northwest Shelf (Horizontal) | 4 | 4 | — | ||||||||||||||||||||||
| Central Basin Platform (Horizontal) | — | — | — | |||||||||||||||||||||||
| Central Basin Platform (Vertical) | 2 | 2 | 3 | |||||||||||||||||||||||
| Total | 6 | 6 | 3 | |||||||||||||||||||||||
| 3Q 2023 | Northwest Shelf (Horizontal) | 5 | 2 | — | ||||||||||||||||||||||
| Central Basin Platform (Horizontal) | 3 | 3 | — | |||||||||||||||||||||||
| Central Basin Platform (Vertical) | 3 | 3 | — | |||||||||||||||||||||||
| Total | 11 | 8 | — | |||||||||||||||||||||||
| 4Q 2023 | Northwest Shelf (Horizontal) | 1 | 4 | — | ||||||||||||||||||||||
| Central Basin Platform (Horizontal) | 3 | 3 | — | |||||||||||||||||||||||
| Central Basin Platform (Vertical) | 3 | 3 | — | |||||||||||||||||||||||
Total (1) | 7 | 10 | — | |||||||||||||||||||||||
FY 2023 | Northwest Shelf (Horizontal) | 14 | 14 | — | ||||||||||||||||||||||
| Central Basin Platform (Horizontal) | 6 | 6 | — | |||||||||||||||||||||||
| Central Basin Platform (Vertical) | 11 | 11 | 9 | |||||||||||||||||||||||
Total (1) | 31 | 31 | 9 | |||||||||||||||||||||||
(1) Fourth quarter total and full year total do not include one SWD well completed in the Northwest Shelf.
Market Conditions and Commodity Prices
Our financial results depend on many factors, particularly the price of crude oil and natural gas and our ability to market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand both domestically and world wide, which are impacted by many factors. As a result, we cannot accurately predict future commodity prices, and therefore, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our drilling program, production volumes, or revenues.
Average oil and natural gas prices received through 2022 and 2023 continued to demonstrate commodity price volatility and we believe oil and natural gas prices will continue to be volatile for the foreseeable future. The ability to find and develop sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success.
Natural Gas Takeaway Capacity
The Permian Basin has been experiencing a lack of sufficient pipeline transportation that is connected to markets that are purchasing the natural gas produced. This has resulted in negative natural gas prices at times, whereby the seller is actually paying the purchaser to take the gas. If these depressed or inverted natural gas prices continue in the region, our natural gas revenues will continue to be negatively impacted.
Inflation
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Inflation has increased costs associated with our capital program and production operations. We have experienced increases in the costs of many of the materials, supplies, equipment and services used in our operations and we expect inflation to continue based on current economic circumstances. In addition, the attempts to reduce inflation by the U.S. Federal Reserve have resulted in increased interest rates on debt, contributed to debt and equity market volatility and increased substantially our interest expense. We continue to closely monitor costs and take all reasonable steps to mitigate the inflationary effect on our cost structure and also work to enhance our efficiency to minimize additional cost increases where possible.
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Results of Operations
The following table sets forth selected operating data for the periods indicated:
| For the years ended December 31, | 2023 | 2022 | 2021 | ||||||||||||||
| Net production: | |||||||||||||||||
| Oil (Bbls) | 4,579,942 | 3,459,840 | 2,686,940 | ||||||||||||||
| Natural gas (Mcf) | 6,339,158 | 4,088,642 | 2,535,188 | ||||||||||||||
| Natural gas liquids (Bbls) | 976,852 | 371,329 | — | ||||||||||||||
| Net sales: | |||||||||||||||||
| Oil | $ | 349,044,863 | $ | 321,062,672 | $ | 181,533,093 | |||||||||||
| Natural gas | 334,175 | 18,693,631 | 14,772,873 | ||||||||||||||
| Natural gas liquids | 11,676,963 | 7,493,234 | — | ||||||||||||||
| Average sales price: | |||||||||||||||||
| Oil (per Bbl) | $ | 76.21 | $ | 92.80 | $ | 67.56 | |||||||||||
| Natural gas (per Mcf) | 0.05 | 4.57 | 5.83 | ||||||||||||||
| Natural gas liquids (Bbl) | 11.95 | 20.18 | — | ||||||||||||||
| Production costs and expenses: | |||||||||||||||||
| Lease operating expenses | $ | 70,158,227 | $ | 47,695,351 | $ | 30,312,399 | |||||||||||
| Gathering, transportation and processing costs | 457,573 | 1,830,024 | 4,333,232 | ||||||||||||||
| Ad valorem taxes | 6,757,841 | 4,670,617 | 2,276,463 | ||||||||||||||
| Oil and natural gas production taxes | 18,135,336 | 17,125,982 | 9,123,420 | ||||||||||||||
| Other costs and operating expenses: | |||||||||||||||||
| Depreciation, depletion and amortization | $ | 88,610,291 | $ | 55,740,767 | $ | 37,167,967 | |||||||||||
| Asset retirement obligation accretion | 1,425,686 | 983,432 | 744,045 | ||||||||||||||
| Operating lease expense | 541,801 | 363,908 | 523,487 | ||||||||||||||
General and administrative expense ("G&A") | 29,188,755 | 27,095,323 | 16,068,105 | ||||||||||||||
| Share-based compensation | 8,833,425 | 7,162,231 | 2,418,323 | ||||||||||||||
G&A excluding share-based compensation | 20,355,330 | 19,933,092 | 13,649,782 | ||||||||||||||
| Other income (expense): | |||||||||||||||||
| Interest income | 257,155 | 4 | 1 | ||||||||||||||
| Interest (expense) | $ | (43,926,732) | $ | (23,167,729) | $ | (14,490,474) | |||||||||||
| Gain (loss) on derivative contracts | 2,767,162 | (21,532,659) | (77,853,141) | ||||||||||||||
Loss on disposal of assets | (87,128) | — | — | ||||||||||||||
| Other income | 198,935 | — | — | ||||||||||||||
Provision for Income Taxes | $ | (125,242) | $ | (8,408,724) | $ | (90,342) | |||||||||||
Year Ended December 31, 2023 Compared to Year Ended December 31, 2022
Oil sales. Oil sales increased approximately $28.0 million to $349.0 million in 2023 from $321.1 million in 2022. The oil sales increased by a volume variance of approximately $103.9 million from a significant increase in sales volumes to 4,579,942 barrels of oil in 2023from 3,459,840 barrels of oil in 2022, with approximately 19% of the increase in oil
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volumes related to the Founders Acquisition. Other impacts to revenue volumes include organic growth from workovers, new drills, and other capital expenditures, offset by divestitures completed. The volume variance was offset by a negative price variance of approximately $76.0 million from a decrease in the average realized per barrel oil price to $76.21 in 2023 from $92.80 in 2022.
Natural gas sales. Natural gas sales decreased approximately $18.4 million to $0.3 million in 2023 from $18.7 million in 2022. The natural gas sales decreased by a negative price variance of approximately $28.6 million, as the average realized per Mcf gas price decreased to $0.05 in 2023 from $4.57 in 2022. The significant reduction in realized natural gas prices was driven by a lower market index price. In 2023, the average gross realized price for natural gas was $1.67 per Mcf, and the average fees per Mcf were $(1.62), bringing the net average price to $0.05 per Mcf. In 2022, the average gross realized price for natural gas was $6.32 per Mcf, and the average fees per Mcf were $(1.75), bringing the net average price to $4.57 per Mcf. This was partially offset by a volume variance of approximately $10.3 million as the volume increased to 6,339,158 Mcf in 2023 from 4,088,642 Mcf in 2022.
NGL sales. NGL sales increased approximately $4.2 million to $11.7 million in 2023 from $7.5 million in 2022. NGL sales had a volume variance of approximately $12.2 million, as volumes were 976,852 barrels of NGLs in 2023 compared to 371,329 barrels in 2022. The volumes increase was primarily due to the Company's change in reporting presentation for its natural gas productions, which were presented on a three-stream basis basis beginning July 1, 2022. Offsetting this increase to sales was a negative price variance of approximately $8.0 million, as the average realized price per barrel of NGLs was $11.95 in 2023 compared to $20.18 in 2022.
Lease operating expenses. Our total lease operating expenses (“LOE”) increased approximately $22.5 million to $70.2 million in 2023 from $47.7 million in 2022 and increased slightly on a Boe basis to $10.61 in 2023 from $10.57 in 2022. These per Boe amounts are calculated by dividing our total LOE by our total volume sold, in Boe. LOE increased primarily due to a 47% increase in production of 2,100,711 Boe year-over-year. Specifically, the following cost increases accounted for the majority of the increase in LOE: $7.5 million in LOE workover costs, $4.2 million in salaries and wages, $2.5 million in electrical/utilities costs, $1.6 million in equipment rental/services $1.3 million in supplies/materials, $1.2 million in contract services, and $1.0 million in chemicals/treating costs.
Gathering, transportation and processing costs. Our total gathering, transportation and processing costs (“GTP”) decreased by $1,372,451 to $457,573 in 2023 from $1,830,024 in 2022 and decreased slightly on a Boe basis to $0.07 in 2023 from $0.41 in 2022. In May 2022, a contract update with one of our largest natural gas processors altered the point of control of gas resulting in a change to the recording of those fees from expense to a netted reduction to revenues. There remains only one contract with a natural gas processing entity in place where point of control of gas dictates requiring the fees be recorded as an expense.
Ad valorem taxes. Our total ad valorem taxes increased approximately $2.1 million to $6.8 million in 2023 from $4.7 million in 2022 and decreased on a Boe basis to $1.02 in 2023 from $1.04 in 2022 . Ad valorem taxes increased due to a full year of taxes for the properties within counties acquired in the Stronghold Acquisition (i.e. Crane County) as well as a partial year of taxes for properties within Ector County, acquired in the Founders Acquisition. Additional increases were primarily in Yoakum County and Andrews County.
Oil and natural gas production taxes. Oil and natural gas production taxes as a percentage of oil and natural gas sales increased to 5.02% in 2023 from 4.93% during 2022. Overall, the percentage was consistent year over year.
Depreciation, depletion and amortization. Our depreciation, depletion and amortization expense increased approximately $32.9 million to $88.6 million in 2023 from $55.7 million in 2022 due to an increase in our total estimated costs of property, resulting in a higher depletion expense per unit, as well as an increase of 2,100,711 in Boe produced. Our average depreciation, depletion and amortization per Boe increased to $13.40 per Boe during 2023 from $12.35 per Boe during 2022.
Asset retirement obligation accretion. Our asset retirement obligation (“ARO”) accretion increased by $442,254 to $1,425,686 in 2023 from $983,432 in 2022. This was due to a full year of accretion on the assets acquired in the Stronghold Acquisition, a partial year of accretion on the assets acquired in the Founders Acquisition, and new wells drilled during 2023, offset by wells sold during 2023.
Operating lease expense. Our operating lease expense increased by $177,893 to $541,801 in 2023 from $363,908 in 2022 due to a full year of the Midland office lease additional space, which was amended effective October 1, 2022, as
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well as a quarter's impact of The Woodlands office lease additional space, which was substantially completed on September 27, 2023.
General and administrative expenses (including share-based compensation). General and administrative expenses increased approximately $2.1 million to $29.2 million in 2023 from $27.1 million in 2022. The increase was primarily related to a $2.2 million increase in salaries, wages, and bonuses, a $1.7 million increase in share-based compensation, $0.6 million in additional legal fees, $0.5 million in higher software costs, $0.1 million in engineering costs, and $0.1 million in accounting, tax, and audit fees. These cost increases were partially offset by a reduction of $2.0 million in transaction costs and a $0.6 million reduction in G&A costs from the Employee Retention Tax Credit.
Interest income. Interest income increased by $257,151 to $257,155 in 2023 from $4 in 2022. The 2023 interest income consisted of $226,315 from depositing excess cash balances in bank sweep accounts beginning in May 2023, $29,042 from interest earned on the Employee Retention Tax Credit, and $1,798 from interest earned on the escrow deposit made for the Founders Acquisition.
Interest expense. Interest expense increased approximately $20.8 million to $43.9 million in 2023 from $23.2 million in 2022. The increase was the result of a combination of higher interest rates, with a weighted average interest rate of 8.8% in 2023 and 5.8% in 2022, and having higher amounts outstanding on our credit facility throughout 2023, with a weighted average daily debt of approximately $422.5 million in 2023 compared to approximately $344.0 million in 2022.
Gain (loss) on derivative contracts. During 2023, the Company incurred a gain on derivative contracts of approximately $2.8 million. During 2022, the Company recorded a loss on derivative contracts of approximately $21.5 million. For the derivative contract settlements, the Company recorded a realized loss of $9.1 million during 2023 and a realized loss of $62.5 million during 2022. The decrease of $53.4 million in the realized loss was $50.5 million from realized oil derivative settlements and $2.9 million from realized natural gas derivative settlements. For the marked-to-market contracts, the Company recorded an unrealized gain of $11.9 million during 2023 and an unrealized gain of $41.0 million during 2022. This change of $29.1 million in unrealized derivatives was from $31.1 million in favorable derivative portfolio changes and futures pricing for marked-to-market oil derivative contracts, offset by $1.9 million unfavorable changes to the marked-to-market natural gas derivative contract balance.
Loss on disposal of assets. During 2023, the Company recognized a loss on disposal of assets of $87,128 from selling multiple company owned vehicles.
Other income. During 2023, the Company's other income of $198,935 primarily resulted from the termination of The Woodlands office operating lease as of May 31, 2023, along with a bank rebate related to the use of a vendor payment program.
Provision for income taxes. The provision for income taxes changed to a provision of $125,242 for 2023 from a provision of $8,408,724 for 2022. The current year change in the Company's federal tax provision was the result of a full valuation allowance release on federal taxes in 2023 with state tax activity recognized.
Net income. The Company achieved net income of $104,864,641 in 2023 compared to net income of $138,635,025 in 2022 compared. The decrease in net income was due to increased LOE costs, depletion, depreciation, and amortization costs, and interest expense and lower natural gas revenues. This was offset by increased oil and NGL revenues in addition to a more favorable derivative contract portfolio in comparison with the year-end commodity futures prices.
Year Ended December 31, 2022 Compared to Year Ended December 31, 2021
Oil sales. Oil sales increased approximately $139.5 million from $181.5 million in 2021 to $321.1 million in 2022 due to an increase in the average realized per barrel oil price from $67.56 in 2021 to $92.80 in 2022 and an increase in sales volume from 2,686,940 barrels of oil in 2021 to 3,459,840 barrels of oil in 2022. The increased average realized per barrel oil price was a result of the significantly higher oil price during the first eight months of 2022. The increased sales volumes were a direct result of assets acquired in the Stronghold Acquisition, which resulted in higher volumes for the last four months of 2022, as well as organic growth from capital expenditures that were $78.0 million greater in 2022 than in 2021.
Natural gas sales. Natural gas sales increased approximately $3.9 million from $14.8 million in 2021 to $18.7 million in 2022. The natural gas sales volume increased from 2,535,188 Mcf in 2021 to 4,088,642 Mcf in 2022 and the average realized per Mcf gas price decreased from $5.83 in 2021 to $4.57 in 2022. The sales volume increase was due to
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the aforementioned increase in capital expenditures as well as the Stronghold Acquisition, which closed August 31, 2022. The price decrease was driven by the Company's change in reporting presentation from two-stream (oil and natural gas) to three-stream (oil, natural gas and NGLs) beginning July 1, 2022.
NGL sales. NGL sales increased approximately $7.5 million from $0.0 million in 2021 to $7.5 million in 2022. NGL sales volumes in were 371,329 barrels compared to zero barrels in 2021, due to the Company’s change in reporting presentation for its natural gas products, which were presented on a three-stream basis beginning July 1, 2022. The average realized price per barrel of NGLs was $20.18 in 2022.
Lease operating expenses. Our total LOE increased from $30,312,399 in 2021 to $47,695,351 in 2022 and increased on a Boe basis from $9.75 in 2021 to $10.57 in 2022. These per Boe amounts are calculated by dividing our total LOE by our total volume sold, in Boe. LOE increased primarily due to a 45% increase in production of 1,403,502 Boe year-over-year, as well as increased costs for goods and services due to increased Permian activity.
Gathering, transportation and processing costs. Our total GTP decreased from $4,333,232 in 2021 to $1,830,024 in 2022 and decreased on a Boe basis from $1.39 in 2021 to $0.41 in 2022. GTP costs decreased due to costs classified as a reduction to oil and natural gas sales revenues, due to a natural gas processing entity beginning to take control of transportation at the wellhead beginning May 1, 2022.
Ad valorem taxes. Our total ad valorem taxes increased from $2,276,463 in 2021 to $4,670,617 in 2022 and increased on a Boe basis from $0.73 in 2021 to $1.04 in 2022. Ad valorem taxes increased primarily due to the increase in taxed commodity prices from the prior year, as well as $783,159 for the properties acquired in the Stronghold Acquisition.
Oil and natural gas production taxes. Oil and natural gas production taxes as a percentage of oil and natural gas sales were 4.65% during 2021 and increased to 4.93% in 2022. Overall, the percentage was consistent year over year, with a slight increase due to proportionately higher gas revenues which are taxed at a higher rate. Production taxes vary from state to state. Therefore, these taxes are likely to vary in the future depending on the mix of production we generate from various states (currently only Texas and New Mexico), and on the possibility that any state may raise its production tax rates.
Depreciation, depletion and amortization. Our depreciation, depletion and amortization expense increased from $37,167,967 in 2021 to $55,740,767 in 2022 due to an increase in our total estimated costs of property as well as an increase of 1,403,502 in Boe produced. Our average depreciation, depletion and amortization per Boe increased from $11.95 per Boe during 2021 to $12.35 per Boe during 2022. These per Boe amounts are calculated by dividing our total depreciation, depletion and amortization expense by our total Boe volumes sold.
Asset retirement obligation accretion. Our ARO accretion increased from $744,045 in 2021 to $983,432 in 2022. This was a result of the 32 additional wells added from 2022 drilling activities as well as ARO accretion associated with the properties acquired in the Stronghold Acquisition, offset by wells plugged and abandoned during 2022.
Operating lease expense. Our operating lease expense decreased from $523,487 in 2021 to $363,908 in 2022 due to the month to month leases for office equipment and compressors used in operations on which the Company had previously elected to apply ASU 2016-02. The office equipment and compressors are not subject to ASU 2016-02 based on the agreement and nature of use. The costs have been recorded as short-term lease costs and amounts included in lease operating expenses beginning in the second quarter of 2021.
General and administrative expenses (including share-based compensation). General and administrative expenses increased from $16,068,105 in 2021 to $27,095,323 in 2022. The increase was primarily related to a $4,743,908 increase in share-based compensation, as well as increases in salaries and bonuses, all attributed to a nearly doubled headcount from 2021 to 2022 to support our growth. Other cost increases include software maintenance, rent, insurance, and environmental sustainability. The 2022 expenses also included non-recurring acquisition-related costs of $2.1 million.
Interest expense. Interest expense increased from $14,490,474 in 2021 to $23,167,729 in 2022. The increase was the result of a combination of higher interest rates during the second half of 2022, with a weighted average interest rate of 5.8% in 2022 and 4.4% in 2021, and having higher amounts outstanding on our credit facility throughout 2022, with a weighted average daily debt of approximately $308.7 million in 2021 compared to approximately $344.0 million in 2022, particularly due to the additional debt incurred for the Stronghold Acquisition.
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Gain (loss) on derivative contracts. During 2022, the Company incurred a loss on derivative contracts of $21,532,659. During 2021, the Company recorded a loss on derivative contracts of $77,853,141. For the derivative contract settlements, the Company recorded a realized loss of $52,768,154 during 2021 and a realized loss of $62,525,954 during 2022, The increase of $9,757,800 in the realized loss was a result of the rise of crude oil prices during 2022, which was above the fixed prices of the derivative contracts. For the marked-to-market contracts, the Company recorded an unrealized gain of $40,993,295 during 2022 and an unrealized loss of $25,084,987 during 2021. This change in unrealized derivatives was due to the roll off of unfavorable contracts during 2022, as well as the Company's purchase of more favorable contracts during 2022.
Provision for income taxes. The provision for income taxes changed from a provision of $90,342 for 2021 to a provision of $8,408,724 for 2022. The current year federal tax expense was the result of certain existing deferred tax assets that will not be offset by existing deferred tax liabilities as a result of the 80% limitation on the utilization of net operating losses incurred after 2017.
Net income. The Company achieved net income of $3,322,892 in 2021 compared to net income of $138,635,025 in 2022. The increase in net income was due primarily to the increase in oil, natural gas, and NGL revenues, as well as the reduction in derivative contract losses, offset by increases in lease operating expenses, depletion, general and administrative expenses, and interest expense.
Liquidity and Capital Resources
Financing of Operations. We have historically funded our operations through cash available from operations and from equity offerings of our stock. Our primary source of cash in 2023 was from funds generated from the sale of oil and natural gas production. These cash flows were primarily used to fund our capital expenditures. We believe the combination of the sources of capital discussed will continue to be adequate to meet our short and long-term liquidity needs.
Credit Facility. On July 1, 2014, the Company entered into a Credit Agreement with SunTrust Bank (now Truist), as lender, issuing bank and administrative agent for several banks and other financial institutions and lenders (the “Administrative Agent”), (which was amended several times) that provided for a maximum borrowing base of $1 billion with security consisting of substantially all of the assets of the Company. In April 2019, the Company amended and restated the Credit Agreement with the Administrative Agent (as amended and restated, the “Credit Facility”).
On August 31, 2022, the Company modified its Credit Facility through a Second Amended and Restated Credit Agreement (the "Second Credit Agreement"), extending the maturity date of the facility to August 2026 and the syndicate was modified to add five lenders, replacing five lenders. In conjunction with the Stronghold Acquisition, with the newly acquired assets put up for collateral, the Company established a borrowing base of $600 million. The borrowing base is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time. The borrowing base is redetermined semi-annually each May and November. The borrowing base is subject to reduction in certain circumstances such as the sale or disposition of certain oil and gas properties of the Company or its subsidiaries and cancellation of certain hedging positions.
Rather than Eurodollar loans, the reference rate on the Second Credit Agreement is the SOFR. Also, the Second Credit Agreement permits the Company to declare dividends for its equity owners, subject to certain limitations, including (i) no default or event of default has occurred or will occur upon such payments, (ii) the pro forma Leverage Ratio (outstanding debt to adjusted earnings before interest, taxes, depreciation and amortization, exploration expenses, and all other non-cash charges acceptable to the Administrative Agent) does not exceed 2.00 to 1.00, (iii) the amount of such payments does not exceed Available Free Cash Flow (as defined in the Second Credit Agreement), and (iv) the Borrowing Base Utilization Percentage (as defined in the Second Credit Agreement) is not greater than 80%.
The interest rate on each SOFR Loan will be the adjusted term SOFR for the applicable interest period plus a margin between 3.0% and 4.0% (depending on the then-current level of borrowing base usage). The annual interest rate on each base rate Loan is (a) the greatest of (i) the Administrative Agent’s prime lending rate, (ii) the Federal Funds Rate (as defined in the Second Credit Agreement) plus 0.5% per annum, (iii) the adjusted term SOFR determined on a daily basis for an interest period of one month, plus 1.00% per annum and (iv) 0.00% per annum, plus (b) a margin between 2.0% and 3.0% per annum (depending on the then-current level of borrowing base usage).
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The Second Credit Agreement contains certain covenants, which, among other things, require the maintenance of (i) a total Leverage Ratio of not more than 3.0 to 1.0 and (ii) a minimum ratio of Current Assets to Current Liabilities (as such terms are defined in the Second Credit Agreement) of 1.0 to 1.0. The Second Credit Agreement also contains other customary affirmative and negative covenants and events of default. The Company is required to maintain on a rolling 24 months basis, hedging transactions in respect of crude oil and natural gas, on not less than 50% of the projected production from its proved, developed, producing oil and gas. However, if the borrowing base utilization is less than 25% at the hedge testing date and the Leverage Ratio is not greater than 1.25 to 1.00, the required hedging percentage for months 13 through 24 of the rolling 24 month period provided for will be 0% from such hedge testing date to the next succeeding hedge testing date and if the borrowing base utilization percentage is equal to or greater than 25%, but less than 50% and the Leverage Ratio is not greater than 1.25 to 1.00, the required hedging percentage for months 13 through 24 of the rolling 24 month period provided for will be 25% from such hedge testing date to the next succeeding hedge testing date.
As of December 31, 2023, $425 million was outstanding on the Credit Facility and the Company was in compliance with all covenants contained in the Second Credit Agreement.
Equity Offering. In October 2020, the Company closed on an underwritten public offering of (i) 9,575,800 Common Shares, (ii) 13,428,500 Pre-Funded Warrants and (iii) 23,004,300 Common Warrants at a combined purchase price of $0.70. This includes a partial exercise of the over-allotment. The Common Warrants have a term of five years and an exercise price of $0.80 per share. Gross proceeds totaled $16,089,582.
Concurrently with the underwritten public offering, the Company closed on a registered direct offering of (i) 3,500,000 Common Shares, (ii) 3,300,000 Pre-Funded Warrants and (iii) 6,800,000 Common Warrants at a combined purchase price of $0.70. The Common Warrants have a term of five years and an exercise price of $0.80 per share. Gross proceeds totaled $4,756,700.
Total gross proceeds from the 2020 underwritten public offering and the registered direct offering aggregated $20,846,282. Total net proceeds for the Common Warrants exercised in 2020 aggregated $19,379,832.
The Common Shares of 9,575,800 and 3,500,000 were issued in 2020. The Pre-Funded Warrants of 3,300,000 were exercised and common stock was issued in 2020. The Pre-Funded Warrants of 13,428,500 were exercised and common stock was issued in 2021, as shown in our Statements of Stockholders' Equity. Of the aforementioned 23,004,300 Common Warrants, 442,600 were exercised and common stock was issued in 2021; 10,253,907 were exercised and common stock was issued in 2022; and 19,029,593 were exercised and common stock was issued in 2023 (4,517,427 exercised at $0.80 and 14,512,166 exercised at $0.62 - refer to Note 11 — STOCKHOLDERS' EQUITY); as shown in our Statements of Stockholders' Equity.
Issuance of Common Stock and Convertible Preferred Stock for Stronghold Acquisition. As part of the consideration for the Stronghold Acquisition, on August 31, 2022 the Company issued 21,339,986 shares of common stock and 153,176 shares of newly created Series A Convertible Preferred Stock, which was converted into 42,548,892 shares of common stock on October 27, 2022.
Cash Flows. Historically, primary sources of cash have been from operations, equity offerings and borrowings on the Credit Facility. During 2023, 2022, and 2021 we had net cash provided by operating activities of $198.2 million, $197.0 million, and $72.7 million, respectively. During the three years ended December 31, 2023, we financed $20.9 million through proceeds from the sale of common stock. During 2023, 2022, and 2021, the Company had a net draw of $10.0 million, a net draw of $125.0 million, and a net repayment of $23.0 million on the Credit Facility, respectively. We primarily used this cash to fund our capital expenditures and development aggregating $596.9 million over the three years ended December 31, 2023. Additionally, during 2023, 2022 and 2021, we used cash of $215.0 million, $511.0 million and $83.2 million, respectively, to reduce the outstanding balance on our Credit Facility. As of December 31, 2023, we had cash on hand of $0.3 million and negative working capital of $57.9 million, compared to cash on hand of $3.7 million and negative working capital of $78.6 million as of December 31, 2022 and cash on hand of $2.4 million and negative working capital of $46.9 million as of December 31, 2021.
Contractual Obligations. The Company maintains a Credit Facility which currently has a $600 million borrowing base. The outstanding balance on that Credit Facility as of December 31, 2023 was $425.0 million, which will require repayment or refinancing at or prior to maturity in August 2026.
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The Company leases office spaces in The Woodlands, Texas and Midland, Texas. The Woodlands office was under a five-and-a-half-year lease beginning January 15, 2021; however, effective as of May 31, 2023, The Woodlands office sub-lease was terminated. On May 9, 2023, the Company entered into a 71-month (five years and 11-month) new lease for a larger amount of office space in The Woodlands, Texas. The Midland office lease was amended effective October 1, 2022, with the revised five-year lease ending September 30, 2027.
The Company has financing leases for vehicles with varying maturity dates through 2026. Future lease payments for financing leases aggregate $2,006,453.
Subsequent Events
Surety Bonds - On January 10, 2024, two insurance companies issued surety bonds on behalf of the Company, one for $250,000, an RRC required blanket performance bond to operate 100 wells or more in the State of Texas, and one for $2,000,000, an RRC required blanket plugging extension bond, each with zero collateral requirements. The term for these two surety bonds ends on July 1, 2025 and can be renewed at that time.
First Amendment to Second Amended and Restated Credit Agreement - On February 12, 2024, the Company, Truist Bank ("Truist") as the Administrative Agent and Issuing Bank, and the lenders party thereto (the "Lenders") entered into an amendment (the "Amendment") to the Second Amended and Restated Credit Agreement dated August 31, 2022, by and among the Company, as Borrower, Truist as Administrative Agent and Issuing Bank, and the Lenders (together with all amendments or other modifications, the "Credit Agreement"). Among other things, the Amendment amends the definition of Free Cash Flow so amounts used by the Company for acquisitions will no longer be subtracted from the calculation of Free Cash Flow.
Effects of Inflation and Pricing
The oil and natural gas industry is cyclical and the demand for goods and services of oil field companies, suppliers, and others associated with the industry puts significant pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do associated costs. Material changes in prices impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, and the value of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money, and retain personnel. We anticipate business costs will vary in accordance with commodity prices for oil and natural gas, and the associated increase or decrease in demand for services related to production and exploration.
Off-Balance Sheet Financing Arrangements
As of December 31, 2023, we had no off-balance sheet financing arrangements.
Critical Accounting Policies and Estimates
Our discussion of financial condition and results of operations is based upon the information reported in our financial statements. The preparation of these statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, weather, politics, global economics, mechanical problems, general business conditions and other factors. Our significant accounting policies, as well as considerations of recent accounting pronouncements, are detailed in "Note 1 — ORGANIZATION, BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES" to our financial statements included in this Annual Report. We have outlined below certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management.
Revenue Recognition. In January 2018, the Company adopted Accounting Standards Update (“ASU”) 2014-09 Revenues from Contracts with Customers (Topic 606) (“ASU 2014-09”). The timing of recognizing revenue from the sale of produced crude oil and natural gas was not changed as a result of adopting ASU 2014-09. The Company predominantly derives its revenue from the sale of produced crude oil and natural gas. The contractual performance obligation is satisfied when the product is delivered to the purchaser. Revenue is recorded in the month the product is delivered to the purchaser.
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The Company receives payment from one to three months after delivery. The transaction price includes variable consideration as product pricing is based on published market prices and reduced for contract specified differentials (quality, transportation and other variables from benchmark prices). The guidance regarding ASU 2014-09 does not require that the transaction price be fixed or stated in the contract. Estimating the variable consideration does not require significant judgment and Ring engages third party sources to validate the estimates. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration the Company expects to receive in exchange for those products. See "Note 2 — REVENUE RECOGNITION" of our financial statements for additional information.
Full Cost Method of Accounting. The Company uses the full cost method of accounting for oil and natural gas properties. Under this method, all costs (direct and indirect) associated with acquisition, exploration, and development of oil and natural gas properties are capitalized. Costs capitalized include acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties and costs of drilling and equipping productive and non-productive wells. Drilling costs include directly related overhead costs. All of our properties are located within the continental United States.
Write-down of Oil and Natural Gas Properties. Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly utilizing the average of prices in effect on the first day of the month for the preceding twelve-month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10%, plus the lower of cost or market value of unproved properties, less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depletion, depreciation and amortization (“DD&A”) rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling.
The Company did not have any write-downs related to the full cost ceiling limitation during the years ended December 31, 2023, 2022, or 2021.
Our estimates of reserves and future cash flow as of December 31, 2023 and 2022 were prepared using an average price equal to the unweighted arithmetic average of the first day of the month price for each month within the 12-month periods ended December 31, 2023 and 2022, respectively, in accordance with SEC guidelines. As of December 31, 2023, our reserves were based on an SEC average price of $74.70 per Bbl of WTI oil posted and $2.637 per MMBtu Henry Hub natural gas. As of December 31, 2022, our reserves were based on an SEC average price of $90.15 per Bbl of WTI oil posted and $6.358 per MMBtu Henry Hub natural gas. Prices are adjusted by local field and lease level differentials and are held constant for life of reserves in accordance with SEC guidelines.
Oil and Natural Gas Reserve Quantities. Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. Reserve quantities and future cash flows included in this Annual Report are prepared in accordance with guidelines established by the SEC and FASB. The accuracy of our reserve estimates is a function of:
•the quality and quantity of available data;
•the interpretation of that data;
•the accuracy of various mandated economic assumptions; and
•the judgments of the persons preparing the estimates.
Our proved reserve information included in this Annual Report was prepared and determined by Cawley, Gillespie & Associates, Inc., independent petroleum engineers. Because these estimates depend on many assumptions, all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered. We continually make revisions to reserve estimates throughout the year as additional properties are acquired. We make changes to depletion rates and impairment calculations in the same period that changes to the reserve estimates are made.
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All capitalized costs of oil and natural gas properties, including the estimated future costs to develop proved reserves and estimated future costs to plug and abandon wells and costs of site restoration, less the estimated salvage value of equipment associated with the oil and natural gas properties, are amortized on the unit-of-production method using estimates of proved reserves as determined by independent petroleum engineers. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined.
Income Taxes. Deferred income taxes are provided on differences between the tax basis of assets and liabilities and their carrying amounts in the financial statements, and tax carryforwards. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is settled. Since our tax returns are filed after the financial statements are prepared, estimates are required in valuing tax assets and liabilities. We record adjustments to the actual values in the period the Company files its tax returns.
In assessing the Company’s deferred tax assets, we consider whether a valuation allowance should be recorded for some or all of the deferred tax assets which may not be realized. The ultimate realization of deferred tax assets is assessed at each reporting period and is dependent upon the generation of future taxable income and the Company’s ability to utilize operation loss carryforwards during the periods in which the temporary differences become deductible. We also consider the reversal of deferred tax liabilities and available tax planning strategies.
Item 7A: Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Market risk refers to the risk of loss from adverse changes in oil and natural gas prices. Realized pricing is primarily driven by the prevailing domestic price for crude oil and spot prices applicable to the region in which we produce oil and natural gas. Historically, prices received for oil and natural gas production have been volatile and unpredictable. We expect pricing volatility to continue.
The prices we receive depend on many factors outside of our control. Oil prices received during 2023 ranged from a monthly average low of $68.72 per barrel to a monthly average high of $89.13 per barrel. Natural gas prices realized during 2023 ranged from a monthly average low of $(0.94) per Mcf to a monthly average high of $1.52 per Mcf. In some months, fees exceeded the pricing, causing a negative net realized price. Gross natural gas prices ranged from a monthly average low of $0.76 per Mcf to a monthly average high of $2.78 per Mcf. Fees ranged from a monthly average low of $(2.07) per Mcf to a monthly average high of $(0.87) per Mcf. NGL prices received during 2023 ranged from a monthly average low of $7.07 per barrel to a monthly average high of $14.71 per barrel. A significant decline in the prices of oil or natural gas would likely have a material adverse effect on our financial condition and results of operations. In order to reduce commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas, we enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production. The following table summarizes the Company's hedges in place on a monthly basis by commodity type. See "Note 7 — DERIVATIVE FINANCIAL INSTRUMENTS" to our financial statements for further information.
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| Oil Hedges (WTI) | Gas Hedges (Henry Hub) | |||||||||||||
| Month | Average BBL/day | Average MMBtu/day | ||||||||||||
| January 2024 | 6,475 | — | ||||||||||||
| February 2024 | 6,457 | 8,999 | ||||||||||||
| March 2024 | 6,438 | 8,311 | ||||||||||||
| April 2024 | 5,921 | 8,383 | ||||||||||||
| May 2024 | 5,906 | 7,999 | ||||||||||||
| June 2024 | 5,891 | 8,124 | ||||||||||||
| July 2024 | 5,575 | 7,704 | ||||||||||||
| August 2024 | 5,575 | 7,590 | ||||||||||||
| September 2024 | 5,575 | 7,722 | ||||||||||||
| October 2024 | 5,400 | 7,336 | ||||||||||||
| November 2024 | 5,400 | 7,467 | ||||||||||||
| December 2024 | 5,400 | 7,133 | ||||||||||||
| January 2025 | 5,275 | 7,023 | ||||||||||||
| February 2025 | 5,275 | 7,633 | ||||||||||||
| March 2025 | 5,275 | 6,831 | ||||||||||||
| April 2025 | 5,100 | 6,961 | ||||||||||||
| May 2025 | 5,100 | 6,662 | ||||||||||||
| June 2025 | 5,100 | 6,790 | ||||||||||||
| July to September 2025 | 4,450 | 6,450 | ||||||||||||
| October to December 2025 | 4,400 | 6,500 | ||||||||||||
Customer Credit Risk
Our principal exposure to credit risk is through receivables from the sale of our oil and natural gas production (approximately $37.9 million as of December 31, 2023). We are subject to credit risk due to the concentration of our oil and natural gas receivables with our most significant customers, or purchasers. We do not require our purchasers to post collateral, and the inability of our significant purchasers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. The following table sets forth certain information regarding the top three purchasers of our oil, natural gas, and NGLs for the year ended December 31, 2023. We believe that the loss of any of these purchasers would not materially impact our business because we could readily find other purchasers for our oil and natural gas.
For the Year Ended | As of | |||||||||||||
December 31, 2023 | December 31, 2023 | |||||||||||||
Percentage of Oil, Natural Gas, and Natural Gas Liquids Revenues | Percentage of accounts receivables from the sale of our oil and natural gas production | |||||||||||||
| Purchaser: | ||||||||||||||
Phillips 66 Company ("Phillips") | 66% | 65% | ||||||||||||
Enterprise Crude Oil LLC ("Enterprise") | 12% | 11% | ||||||||||||
NGL Crude Partners ("NGL Crude") | 10% | 8% | ||||||||||||
Interest Rate Risk
We are subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility, which bears variable interest based upon a prime rate and is therefore susceptible to interest rate fluctuations.
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Changes in interest rates affect the interest earned on the Company’s cash and cash equivalents and the interest rate paid on borrowings under the Credit Facility.
As of December 31, 2023, we had $425.0 million outstanding on our Credit Facility with a weighted average annual interest rate for the year then ended of 8.8%. A 1% change in the interest rate on our Credit Facility would result in an estimated $4.3 million change in our annual interest expense. See "Note 9 — REVOLVING LINE OF CREDIT" in the notes to the financial statements for more information on the Company’s interest rates of our Credit Facility.
Currently, we do not use interest rate derivative instruments to manage exposure to interest rate changes.
Currency Exchange Rate Risk
Foreign sales accounted for none of the Company's sales; the Company accepts payment for its commodity sales only in U.S. dollars. Ring is therefore not exposed to foreign currency exchange rate risk on these sales.
Please also see Item 1A “Risk Factors” above for a discussion of other risks and uncertainties we face in our business.
Item 8: Financial Statements and Supplementary Data
The financial statements and supplementary data required by this item are included beginning at page F-1 of this Annual Report.
Item 9: Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A: Controls and Procedures
Evaluation of disclosure controls and procedures.
Under the direction of our Chief Executive Officer and Chief Financial Officer, we have established disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.
As of December 31, 2023, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that as of December 31, 2023, our disclosure controls and procedures are effective.
Changes in internal control over financial reporting.
We regularly review our system of internal control over financial reporting and make changes to our processes and systems to improve controls and increase efficiency, while ensuring that we maintain an effective internal control environment. Changes may include such activities as implementing new, more efficient systems, consolidating activities, and migrating processes.
There were no changes in our internal control over financial reporting that occurred during the fourth quarter ended December 31, 2023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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Management’s Annual Report on Internal Control Over Financial Reporting and Report of Independent Accounting Firm
Our management is responsible for establishing and maintaining adequate internal controls over financial reporting. Our internal control system is designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Furthermore, the effectiveness of a system of internal control over financial reporting in future periods can change as conditions change.
In making our assessment of internal control over financial reporting, our management used the criteria issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework (2013). Based on our assessment, we believe that, as of December 31, 2023, our internal control over financial reporting is effective based on those criteria.
The independent registered public accounting firm, Grant Thornton LLP, has audited the financial statements and internal control over financial reporting included in this Annual Report on Form 10-K, and has issued their report on the effectiveness of the Company’s internal control over financial reporting at December 31, 2023. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting at December 31, 2023, is set forth below.
65
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Ring Energy, Inc.
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of Ring Energy, Inc. (a Nevada corporation) (the “Company”) as of December 31, 2023, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the financial statements of the Company as of and for the year ended December 31, 2023, and our report dated March 7, 2024 expressed an unqualified opinion on those financial statements.
Basis for opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and limitations of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ GRANT THORNTON LLP
Houston, Texas
March 7, 2024
66
Item 9B: Other Information
On March 6, 2024, the Board, upon the recommendation of the compensation committee of the Board (the “Compensation Committee”), approved the Ring Energy, Inc. Change in Control and Severance Benefit Plan (the “CIC Plan”) which provides for severance benefits to our named executive officers (and certain other officers and key employees), including: Paul D. McKinney, Chairman of the Board and Chief Executive Officer (the “Tier 1 NEO”), and Marinos Baghdati, Executive Vice President of Operations, Stephen D. Brooks, Executive Vice President of Land, Legal, Human Resources and Marketing, Alexander Dyes, Executive Vice President of Engineering and Corporate Strategy, and Travis T. Thomas Executive Vice President and Chief Financial Officer (collectively, the “Tier 2 NEOs” and with the Tier 1 NEO, collectively, the “NEOs”). The CIC Plan supersedes and replaces all other severance arrangements between the Company and the NEOs, which previously had been governed by separate employment agreements.
Pursuant to the CIC Plan, following a Change in Control (as defined in the CIC Plan) and during the “protection period,” which period extends from the date six months prior to a Change in Control until the date 24 months following the occurrence of a Change in Control, if the Tier 1 NEO’s employment is terminated by the Company without Cause (as defined in the CIC Plan) or by him for a CIC Good Reason (as defined in the CIC Plan), he is entitled to (1) 300% of his annual base salary; (2) 300% of his most recent target annual bonus (the “AIP Amount”); (3) 100% of his pro-rated AIP Amount (based on the number of days employed during the year of termination); (4) acceleration and vesting of his outstanding equity awards; and (5) reimbursement of 24 months of health benefits.
In addition, following the Tier 1 NEO’s death or disability, he would be entitled to (1) acceleration and vesting of his outstanding equity awards; and (2) reimbursement of 12 months of health benefits.
Pursuant to the CIC Plan, if the Tier 1 NEO’s employment with the Company is terminated by the Company without Cause or by him for a Good Reason (as defined in the CIC Plan) and not during the applicable protection period, he is entitled to receive (1) 200% of his annual base salary, (2) 200% of his AIP Amount; (3) 100% of his pro-rated AIP Amount (based on the number of days employed during the year of termination); (4) acceleration and vesting of his outstanding equity awards; and (5) reimbursement of 24 months of health benefits.
Pursuant to the CIC Plan, following a Change in Control and during the “protection period,” which period extends from the date six months prior to a Change in Control until the date 24 months following the occurrence of a Change in Control, if the Tier 2 NEO’s employment is terminated by the Company without Cause or by him for a CIC Good Reason, he is entitled to (1) 200% of his annual base salary; (2) 200% of his AIP Amount; (3) 100% of his pro-rated AIP Amount (based on the number of days employed during the year of termination); (4) acceleration and vesting of his outstanding equity awards; and (5) reimbursement of 18 months of health benefits.
In addition, following the Tier 2 NEO’s death or disability, he would be entitled to (1) acceleration and vesting of his outstanding equity awards; and (2) reimbursement of 12 months of health benefits.
Pursuant to the CIC Plan, if the Tier 2 NEO’s employment with the Company is terminated by the Company without Cause or by him for a Good Reason and not during the applicable protection period, he is entitled to receive (1) 100% of his annual base salary; (2) 100% of his AIP Amount; (3) 100% of his pro-rated AIP Amount (based on the number of days employed during the year of termination); (4) acceleration and vesting of his outstanding equity awards; and (5) reimbursement of 18 months of health benefits.
Entitlement to the above benefits is conditioned on the timely execution of a general release in the form and substance approved by the Compensation Committee, and each executive’s compliance with non-competition, non-solicitation and confidentiality covenants set forth in the CIC Plan.
In order to be eligible to receive benefits under the CIC Plan, the executives must execute and return to the Company a participation agreement (a “Participation Agreement”) the form of which is attached as Exhibit B to the CIC Plan. Upon the execution of a Participation Agreement, the executive’s prior employment agreement terminates, and the continued employment of such executive will be on an at-will basis. On March 6, 2024, Messrs. McKinney, Baghdati, Brooks, Dyes and Thomas became participants in the CIC Plan upon their delivery to the Company of executed Participation Agreements, pursuant to which the NEOs agreed to terminate the existing employment agreements between them and the Company, effective immediately, and the terms of the CIC Plan and respective Participation Agreements supersede any rights or entitlements to severance benefits under any employment agreement so terminated or other severance arrangements. The CIC Plan does not affect the NEOs’ eligibility to their base salary, subject to increase at the
67
discretion of the Board, or the Compensation Committee, and to participate in any and all other standard benefit plans, programs and policies of the Company.
The description of the CIC Plan contained in this Item 9B does not purport to be complete and is qualified in its entirety by reference to the CIC Plan included as Exhibit 10.25 to this Annual Report.
Item 9C: Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
None.
PART III
Item 10: Directors, Executive Officers and Corporate Governance
The information required by this item is incorporated by reference herein from the Company's 2024 Proxy Statement to be filed with the SEC no later than 120 days after December 31, 2023. If the Proxy Statement is not filed with the SEC by such time, such information will be included in an amendment to this Annual Report by such time.
Item 11: Executive Compensation
The information required by this item is incorporated by reference herein from the Company's 2024 Proxy Statement to be filed with the SEC no later than 120 days after December 31, 2023. If the Proxy Statement is not filed with the SEC by such time, such information will be included in an amendment to this Annual Report by such time.
Item 12: Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by this item is incorporated by reference herein from the Company's 2024 Proxy Statement to be filed with the SEC no later than 120 days after December 31, 2023. If the Proxy Statement is not filed with the SEC by such time, such information will be included in an amendment to this Annual Report by such time.
Item 13: Certain Relationships and Related Transactions, and Director Independence
The information required by this item is incorporated by reference herein from the Company's 2024 Proxy Statement to be filed with the SEC no later than 120 days after December 31, 2023. If the Proxy Statement is not filed with the SEC by such time, such information will be included in an amendment to this Annual Report by such time.
Item 14: Principal Accountant Fees and Services
The information required by this item is incorporated by reference herein from the Company's 2024 Proxy Statement to be filed with the SEC no later than 120 days after December 31, 2023. If the Proxy Statement is not filed with the SEC by such time, such information will be included in an amendment to this Annual Report by such time.
68
PART IV
Item 15: Exhibits and Financial Statement Schedules
| Incorporated by Reference | ||||||||||||||||||||||||||||||||||||||||||||
| Exhibit Number | Exhibit Description | Form | File No. | Exhibit | Filing Date | Filed Here-with | Furn-ished Here-with | |||||||||||||||||||||||||||||||||||||
| 2.1 | 8-K | 001-36057 | 2.1 | 2/28/19 | ||||||||||||||||||||||||||||||||||||||||
| 2.2 | 8-K | 001-36057 | 2.1 | 7/8/22 | ||||||||||||||||||||||||||||||||||||||||
| 2.2(a) | 8-K | 001-36057 | 2.1 | 8/9/22 | ||||||||||||||||||||||||||||||||||||||||
| 2.3 | 8-K | 001-36057 | 2.1 | 7/14/23 | ||||||||||||||||||||||||||||||||||||||||
| 3.1 | 10-K | 000-53920 | 3.1 | 4/1/13 | ||||||||||||||||||||||||||||||||||||||||
| 3.1(a) | 8-K | 001-36057 | 3.1 | 12/17/21 | ||||||||||||||||||||||||||||||||||||||||
3.1(b) | 8-K | 001-36057 | 3.1 | 5/26/23 | ||||||||||||||||||||||||||||||||||||||||
| 3.2 | 8-K | 001-36057 | 3.1 | 4/15/21 | ||||||||||||||||||||||||||||||||||||||||
| 3.3 | 8-K | 001-36057 | 3.1 | 9/6/22 | ||||||||||||||||||||||||||||||||||||||||
| 3.4 | 8-K | 001-36057 | 3.1 | 10/31/22 | ||||||||||||||||||||||||||||||||||||||||
| 4.1 | 10-Q | 001-36057 | 4.1 | 4/12/19 | ||||||||||||||||||||||||||||||||||||||||
| 4.2 | X | |||||||||||||||||||||||||||||||||||||||||||
| 4.3 | 8-K | 001-36057 | 4.1 | 10/29/20 | ||||||||||||||||||||||||||||||||||||||||
69
| Incorporated by Reference | ||||||||||||||||||||||||||||||||||||||||||||
| Exhibit Number | Exhibit Description | Form | File No. | Exhibit | Filing Date | Filed Here-with | Furn-ished Here-with | |||||||||||||||||||||||||||||||||||||
| 10.1* | 8-K | 001-36957 | 10.1 | 12/4/20 | ||||||||||||||||||||||||||||||||||||||||
| 10.2* | 8-K | 001-36957 | 10.1 | 10/6/20 | ||||||||||||||||||||||||||||||||||||||||
| 10.3* | 8-K | 001-36057 | 10.1 | 12/22/20 | ||||||||||||||||||||||||||||||||||||||||
| 10.4* | 8-K | 001-36057 | 10.2 | 12/22/20 | ||||||||||||||||||||||||||||||||||||||||
| 10.5* | 8-K | 000-53920 | 99.3 | 1/24/13 | ||||||||||||||||||||||||||||||||||||||||
| 10.6* | 10-Q | 000-53920 | 10.2 | 8/14/12 | ||||||||||||||||||||||||||||||||||||||||
| 10.7 | 10-Q | 001-36057 | 10.2 | 5/8/19 | ||||||||||||||||||||||||||||||||||||||||
| 10.8 | 8-K | 001-36057 | 10.1 | 12/9/19 | ||||||||||||||||||||||||||||||||||||||||
| 10.9 | 8-K | 001-36057 | 10.1 | 6/19/20 | ||||||||||||||||||||||||||||||||||||||||
| 10.10 | 8-K | 001-36057 | 10.1 | 12/29/20 | ||||||||||||||||||||||||||||||||||||||||
| 10.11 | 8-K | 001-36057 | 10.1 | 6/16/21 | ||||||||||||||||||||||||||||||||||||||||
| 10.12 | 8-K | 001-36057 | 10.1 | 6/25/21 | ||||||||||||||||||||||||||||||||||||||||
10.13* | 8-K | 001-36057 | 10.1 | 3/26/21 | ||||||||||||||||||||||||||||||||||||||||
| 10.14 | 8-K | 001-36057 | 10.1 | 9/6/22 | ||||||||||||||||||||||||||||||||||||||||
| 10.15 | 8-K | 001-36057 | 10.2 | 9/6/22 | ||||||||||||||||||||||||||||||||||||||||
| 10.16 | 8-K | 001-36057 | 10.3 | 9/6/22 | ||||||||||||||||||||||||||||||||||||||||
70
| Incorporated by Reference | ||||||||||||||||||||||||||||||||||||||||||||
| Exhibit Number | Exhibit Description | Form | File No. | Exhibit | Filing Date | Filed Here-with | Furn-ished Here-with | |||||||||||||||||||||||||||||||||||||
| 10.17 | 8-K | 001-36057 | 10.4 | 9/6/22 | ||||||||||||||||||||||||||||||||||||||||
10.18* | DEF 14A | 001-36057 | 4/22/21 | |||||||||||||||||||||||||||||||||||||||||
10.19* | 8-K | 001-36057 | 10.1 | 5/26/23 | ||||||||||||||||||||||||||||||||||||||||
10.20* | 8-K | 001-36057 | 10.1 | 11/30/21 | ||||||||||||||||||||||||||||||||||||||||
10.21* | 8-K | 001-36057 | 10.1 | 2/23/23 | ||||||||||||||||||||||||||||||||||||||||
10.22* | 8-K | 001-36057 | 10.2 | 2/23/23 | ||||||||||||||||||||||||||||||||||||||||
| 10.23 | 8-K | 001-36057 | 10.1 | 4/12/23 | ||||||||||||||||||||||||||||||||||||||||
| 10.24 | 8-K | 001-36057 | 10.1 | 2/16/24 | ||||||||||||||||||||||||||||||||||||||||
| 10.25 | X | |||||||||||||||||||||||||||||||||||||||||||
| 14.1 | 8-K | 000-53920 | 14.1 | 1/24/13 | ||||||||||||||||||||||||||||||||||||||||
| 23.1 | X | |||||||||||||||||||||||||||||||||||||||||||
| 23.2 | X | |||||||||||||||||||||||||||||||||||||||||||
| 24.1 | X | |||||||||||||||||||||||||||||||||||||||||||
| 31.1 | X | |||||||||||||||||||||||||||||||||||||||||||
| 31.2 | X | |||||||||||||||||||||||||||||||||||||||||||
| 32.1 | X | |||||||||||||||||||||||||||||||||||||||||||
| 32.2 | X | |||||||||||||||||||||||||||||||||||||||||||
| 97.1 | X | |||||||||||||||||||||||||||||||||||||||||||
| 99.1 | X | |||||||||||||||||||||||||||||||||||||||||||
| 101.INS | Inline XBRL Instance Document | X | ||||||||||||||||||||||||||||||||||||||||||
| 101.SCH | Inline XBRL Taxonomy Extension Schema Document | X | ||||||||||||||||||||||||||||||||||||||||||
| 101.CAL | Inline XBRL Taxonomy Extension Calculation Linkbase Document | X | ||||||||||||||||||||||||||||||||||||||||||
| 101.DEF | Inline XBRL Taxonomy Extension Definition Linkbase Document | X | ||||||||||||||||||||||||||||||||||||||||||
| 101.LAB | Inline XBRL Taxonomy Extension Label Linkbase Document | X | ||||||||||||||||||||||||||||||||||||||||||
71
| Incorporated by Reference | ||||||||||||||||||||||||||||||||||||||||||||
| Exhibit Number | Exhibit Description | Form | File No. | Exhibit | Filing Date | Filed Here-with | Furn-ished Here-with | |||||||||||||||||||||||||||||||||||||
| 101.PRE | Inline XBRL Taxonomy Extension Presentation Linkbase Document | X | ||||||||||||||||||||||||||||||||||||||||||
| 104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). | |||||||||||||||||||||||||||||||||||||||||||
*Management contract
Item 16: Form 10-K Summary
None.
72
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| Ring Energy, Inc. | ||||||||
| By: | /s/ Paul D. McKinney | |||||||
| Mr. Paul D. McKinney | ||||||||
| Chief Executive Officer | ||||||||
Date: March 7, 2024 | ||||||||
KNOW ALL PERSONS BY THESE PRESENTS, that each individual whose signature appears below constitutes and appoints Paul D. McKinney, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K filed with the Securities and Exchange Commission, hereby ratifying and confirming his signature as he may be signed by his or her said attorney to any and all amendments to said Annual Report on Form 10-K.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on the dates indicated.
| /s/ Paul D. McKinney | /s/ Thomas L. Mitchell | |||||||
| Mr. Paul D. McKinney | Mr. Thomas L. Mitchell | |||||||
| Chief Executive Officer and Director | Director | |||||||
| (Principal Executive Officer) | Date: March 7, 2024 | |||||||
Date: March 7, 2024 | ||||||||
| /s/ Travis T. Thomas | /s/ Anthony B. Petrelli | |||||||
| Mr. Travis T. Thomas | Mr. Anthony B. Petrelli | |||||||
| Chief Financial Officer | Director | |||||||
| (Principal Financial Officer) | Date: March 7, 2024 | |||||||
Date: March 7, 2024 | ||||||||
| /s/ Regina Roesener | /s/ Clayton E. Woodrum | |||||||
| Mrs. Regina Roesener | Mr. Clayton E. Woodrum | |||||||
| Director | Director | |||||||
Date: March 7, 2024 | Date: March 7, 2024 | |||||||
| /s/ Richard E. Harris | /s/ John A. Crum | |||||||
| Mr. Richard E. Harris | Mr. John A. Crum | |||||||
| Director | Director | |||||||
Date: March 7, 2024 | Date: March 7, 2024 | |||||||
| /s/ Roy I. Ben-Dor | /s/ David S. Habachy | |||||||
| Mr. Roy I. Ben-Dor | Mr. David S. Habachy | |||||||
| Director | Director | |||||||
Date: March 7, 2024 | Date: March 7, 2024 | |||||||
73
RING ENERGY, INC.
INDEX TO FINANCIAL STATEMENTS
| Page | |||||
Report of | F-2 | ||||
F-4 | |||||
F-5 | |||||
F-6 | |||||
F-7 | |||||
F-9 | |||||
F-39 | |||||
F-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Ring Energy, Inc.
Opinion on the financial statements
We have audited the accompanying balance sheets of Ring Energy, Inc. (a Nevada corporation) (the “Company”) as of December 31, 2023 and 2022, the related statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated March 7, 2024 expressed an unqualified opinion.
Basis for opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical audit matters
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing separate opinions on the critical audit matter or on the accounts or disclosures to which it relates.
The development of estimated proved crude oil and natural gas reserves used in the calculation of depletion, depreciation and amortization expense under the full cost method of accounting
As described further in Note 1 to the financial statements, the Company accounts for its oil and gas properties using the full cost method of accounting, which requires management to make estimates of proved crude oil and natural gas reserve volumes and future net revenues to record depletion, depreciation and amortization expense. To estimate the volume of proved crude oil and natural gas reserves and future net revenue, management makes significant estimates and assumptions including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties. In addition, the estimation of proved crude oil and natural gas reserves is impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved crude oil and natural gas reserves to determine if wells are expected, with reasonable certainty, to be economical under the appropriate pricing assumptions required in the estimation of depletion,
F-2
depreciation and amortization expense. We identified the estimation of proved reserves of oil and gas properties as a critical audit matter.
The principal consideration for our determination that the estimation of proved crude oil and natural gas reserves is a critical audit matter is that changes in certain inputs and assumptions, which require a high degree of subjectivity, necessary to estimate the volume and future net revenues of the Company’s proved reserves could have a significant impact on the measurement of depletion, depreciation and amortization expense. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment.
Our audit procedures related to the estimation of proved crude oil and natural gas reserves included the following, among others.
•We tested the design and operating effectiveness of controls relating to management’s estimation of proved crude oil and natural gas reserves for the purpose of estimating depletion, depreciation and amortization expense.
•We evaluated the independence, objectivity, and professional qualifications of the Company’s reserve engineers, made inquiries of those specialists regarding the process followed and judgments made to estimate the Company’s proved crude oil and natural gas reserve volumes, and read the reserve report prepared by the Company’s specialists.
•To the extent key inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, including, but not limited to: historical pricing differentials, operating costs, estimated capital costs, and ownership interests, we tested management’s process for determining the assumptions, including examining the underlying support on a sample basis. Specifically, our audit procedures involved testing management’s assumptions by performing the following:
◦We compared the estimated pricing differentials used in the reserve report to prices realized by the Company related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials.
◦We tested models used to estimate the future operating costs in the reserve report and compared amounts to historical operating costs.
◦We evaluated the method used to determine the estimated future development costs used in the reserve report and compared management’s estimates to amounts expended for recently drilled and completed wells.
◦We tested the working and net revenue interests used in the reserve report by inspecting land, legal and division order records.
◦We evaluated evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company’s ability to fund and intent to develop the proved undeveloped properties, and
◦We applied analytical procedures to production forecasts in the reserve report by comparing to historical actual results.
/s/ GRANT THORNTON LLP
We have served as the Company’s auditor since 2021.
March 7, 2024
F-3
| As of December 31, | 2023 | 2022 | ||||||||||||
| ASSETS | ||||||||||||||
| Current Assets | ||||||||||||||
| Cash and cash equivalents | $ | $ | ||||||||||||
| Accounts receivable | ||||||||||||||
Joint interest billing receivables, net | ||||||||||||||
| Derivative assets | ||||||||||||||
| Inventory | ||||||||||||||
| Prepaid expenses and other assets | ||||||||||||||
| Total Current Assets | ||||||||||||||
| Properties and Equipment | ||||||||||||||
| Oil and natural gas properties, full cost method | ||||||||||||||
| Financing lease asset subject to depreciation | ||||||||||||||
| Fixed assets subject to depreciation | ||||||||||||||
| Total Properties and Equipment | ||||||||||||||
| Accumulated depreciation, depletion and amortization | ( | ( | ||||||||||||
| Net Properties and Equipment | ||||||||||||||
| Operating lease asset | ||||||||||||||
| Derivative assets | ||||||||||||||
| Deferred financing costs | ||||||||||||||
| Total Assets | $ | $ | ||||||||||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||||||||
| Current Liabilities | ||||||||||||||
| Accounts payable | $ | $ | ||||||||||||
| Financing lease liability | ||||||||||||||
| Operating lease liability | ||||||||||||||
| Derivative liabilities | ||||||||||||||
| Notes payable | ||||||||||||||
| Deferred cash payment | ||||||||||||||
| Asset retirement obligations | ||||||||||||||
| Total Current Liabilities | ||||||||||||||
| Non-current Liabilities | ||||||||||||||
| Deferred income taxes | ||||||||||||||
| Revolving line of credit | ||||||||||||||
| Financing lease liability, less current portion | ||||||||||||||
| Operating lease liability, less current portion | ||||||||||||||
| Derivative liabilities | ||||||||||||||
| Asset retirement obligations | ||||||||||||||
| Total Liabilities | ||||||||||||||
Commitments and Contingencies - See Note | ||||||||||||||
| Stockholders' Equity | ||||||||||||||
Preferred stock - $ | ||||||||||||||
Common stock - $ | ||||||||||||||
| Additional paid-in capital | ||||||||||||||
| Accumulated deficit | ( | ( | ||||||||||||
| Total Stockholders’ Equity | ||||||||||||||
| Total Liabilities and Stockholders' Equity | $ | $ | ||||||||||||
The accompanying notes are an integral part of these financial statements.
F-4
| For the years ended December 31, | 2023 | 2022 | 2021 | |||||||||||||||||
| Oil, Natural Gas, and Natural Gas Liquids Revenues | $ | $ | $ | |||||||||||||||||
| Costs and Operating Expenses | ||||||||||||||||||||
| Lease operating expenses | ||||||||||||||||||||
| Gathering, transportation and processing costs | ||||||||||||||||||||
| Ad valorem taxes | ||||||||||||||||||||
| Oil and natural gas production taxes | ||||||||||||||||||||
| Depreciation, depletion and amortization | ||||||||||||||||||||
| Asset retirement obligation accretion | ||||||||||||||||||||
| Operating lease expense | ||||||||||||||||||||
| General and administrative expense | ||||||||||||||||||||
| Total Costs and Operating Expenses | ||||||||||||||||||||
Income from Operations | ||||||||||||||||||||
| Other Income (Expense) | ||||||||||||||||||||
| Interest income | ||||||||||||||||||||
| Interest (expense) | ( | ( | ( | |||||||||||||||||
| Gain (loss) on derivative contracts | ( | ( | ||||||||||||||||||
Loss on disposal of assets | ( | |||||||||||||||||||
| Other income | ||||||||||||||||||||
| Net Other Income (Expense) | ( | ( | ( | |||||||||||||||||
Income Before Provision for Income Taxes | ||||||||||||||||||||
Provision for Income Taxes | ( | ( | ( | |||||||||||||||||
Net Income | $ | $ | $ | |||||||||||||||||
Basic Earnings per Share | $ | $ | $ | |||||||||||||||||
Diluted Earnings per Share | $ | $ | $ | |||||||||||||||||
The accompanying notes are an integral part of these financial statements.
F-5
| Common Stock | Additional Paid-in Capital | Retained Earnings (Accumulated Deficit) | Total Stockholders' Equity | |||||||||||||||||||||||||||||
| Shares | Amount | |||||||||||||||||||||||||||||||
| Balance, December 31, 2020 | $ | $ | $ | ( | $ | |||||||||||||||||||||||||||
| Common stock and warrants issued for cash, net | — | — | ( | — | ( | |||||||||||||||||||||||||||
| Exercise of pre-funded warrants issued in offering | — | — | ||||||||||||||||||||||||||||||
Exercise of common warrants issued in offering | — | |||||||||||||||||||||||||||||||
Options exercised | — | |||||||||||||||||||||||||||||||
| Restricted stock vested | ( | — | ||||||||||||||||||||||||||||||
Shares to cover tax withholdings for restricted stock vested | ( | ( | — | |||||||||||||||||||||||||||||
Payments to cover tax withholdings for restricted stock vested, net | — | — | ( | — | ( | |||||||||||||||||||||||||||
| Share-based compensation | — | — | — | |||||||||||||||||||||||||||||
Net income | — | — | — | |||||||||||||||||||||||||||||
| Balance, December 31, 2021 | $ | $ | $ | ( | $ | |||||||||||||||||||||||||||
| Exercise of common warrants issued in offering | — | |||||||||||||||||||||||||||||||
| Options exercised | ( | — | ||||||||||||||||||||||||||||||
Shares elected to be withheld for options exercised | ( | ( | — | |||||||||||||||||||||||||||||
| Restricted stock vested | ( | — | ||||||||||||||||||||||||||||||
Shares to cover tax withholdings for restricted stock vested | ( | ( | — | |||||||||||||||||||||||||||||
Payments to cover tax withholdings for restricted stock vested, net | — | — | ( | — | ( | |||||||||||||||||||||||||||
Common stock issuance for Stronghold Acquisition | ||||||||||||||||||||||||||||||||
Conversion of mezzanine preferred shares for Stronghold Acquisition | ||||||||||||||||||||||||||||||||
| Share-based compensation | — | — | — | |||||||||||||||||||||||||||||
Net income | — | — | — | |||||||||||||||||||||||||||||
| Balance, December 31, 2022 | $ | $ | $ | ( | $ | |||||||||||||||||||||||||||
| Exercise of common warrants issued in offering | — | |||||||||||||||||||||||||||||||
Induced exercise of common warrants issued in offering | — | |||||||||||||||||||||||||||||||
| Restricted stock vested | ( | — | ||||||||||||||||||||||||||||||
| Shares to cover tax withholdings for restricted stock vested | ( | ( | — | |||||||||||||||||||||||||||||
Payments to cover tax withholdings for restricted stock vested, net | ( | ( | ||||||||||||||||||||||||||||||
Performance stock vested | ( | — | ||||||||||||||||||||||||||||||
Shares to cover tax withholdings for performance stock vested | ( | ( | — | |||||||||||||||||||||||||||||
| Share-based compensation | ||||||||||||||||||||||||||||||||
| Net income | ||||||||||||||||||||||||||||||||
| Balance, December 31, 2023 | $ | $ | $ | ( | $ | |||||||||||||||||||||||||||
The accompanying notes are an integral part of these financial statements.
F-6
| For the Years Ended December 31, | 2023 | 2022 | 2021 | |||||||||||||||||
| Cash Flows From Operating Activities | ||||||||||||||||||||
Net income | $ | $ | $ | |||||||||||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||||||||||
| Depreciation, depletion and amortization | ||||||||||||||||||||
| Asset retirement obligation accretion | ||||||||||||||||||||
| Amortization of deferred financing costs | ||||||||||||||||||||
| Share-based compensation | ||||||||||||||||||||
| Bad debt expense | ||||||||||||||||||||
| Deferred income tax expense (benefit) | ( | |||||||||||||||||||
| Excess tax expense (benefit) related to share-based compensation | ( | ( | ||||||||||||||||||
| (Gain) loss on derivative contracts | ( | |||||||||||||||||||
Cash paid for derivative settlements, net | ( | ( | ( | |||||||||||||||||
Changes in operating assets and liabilities: | ||||||||||||||||||||
| Accounts receivable | ( | ( | ||||||||||||||||||
| Inventory | ( | |||||||||||||||||||
| Prepaid expenses and other assets | ( | ( | ||||||||||||||||||
| Accounts payable | ( | |||||||||||||||||||
| Settlement of asset retirement obligation | ( | ( | ( | |||||||||||||||||
| Net Cash Provided by Operating Activities | ||||||||||||||||||||
| Cash Flows From Investing Activities | ||||||||||||||||||||
| Payments for the Stronghold Acquisition | ( | ( | ||||||||||||||||||
Payments for the Founders Acquisition | ( | |||||||||||||||||||
| Payments to purchase oil and natural gas properties | ( | ( | ( | |||||||||||||||||
| Payments to develop oil and natural gas properties | ( | ( | ( | |||||||||||||||||
| Payments to acquire or improve fixed assets subject to depreciation | ( | ( | ( | |||||||||||||||||
| Sale of fixed assets subject to depreciation | ||||||||||||||||||||
| Proceeds from divestiture of oil and natural gas properties | ||||||||||||||||||||
Proceeds from sale of Delaware properties | ||||||||||||||||||||
Proceeds from sale of New Mexico properties | ||||||||||||||||||||
Net Cash Used in Investing Activities | ( | ( | ( | |||||||||||||||||
| Cash Flows From Financing Activities | ||||||||||||||||||||
| Proceeds from revolving line of credit | ||||||||||||||||||||
| Payments on revolving line of credit | ( | ( | ( | |||||||||||||||||
| Proceeds from issuance of common stock and warrants | ||||||||||||||||||||
| Proceeds from option exercise | ||||||||||||||||||||
Payments for taxes withheld on vested restricted shares, net | ( | ( | ( | |||||||||||||||||
| Proceeds from notes payable | ||||||||||||||||||||
| Payments on notes payable | ( | ( | ( | |||||||||||||||||
| Payment of deferred financing costs | ( | ( | ( | |||||||||||||||||
| Reduction of financing lease liabilities | ( | ( | ( | |||||||||||||||||
| Net Cash Provided by (Used in) Financing Activities | ( | |||||||||||||||||||
| Net Increase (Decrease) in Cash | ( | ( | ||||||||||||||||||
| Cash at Beginning of Period | ||||||||||||||||||||
| Cash at End of Period | $ | $ | $ | |||||||||||||||||
F-7
| For the Years Ended December 31, | 2023 | 2022 | 2021 | |||||||||||||||||
| Supplemental Cash Flow Information | ||||||||||||||||||||
| Cash paid for interest | $ | $ | $ | |||||||||||||||||
Cash paid for income taxes | ||||||||||||||||||||
| Noncash Investing and Financing Activities | ||||||||||||||||||||
| Asset retirement obligation incurred during development | $ | $ | $ | |||||||||||||||||
| Asset retirement obligation acquired | ||||||||||||||||||||
| Asset retirement obligation revision of estimate | ||||||||||||||||||||
| Asset retirement obligation sold | ( | ( | ||||||||||||||||||
| Operating lease assets obtained in exchange for new operating lease liability | ||||||||||||||||||||
| Operating lease asset revision | ( | |||||||||||||||||||
| Financing lease assets obtained in exchange for new financing lease liability | ||||||||||||||||||||
Change in capitalized expenditures attributable to drilling projects financed through current liabilities | ( | |||||||||||||||||||
| Supplemental Schedule for Founders Acquisition | ||||||||||||||||||||
| Investing Activities - Cash Paid | ||||||||||||||||||||
| Escrow deposit released at closing | $ | $ | $ | |||||||||||||||||
| Closing amount paid to Founders | ||||||||||||||||||||
| Interest from escrow deposit | ||||||||||||||||||||
| Direct transaction costs | ||||||||||||||||||||
| Post-close adjustments | ( | |||||||||||||||||||
Payment of deferred cash payment | ||||||||||||||||||||
| Payments for the Founders Acquisition | $ | $ | $ | |||||||||||||||||
| Investing Activities - Noncash | ||||||||||||||||||||
| Assumption of suspense liability | $ | $ | $ | |||||||||||||||||
| Assumption of asset retirement obligation | ||||||||||||||||||||
| Assumption of ad valorem tax liability | ||||||||||||||||||||
| Deferred cash payment at fair value | ||||||||||||||||||||
| Supplemental Schedule for Stronghold Acquisition | ||||||||||||||||||||
| Investing Activities - Cash Paid | ||||||||||||||||||||
| Cash paid by bank to Stronghold on closing | $ | $ | $ | |||||||||||||||||
| Deposit in escrow | ||||||||||||||||||||
| Direct transaction costs | ||||||||||||||||||||
| Cash paid for realized August oil derivative losses | ||||||||||||||||||||
| Cash paid for inventory and fixed assets acquired | ||||||||||||||||||||
| Cash received for post-close adjustments, net | ( | |||||||||||||||||||
Payment of deferred cash payment | ||||||||||||||||||||
Payment of post-close settlement | ||||||||||||||||||||
| Payments for the Stronghold Acquisition | $ | $ | $ | |||||||||||||||||
| Investing Activities - Noncash | ||||||||||||||||||||
| Assumption of suspense liability | $ | $ | $ | |||||||||||||||||
| Assumption of derivative liabilities | ||||||||||||||||||||
| Assumption of asset retirement obligation | ||||||||||||||||||||
| Deferred cash payment at fair value | ||||||||||||||||||||
| Financing Activities - Noncash | ||||||||||||||||||||
| Common stock issued for acquisition | ||||||||||||||||||||
| Convertible preferred stock issued for acquisition | ||||||||||||||||||||
The accompanying notes are an integral part of these financial statements.
F-8
RING ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
Index to the Notes to the Financial Statements
NOTE 1 — ORGANIZATION, BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization and Nature of Operations – Ring Energy, Inc., a Nevada corporation (“Ring,” “Ring Energy,” the “Company,” “we,” “us,” “our,” or similar terms), is a growth oriented independent oil and natural gas exploration and production company based in The Woodlands, Texas and is engaged in oil and natural gas development, production, acquisition, and exploration activities currently focused in the Permian Basin of Texas. Our drilling operations target the oil and liquids rich producing formations in the Northwest Shelf and the Central Basin Platform, in the Permian Basin in Texas.
Liquidity and Capital Considerations– The Company strives to maintain an adequate liquidity level to address volatility and risk. Sources of liquidity include the Company’s net cash provided by operating activities, cash on hand, available borrowing capacity under its revolving credit facility, and proceeds from sales of non-strategic assets.
While changes in oil and natural gas prices affect the Company’s liquidity, the Company has put in place hedges in seeking to protect a substantial portion of its cash flows from price declines; however, if oil or natural gas prices rapidly deteriorate due to unanticipated economic conditions, this could still have a material adverse effect on the Company’s cash flows.
The Company expects ongoing oil price volatility over an indeterminate term. Extended depressed oil prices have historically had and could have a material adverse impact on the Company’s oil revenue, which is mitigated to some extent by the Company’s hedge contracts. The Company is always mindful of oil price volatility and its impact on our liquidity.
The Company believes that it has the ability to continue to fund its operations and service its debt by using cash flows from operations.
Use of Estimates – The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses during the reporting period. The Company's financial statements are based on a number of significant estimates, including estimates of oil and natural gas reserve quantities, which are the basis for the calculation of depletion and impairment of oil and gas properties. Reserve estimates, by their nature, are inherently imprecise. Actual results could differ from those estimates. Changes in the future estimated oil and natural gas reserves or the estimated future cash flows attributable to the reserves that are utilized for impairment analysis could have a significant impact on the Company's future results of operations.
Fair Value Measurements - Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Financial Accounting Standards Board (“FASB”) has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure
F-9
fair value. This hierarchy consists of three broad levels. Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 are unobservable inputs for an asset or liability.
Fair Values of Financial Instruments – The carrying amounts reported for our revolving line of credit approximate their fair value because the underlying instruments are at interest rates which approximate current market rates. The carrying amounts of accounts receivable and accounts payable and other current assets and liabilities approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities.
Fair Value of Non-financial Assets and Liabilities – The Company also applies fair value accounting guidance to initially, or as events dictate, measure non-financial assets and liabilities such as those obtained through business acquisitions, property and equipment and asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two as considered appropriate based on the circumstances. Under the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and natural gas production or other applicable sales estimates, operational costs and a risk-adjusted discount rate. The Company may use the present value of estimated future cash inflows and/or outflows or third-party offers or prices of comparable assets with consideration of current market conditions to value its non-financial assets and liabilities when circumstances dictate determining fair value is necessary. Given the significance of the unobservable nature of a number of the inputs, these are considered Level 3 on the fair value hierarchy.
Concentration of Credit Risk and Receivables – Financial instruments that potentially subject the Company to a concentration of credit risk consist principally of cash and receivables.
Cash and cash equivalents - The Company has cash in excess of federally insured limits of $46,384 and $3,462,526 as of December 31, 2023 and 2022, respectively. The Company places its cash with a high credit quality financial institution. The Company has not experienced any losses in such accounts and believes it is not exposed to significant credit risk in this area.
Accounts receivable - Substantially all of the Company’s accounts receivable is from purchasers of oil and natural gas. Oil and natural gas sales are generally unsecured. Accounts receivable from purchasers outstanding longer than the contractual payment terms are considered past due. The Company has not had any significant credit losses in the past and believes its accounts receivable are fully collectable. Refer to the "Major Purchasers" section below for detail on purchaser activity for the years ended December 31, 2023, 2022, and 2021.
Production imbalances - The Company accounts for natural gas production imbalances using the sales method, which recognizes revenue on all natural gas sold even though the natural gas volumes sold may be more or less than the Company's ownership entitles it to sell. Liabilities are recorded for imbalances greater than the Company’s proportionate share of remaining estimated natural gas reserves. The Company recorded no imbalances as of December 31, 2023 or 2022.
| For the Years Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Bad debt expense | $ | $ | $ | ||||||||||||||
The following table reflects the Company's joint interest billing receivables and allowance for credit losses as of December 31, 2023 and 2022.
F-10
| 2023 | 2022 | ||||||||||
| Joint interest billing receivables | $ | $ | |||||||||
| Allowance for credit losses | ( | ( | |||||||||
Joint interest billing receivables, net | $ | $ | |||||||||
The reduction of $183,678 in the allowance for credit losses during the year ended December 31, 2023 was primarily due to a clearing of $105,620 in allowances that were associated with the Delaware Basin asset sale.
Inventory - The full balance of the Company's inventory consists of materials and supplies for its operations, with no work in process or finished goods inventory balances. Inventory is added to the books upon the purchase of supplies (inclusive of freight and sales tax costs) to use on well sites, and inventory is reduced by material transfers for inventory usage based on the initial invoiced value. The Company reports the balance of its inventory at the lower of cost or net realizable value. Inventory balances are excluded from the Company's calculation of depletion.
Oil and Natural Gas Properties – The Company uses the full cost method of accounting for oil and natural gas properties. Under this method, all costs (direct and indirect) associated with acquisition, exploration, and development of oil and natural gas properties are capitalized. Costs capitalized include acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties and costs of drilling and equipping productive and non-productive wells. Drilling costs include directly related overhead costs. Capitalized costs are categorized either as being subject to amortization or not subject to amortization. All of the Company’s capitalized costs, excluding inventory, are subject to amortization.
The Company records a liability in the period in which an asset retirement obligation (“ARO”) is incurred, in an amount equal to the discounted estimated fair value of the obligation that is capitalized. Thereafter this liability is accreted up to the final retirement cost. An ARO is a future expenditure related to the disposal or other retirement of certain assets. The Company’s ARO relates to future plugging and abandonment expenses of its oil and natural gas properties and related facilities disposal. Dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs.
All capitalized costs of oil and natural gas properties, including the estimated future costs to develop proved reserves and estimated future costs to plug and abandon wells and costs of site restoration, less the estimated salvage value of equipment associated with the oil and natural gas properties, are amortized on the unit-of-production method using estimates of proved reserves as determined by independent petroleum engineers. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is offset to the capitalized costs to be amortized. The following table shows total depletion and the depletion per barrel-of-oil-equivalent rate, for the years ended December 31, 2023, 2022, and 2021.
| For the Years Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Depletion | $ | $ | $ | ||||||||||||||
| Depletion rate, per barrel-of-oil-equivalent (Boe) | $ | $ | $ | ||||||||||||||
In addition, capitalized costs less accumulated depreciation, depletion and amortization and related deferred income taxes are not allowed to exceed an amount (the full cost ceiling) equal to the sum of:
1)the present value of estimated future net revenues discounted at ten percent computed in compliance with SEC guidelines;
2)plus the cost of properties not being amortized;
3)plus the lower of cost or estimated fair value of unproven properties included in the costs being amortized;
4)less income tax effects related to differences between the book and tax basis of the properties.
F-11
Land, Buildings, Equipment, Software, Leasehold Improvements, Automobiles, Buildings and Structures – Land, buildings, equipment, software, leasehold improvements, automobiles, buildings and structures are carried at historical cost, adjusted for impairment loss and accumulated depreciation (except for land). Historical costs include all direct costs associated with the acquisition of land, buildings, equipment, software, leasehold improvements, automobiles, buildings and structures and placing them in service. Upon sale or abandonment, the cost of the fixed asset(s) and related accumulated depreciation are removed from the accounts and any gain or loss is recognized.
Depreciation of buildings, equipment, software, leasehold improvements, automobiles, buildings and structures is calculated using the straight-line method based upon the following estimated useful lives:
| Leasehold improvements | ||||||||
| Office equipment and software | ||||||||
| Equipment | ||||||||
| Automobiles | ||||||||
Buildings and structures | ||||||||
The following table provides information on the Company's depreciation expense for the years ended December 31, 2023, 2022, and 2021.
| For the Years Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
Depreciation expense | $ | $ | $ | ||||||||||||||
During the year ended December 31, 2023, the Company sold some of its automobiles, and recognized a loss on disposal of $87,128 .
Accounts Payable
The following table summarizes the Company's components of its current accounts payable balance presented in its Balance Sheets at December 31, 2023 and 2022:
| 2023 | 2022 | ||||||||||
Trade accounts payable | $ | $ | |||||||||
| Revenues payable | |||||||||||
| Accrued expenses | |||||||||||
Accounts payable | $ | $ | |||||||||
Trade accounts payable – The following table summarizes the Company's current trade accounts payable at December 31, 2023 and 2022:
| 2023 | 2022 | ||||||||||
| Accounts payable related to vendors | $ | $ | |||||||||
| Other | |||||||||||
Trade accounts payable | $ | $ | |||||||||
Revenues payable – The following table summarizes the Company's current revenues and royalties payable at December 31, 2023 and 2022:
F-12
| 2023 | 2022 | ||||||||||
| Revenue held in suspense | $ | $ | |||||||||
| Revenues and royalties payable | |||||||||||
Revenues payable | $ | $ | |||||||||
Accrued expenses – The following table summarizes the Company's current accrued expenses at December 31, 2023 and 2022:
| 2023 | 2022 | ||||||||||
| Accrued capital expenditures | $ | $ | |||||||||
| Accrued lease operating expenses | |||||||||||
| Accrued interest | |||||||||||
| Accrued general and administrative expense | |||||||||||
| Other | |||||||||||
Accrued expenses | $ | $ | |||||||||
Notes Payable – At the end of May 2023, the Company renewed its control of well, general liability, pollution, umbrella, property, workers' compensation, auto, and D&O (directors and officers) insurance policies, and funded the premiums with a promissory note with a total face value after down payments of $1,565,071 . In November 2023, the Company renewed its cybersecurity insurance policy, and funded the premium with a promissory note with a total face value after down payments of $72,442 . The annual percentage rate (APR) for both notes is 7.08 %. As of December 31, 2023, the notes payable balance included within current liabilities on the balance sheet is $533,734 . The weighted average notes payable balance during the years ended December 31, 2023 and 2022 were $687,456 and $593,766 , respectively. The average interest on the weighted average notes payable balance during the years ended December 31, 2023 and 2022 were 7.23 % and 4.31 %, respectively. The following table shows interest paid related to notes payable for the years ended December 31, 2023, 2022, and 2021. This interest is included within "Interest (expense)" in the Statements of Operations.
| For the Years Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
Interest paid for notes payable | $ | $ | $ | ||||||||||||||
Revenue Recognition – In January 2018, the Company adopted Accounting Standards Update (“ASU”) 2014-09 Revenues from Contracts with Customers (Topic 606) (“ASU 2014-09”). The timing of recognizing revenue from the sale of produced crude oil and natural gas was not changed as a result of adopting ASU 2014-09. The Company predominantly derives its revenue from the sale of produced crude oil and natural gas. The contractual performance obligation is satisfied when the product is delivered to the purchaser. Revenue is recorded in the month the product is delivered to the purchaser. The Company receives payment from one to three months after delivery. The transaction price includes variable consideration as product pricing is based on published market prices and reduced for contract specified differentials (quality, transportation and other variables from benchmark prices). The guidance regarding ASU 2014-09 does not require that the transaction price be fixed or stated in the contract. Estimating the variable consideration does not require significant judgment and Ring engages third party sources to validate the estimates. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration the Company expects to receive in exchange for those products. See "Note 2 — REVENUE RECOGNITION" for additional information.
Income Taxes – Provisions for income taxes are based on taxes payable or refundable for the current year and deferred taxes. Deferred income taxes are provided on differences between the tax basis of assets and liabilities and their carrying amounts in the financial statements, and tax carryforwards. Deferred tax assets and liabilities are included in the financial statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the provision for income taxes.
Since December 31, 2020, the Company determined that a full valuation allowance was necessary due to the Company's assessment that it was more likely than not that it would be unable to obtain the benefits of its deferred tax assets due to the Company’s history of taxable losses. The Company determined that certain existing deferred tax assets would not be offset
F-13
by existing deferred tax liabilities as a result of the 80% limitation on the utilization of net operating losses incurred after 2017. Since 2021, commodity prices increased and the Company continues to project positive pre-tax book income. As of June 30, 2023, the Company was no longer in a cumulative loss position. As a result, future forecasted pre-tax book income was considered as positive evidence in assessing the valuation allowance. Based on the change in judgment on the realizability of the related federal deferred tax assets in future years, the Company released $24.2 million of valuation allowance as a benefit during the year ended December 31, 2023. The Company recorded the following federal and state income tax benefits (provisions) for the years ended December 31, 2023, 2022, and 2021.
| For the Years Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Deferred federal income tax benefit (provision) | $ | $ | ( | $ | |||||||||||||
| Current state income tax provision | ( | ||||||||||||||||
| Deferred state income tax provision | ( | ( | ( | ||||||||||||||
| Provision for Income Taxes | $ | ( | $ | ( | $ | ( | |||||||||||
The Company’s overall effective tax rates (calculated as Provision for Income Taxes divided by Income Before Provision for Income Taxes) for the years ended December 31, 2023, 2022, and 2021 were as follows.
| For the Years Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
Effective tax rate | % | % | % | ||||||||||||||
These rates were primarily impacted by the release of valuation allowance on the Company's federal net deferred tax asset. A tax benefit of $24.2 million was recorded in the year ended December 31, 2023.
Accounting for Uncertainty in Income Taxes – In accordance with GAAP, the Company has analyzed its filing positions in all jurisdictions where it is required to file income tax returns for the open tax years. The Company has identified its federal income tax return and its franchise tax return in Texas in which it operates as a “major” tax jurisdiction. The Company’s federal income tax returns for the years ended December 31, 2019 and after remain subject to examination. The Company’s federal income tax returns for the years ended December 31, 2007 and after remain subject to examination to the extent of the net operating loss (NOL) carryforwards. The Company’s franchise tax returns in Texas remain subject to examination for 2018 and after. The Company currently believes that all significant filing positions are highly certain and that all of its significant income tax filing positions and deductions would be sustained upon audit. Therefore, the Company has no significant reserves for uncertain tax positions and no adjustments to such reserves were required by GAAP. No interest or penalties have been levied against the Company and none are anticipated; therefore, no interest or penalty has been included in our provision for income taxes in the Statements of Operations.
Three-Stream Reporting - Beginning July 1, 2022, the Company began reporting volumes and revenues on a three-stream basis, separately reporting crude oil, natural gas, and NGL sales. For periods prior to July 1, 2022, sales and reserve volumes, prices, and revenues for NGLs were presented with natural gas. This represents a change in our accounting and reporting presentation necessitated by a change in the underlying facts and circumstances surrounding the Stronghold Acquisition, as Stronghold has historically reported its revenues on a three-stream basis. As clarified in the interpretive guidance of ASC 250, such changes should not be applied on a retrospective basis. Accordingly, we began reporting on a three-stream basis prospectively, beginning July 1, 2022. See Note 5 — ACQUISITIONS & DIVESTITURES for a discussion of the Stronghold Acquisition.
Leases - The Company accounts for its leases in accordance with ASU 2016-02, Leases (Topic 842), effective January 1, 2019. The Company made accounting policy elections to not capitalize leases with a lease term of twelve months or less (i.e. short-term leases) and to not separate lease and non-lease components for all asset classes. The Company also elected to adopt the package of practical expedients within ASU 2016-02 that allows an entity to not reassess prior to the effective date (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases, or (iii) initial direct costs for any existing leases and the practical expedient regarding land easements that exist prior to the adoption of ASU 2016-02. The Company did not elect the practical expedient of hindsight when determining the lease term of existing contracts at the effective date.
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Earnings (Loss) Per Share – Basic earnings (loss) per share is computed by dividing net income (loss) by the weighted-average number of common shares outstanding during the year. Diluted earnings (loss) per share are calculated to give effect to potentially issuable dilutive common shares.
Major Purchasers – During the year ended December 31, 2023, sales to three purchasers represented 66 %, 12 %, and 10 %, respectively, of total oil, natural gas, and natural gas liquids sales. As of December 31, 2023, sales outstanding from these three purchasers represented 65 %, 11 %, and 8 %, respectively, of accounts receivable. During the year ended December 31, 2022, sales to three purchasers represented 68 %, 13 %, and 5 %, respectively, of total oil, natural gas and natural gas liquids sales. As of December 31, 2022, sales outstanding from these three purchasers represented 69 %, 7 %, and 10 %, respectively, of accounts receivable. During the year ended December 31, 2021, sales to three purchasers represented 76 %, 7 %, and 6 %, respectively, of total oil and natural gas sales. As of December 31, 2021, sales outstanding from these three purchasers represented 75 %, 8 %, and 4 %, respectively, of accounts receivable.
Share-Based Compensation to Non-Employees – The Company accounts for share-based compensation issued to non-employees as either the fair value of the consideration received or the fair value of the equity instruments issued, whichever is more reliably measurable. The measurement date for these issuances is the earlier of (i) the date at which a commitment for performance by the recipient to earn the equity instruments is reached or (ii) the date at which the recipient’s performance is complete.
Share-Based Compensation - The following table summarizes the Company's share-based compensation, included with General and administrative expense within our Statements of Operations, incurred for the years ended December 31, 2023, 2022, and 2021.
| For the Years Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
Share-based compensation | $ | $ | $ | ||||||||||||||
Derivative Instruments and Hedging Activities – The Company periodically enters into derivative contracts to manage its exposure to commodity price risk. These derivative contracts, which are generally placed with major financial institutions, may take the form of forward contracts, futures contracts, swaps or options. The oil and gas reference prices upon which the commodity derivative contracts are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company for its oil and natural gas production.
As the Company has not designated its derivative instruments as hedges for accounting purposes, any gains or losses resulting from changes in fair value of outstanding derivative financial instruments and from the settlement of derivative financial instruments are recognized in earnings and included as a component of other income (expense) in the Statements of Operations.
When applicable, the Company records all derivative instruments, other than those that meet the normal purchases and sales exception, on the balance sheet as either an asset or liability measured at fair value. Changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. Refer to "Note 7 — DERIVATIVE FINANCIAL INSTRUMENTS" for additional information.
The Company uses the indirect method of reporting operating cash flows within the Statements of Cash Flows. Accordingly, the non-cash, unrealized gains and losses from derivative contracts are reflected as an adjustment to arrive at Net cash provided by operating activities. The total Gain (loss) on derivative contracts less the Cash received (paid) for derivative settlements, net represents the unrealized (mark to market) gain or loss on derivative contracts.
Recently Adopted Accounting Pronouncements – In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”). ASU
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2018-13 eliminates, adds and modifies certain disclosure requirements for fair value measurement. ASU 2018-13 became effective for annual and interim periods beginning January 1, 2020. ASU 2018-13 requires that the additional disclosure requirements be adopted using a retrospective approach. The adoption of this guidance did not have a material impact on the Company’s financial statements.
In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, followed by other related ASUs that provided targeted improvements (collectively “ASU 2016-13”). ASU 2016-13 provides financial statement users with more decision-useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. The guidance is to be applied using a modified retrospective method and became effective for fiscal years beginning after December 15, 2019. The Company adopted ASU 2016-13 on January 1, 2020. The adoption of ASU 2016-13 did not have a material impact to the Company’s financial statements or disclosures.
In December 2019, the FASB released ASU No. 2019-12 (“ASU 2019-12”), Income Taxes (Topic 740) – Simplifying the Accounting for Income Taxes, which removes certain exceptions for recognizing deferred taxes for investments, performing intraperiod allocation and calculating income taxes in interim periods. The ASU also adds guidance to reduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and allocating taxes to members of a consolidated group. The amended standard became effective for fiscal years beginning after December 15, 2020. The adoption of ASU 2019-12 did not have a material impact to the Company’s financial statements or disclosures.
In October 2020, the FASB issued ASU 2020-10, Codification Improvements ("ASU 2020-10"), which clarifies or improves disclosure requirements for various topics to align with SEC regulations. This update was effective for the Company beginning in the first quarter of 2021 and was applied retrospectively. The adoption and implementation of this ASU did not have a material impact on the Company’s financial statements.
In August 2020, the FASB issued ASU No. 2020-06, “Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40)” (“ASU 2020-06”). ASU 2020-06 was issued to reduce the complexity associated with accounting for certain financial instruments with characteristics of liabilities and equity. ASU 2020-06 became effective for fiscal years beginning after December 15, 2021. The Company adopted ASU 2020-06 effective January 1, 2022. The adoption and implementation of this ASU did not have a material impact on the Company’s financial statements.
In October 2021, the FASB issued ASU 2021-08, "Business Combinations (Topic 805) – Accounting for Contract Assets and Contract Liabilities from Contracts with Customers” ("ASU 2021-08"). This update requires the acquirer in a business combination to record contract asset and liabilities following Topic 606 – “Revenue from Contracts with Customers” at acquisition as if it had originated the contract, rather than at fair value. This update became effective for public business entities beginning after December 15, 2022. The Company adopted ASU 2021-08 effective January 1, 2023. The adoption and implementation of this ASU did not have a material impact on the Company’s financial statements, as its revenue is recognized when control transfers to the purchaser at the point of delivery, and no contract liabilities or assets are recognized in accordance with ASC 606.
In July 2023, the FASB issued ASU 2023-03, Presentation of Financial Statements (Topic 205), Income Statement - Reporting Comprehensive Income (Topic 220), Distinguishing Liabilities from Equity (Topic 480), Equity (Topic 505), and Compensation - Stock Compensation (Topic 718): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 120, SEC Staff Announcement at the March 24, 2022 EITF Meeting, and Staff Accounting Bulletin Topic 6.B, Accounting Series Release 280 - General Revision of Regulation S-X: Income or Loss Applicable to Common Stock. The ASU provided updated views from the SEC Staff on employee and non-employee share-based payment accounting, including guidance related to spring-loaded awards. As the ASU did not provide any new ASC guidance, and there was no transition or effective date provided, the Company adopted this standard upon issuance, and the adoption did not have a material impact on the Company's financial statements.
Recent Accounting Pronouncements – In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”), which provided optional expedients and exceptions for applying GAAP to contract modifications and hedging relationships, subject to meeting certain criteria, that referenced LIBOR ("London Inter-Bank Offered Rate") or another rate. ASU 2020-04 was in effect through December 31, 2022. In January 2021, the FASB issued ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), to provide clarifying guidance regarding the scope of Topic 848. ASU 2020-04 was issued to provide optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the
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effects of) reference rate reform on financial reporting. In December 2022, the FASB issued ASU 2022-06, "Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848" ("ASU 2022-06"), which defers the sunset date of Topic 848 from December 31, 2022 to December 31, 2024. Beginning August 31, 2022, under the Company's Second Amended and Restated Credit Agreement, the Company's interest rates were transitioned from the LIBOR to the SOFR reference rate. At this time, the Company does not plan to enter into additional contracts using LIBOR as a reference rate.
In October 2023, the FASB issued ASU 2023-06, "Disclosure Improvements: Codification Amendments in Response to the SEC's Disclosure Update and Simplification Initiative." This update modifies the disclosure or presentation requirements of a variety of Topics in the Codification, which should be applied prospectively. For instance, within ASC 230-10 Statement of Cash Flows - Overall, the amendment requires an accounting policy disclosure in annual periods of where cash flows associated with their derivative instruments and their related gains and losses are presented in the statement of cash flows. Additionally, within ASC 260-10 Earnings Per Share - Overall, the amendment requires disclosure of the methods used in the diluted earnings-per-share computation for each dilutive security and clarifies that certain disclosures should be made during interim periods. The Company is currently assessing the impact of this update on its financial statements and related notes. If by June 30, 2027, the SEC has not removed the applicable requirement from Regulation S-X or Regulation S-K, the pending content of the related amendment will be removed from the Codification and will not become effective for any entity.
In November 2023, the FASB issued ASU 2023-07 "Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures." This update requires that a public entity with multiple reportable segments disclose significant segment expenses that are regularly provided to the chief operating decision maker ("CODM"), as well as other segment items that are included in the calculation of segment profit or loss. A public entity will also be required to disclose all annual disclosures about a reportable segment's profit or loss currently required by Topic 280 in interim periods. Although a public entity is permitted to disclose multiple measures of a segment's profit or loss, at least one of the reported segment profit or loss measures should be consistent with the measurement principles used in measuring the corresponding amounts of the public entity's consolidated financial statements. Further, a public entity must disclose the title and position of the CODM as well as how the CODM uses the reported measure(s) of segment profit or loss in assessing segment performance and deciding how to allocate resources. Finally, the update requires that a public entity that has a single reportable segment provide all the disclosures required by the amendments in this update and all existing segment disclosures in Topic 280. The Company is currently assessing the impact of adopting this new guidance on its financial disclosures. The amendments in this update are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024.
NOTE 2 — REVENUE RECOGNITION
The Company predominantly derives its revenue from the sale of produced crude oil, natural gas, and NGLs. The contractual performance obligation is satisfied when the product is delivered to the purchaser. Revenue is recorded in the
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month the product is delivered to the purchaser. The Company receives payment from one to three months after delivery. The Company has utilized the practical expedient in Accounting Standards Codification ("ASC") 606-10-50-14, which states an entity is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company’s sales contracts, each unit of production delivered to a purchaser represents a separate performance obligation, therefore, future volumes to be delivered are wholly unsatisfied and disclosure of transaction price allocated to remaining performance obligation is not required. The transaction price includes variable consideration as product pricing is based on published market prices and adjusted for contract specified differentials such as quality, energy content, and transportation. The guidance does not require that the transaction price be fixed or stated in the contract. Estimating the variable consideration does not require significant judgment and the Company engages third party sources to validate the estimates. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration the Company expects to receive in exchange for those products.
Oil sales
Under the Company’s oil sales contracts, the Company sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue at the net price received when control transfers to the purchaser at the point of delivery and it is probable the Company will collect the consideration it is entitled to receive.
Natural gas and NGL sales
Under the Company’s natural gas sales processing contracts for its Central Basin Platform properties and a portion of its Northwest Shelf assets, the Company delivers unprocessed natural gas to a midstream processing entity at the wellhead. The midstream processing entity obtains control of the natural gas and NGLs at the wellhead. The midstream processing entity gathers and processes the natural gas and NGLs and remits proceeds to the Company for the resulting sale of natural gas and NGLs. Under these processing agreements, the Company recognizes revenue when control transfers to the purchaser at the point of delivery and it is probable the Company will collect the consideration it is entitled to receive. As such, the Company accounts for any fees and deductions as a reduction of the transaction price.
Until April 30, 2022, under the Company's natural gas sales processing contracts for the bulk of our Northwest Shelf assets, the Company delivered unprocessed natural gas to a midstream processing entity at the wellhead. However, the Company maintained ownership of the gas through processing and received proceeds from the marketing of the resulting products. Under this processing agreement, the Company recognized the fees associated with the processing as an expense rather than netting these costs against Oil and Natural Gas Revenues in the Statements of Operations. Beginning May 1, 2022, these contracts were combined into one contract, and it was modified so that the Company no longer maintained ownership of the gas through processing. Accordingly, the Company from that point on accounts for any such fees and deductions as a reduction of the transaction price. There remains only one contract with a natural gas processing entity in place where point of control of gas dictates requiring the fees be recorded as an expense.
Disaggregation of Revenue. The following table presents revenues disaggregated by product:
| For the years ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Oil, Natural Gas, and Natural Gas Liquids Revenues | |||||||||||||||||
| Oil | $ | $ | $ | ||||||||||||||
Natural gas (1) | |||||||||||||||||
Natural gas liquids (1) | |||||||||||||||||
| Total oil, natural gas, and natural gas liquids revenues | $ | $ | $ | ||||||||||||||
(1) Beginning on July 1, 2022, the Company began reporting volumes and revenues on a three-stream basis, separately reporting crude oil, natural gas, and NGL sales. For periods prior to July 1, 2022, sales revenues for NGLs were presented with natural gas.
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NOTE 3 — LEASES
The Company has operating leases for its offices in Midland, Texas and The Woodlands, Texas. The Midland office is under a five-year lease which began January 1, 2021. The Midland office lease was amended effective October 1, 2022, with the revised five-year lease ending September 30, 2027. Beginning January 15, 2021, the Company entered into a five-and-a-half-year sub-lease for office space in The Woodlands, Texas; however, effective as of May 31, 2023, The Woodlands office sub-lease was terminated. On May 9, 2023, the Company entered into a 71-month (five years and 11-month) new lease for a larger amount of office space in The Woodlands, Texas. At the time of the new lease commencement, the additional office space that was added was under construction and until completed, the rental obligation for this space had not yet commenced, because the Company did not have control of the additional office space in accordance with ASC 842-40-55-5. On September 27, 2023, the Company provided a certificate of acceptance of premises to the lessor of the additional office space, and accordingly, the future payments for this space are included along with the other operating leases, reflected in the future lease payments schedule below.
During the first quarter of 2021, the Company had an operating lease with Arenaco, LLC for its Tulsa, Oklahoma office. The Tulsa lease was terminated as of March 31, 2021, with payments made until the end of February 2021. Refer to "Note 13 — RELATED PARTY TRANSACTIONS" for further details.
The Company has month to month leases for office equipment and compressors used in its operations on which the Company has elected to apply ASU 2016-02 (i.e. to not capitalize). The office equipment and compressors are not subject to ASU 2016-02 based on the agreement and nature of use. These leases are for terms that are less than 12 months and the Company does not intend to continue to lease this equipment for more than 12 months. The lease costs associated with these leases is reflected in the short-term lease costs within Lease operating expenses, shown below.
The Company has financing leases for vehicles. These leases have a term of 36 months at the end of which the Company owns the vehicles. These vehicles are generally sold at the end of their term and the proceeds applied to a new vehicle.
Future lease payments associated with these operating and financing leases as of December 31, 2023 are as follows:
| 2024 | 2025 | 2026 | 2027 | 2028 | Thereafter | ||||||||||||||||||||||||||||||
Operating lease payments (1) | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||
Financing lease payments (2) | |||||||||||||||||||||||||||||||||||
(1)The weighted average annual discount rate as of December 31, 2023 for operating leases was 4.50 %. Based on this rate, the future lease payments above include imputed interest of $277,833 . The weighted average remaining term of operating leases was 4.32 years.
The following table represents a reconciliation between the undiscounted future cash flows in the table above and the operating and financing lease liabilities disclosed in the Balance Sheets:
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| As of December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| Operating lease liability, current portion | |||||||||||
| Operating lease liability, non-current portion | |||||||||||
| Operating lease liability, total | |||||||||||
| Total undiscounted future cash flows (sum of future operating lease payments) | |||||||||||
| Imputed interest | |||||||||||
| Undiscounted future cash flows less imputed interest | |||||||||||
| Financing lease liability, current portion | |||||||||||
| Financing lease liability, non-current portion | |||||||||||
| Financing lease liability, total | |||||||||||
| Total undiscounted future cash flows (sum of future financing lease payments) | |||||||||||
| Imputed interest | |||||||||||
| Undiscounted future cash flows less imputed interest | |||||||||||
The following table provides supplemental information regarding lease costs in the Statements of Operations:
| 2023 | |||||
| Operating lease costs | $ | ||||
Short-term lease costs (1) | $ | ||||
| Financing lease costs: | |||||
Amortization of financing lease assets (2) | $ | ||||
Interest on financing lease liabilities (3) | $ | ||||
(1)Amount included in Lease operating expenses
(2)Amount included in Depreciation, depletion and amortization
(3)Amount included in Interest (expense)
NOTE 4 — EARNINGS PER SHARE INFORMATION
The following table presents the calculation of the Company's basic and diluted earnings per share for the years ended December 31, 2023, 2022 and 2021. For all dilutive securities, the treasury stock method of calculating the incremental shares is applied.
| For the years ended December 31, | 2023 | 2022 | 2021 | |||||||||||||||||
| Net Income | $ | $ | $ | |||||||||||||||||
| Basic Weighted-Average Shares Outstanding | ||||||||||||||||||||
| Effect of dilutive securities: | ||||||||||||||||||||
| Stock options | ||||||||||||||||||||
| Restricted stock units | ||||||||||||||||||||
| Performance stock units | ||||||||||||||||||||
| Common warrants | ||||||||||||||||||||
| Diluted Weighted-Average Shares Outstanding | ||||||||||||||||||||
| Basic Earnings per Share | $ | $ | $ | |||||||||||||||||
| Diluted Earnings per Share | $ | $ | $ | |||||||||||||||||
The following table presents the securities which were excluded from the Company's computation of diluted earnings (loss) per share for the years ended December 31, 2023, 2022 and 2021, as their effect would have been anti-dilutive.
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| 2023 | 2022 | 2021 | ||||||||||||||||||
| Antidilutive securities: | ||||||||||||||||||||
| Stock options to purchase common stock | ||||||||||||||||||||
| Unvested restricted stock units | ||||||||||||||||||||
| Unvested performance stock units | ||||||||||||||||||||
NOTE 5 — ACQUISITIONS & DIVESTITURES
Andrews County Sale and Exchange
The Company entered into a Purchase, Sale and Exchange Agreement effective January 1, 2021, with an unrelated party, covering the sale and exchange of certain oil and gas interests in Andrews County, Texas. Upon closing, the Company received cash consideration of $2,000,000 and reduced the Company’s asset retirement obligations by $2,934,126 for the properties sold and added $662,705 of asset retirement obligations for the wells acquired.
Stronghold Acquisition
On July 1, 2022, Ring, as buyer, 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”), as seller, entered into a purchase and sale agreement (the “Purchase Agreement”). Pursuant to the Purchase Agreement, Ring acquired (the “Stronghold Acquisition”) interests in oil and gas leases and related property of Stronghold consisting of approximately 37,000 net acres located in the Central Basin Platform of the Texas Permian Basin. On August 31, 2022, Ring completed the Stronghold Acquisition.
The fair value of consideration paid to Stronghold was approximately $394.0 million, of which $165.9 million, net of customary purchase price adjustments, was paid in cash at closing, $15.0 million was payable in cash after the six-month anniversary of the closing date of the Stronghold Acquisition. Shortly after closing, approximately $4.5 million was paid for inventory and vehicles and approximately $1.8 million was paid for August oil derivative settlements for certain novated hedges. The cash portion of the consideration was funded primarily from borrowings under a new fully committed revolving credit facility (the “Credit Facility”) underwritten by Truist Securities, Citizens Bank, N.A., KeyBanc Capital Markets Inc., and Mizuho Bank, Ltd. The borrowing base of the $1.0 billion Credit Facility was increased from $350.0 million to $600 million at the closing of the Stronghold Acquisition. The remaining consideration consisted of 21,339,986 shares of Ring common stock and 153,176 shares of newly created Series A Convertible Preferred Stock, par value $0.001 (“Preferred Stock”) which was converted into 42,548,892 shares of common stock on October 27, 2022. Please see "Note 11 — STOCKHOLDERS' EQUITY" for further discussion. In addition, Ring assumed $24.8 million of derivative liabilities, $1.7 million of items in suspense and $14.5 million in asset retirement obligations.
The Stronghold Acquisition was accounted for as an asset acquisition in accordance with ASC Topic 805 - Business Combinations. The fair value of the consideration paid by Ring and allocation of that amount to the underlying assets acquired, on a relative fair value basis, was recorded on Ring’s books as of the date of the closing of the Stronghold Acquisition. Additionally, costs directly related to the Stronghold Acquisition were capitalized as a component of the purchase price. Determining the fair value of the assets and liabilities acquired required judgment and certain assumptions to be made, the most significant of these being related to the valuation of Stronghold’s oil and gas properties. The inputs and assumptions related to the oil and gas properties were categorized as level 3 in the fair value hierarchy.
The following table represents the final allocation of the total cost of the Stronghold Acquisition to the assets acquired and liabilities assumed as of the Stronghold Acquisition date:
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| Consideration: | |||||
| Shares of Common Stock issued | |||||
| Common Stock price as of August 31, 2022 | $ | ||||
| Common Stock Consideration | $ | ||||
| Shares of Preferred Stock issued | |||||
| Aggregate Liquidation Preference | $ | ||||
| Conversion Price | $ | ||||
| As-Converted Shares of Common Stock | |||||
| Common Stock Price as of August 31, 2022 | $ | ||||
| Preferred Stock Consideration | $ | ||||
| Cash consideration: | |||||
| Closing amount paid to Stronghold | |||||
| Escrow deposit paid | |||||
| Cash paid for inventory and fixed assets | |||||
| Cash paid for realized losses on August oil derivatives | |||||
| Cash received for post-close adjustments, net | ( | ||||
| Total cash consideration | |||||
| Fair value of deferred payment liability | |||||
| Post-close settlement to be paid to Stronghold | |||||
| Fair value of consideration paid to seller | |||||
| Direct transaction costs | |||||
| Total consideration | $ | ||||
| Fair value of assets acquired: | |||||
| Oil and natural gas properties | |||||
| Inventory and fixed assets | |||||
| Amount attributable to assets acquired | $ | ||||
| Fair value of liabilities assumed: | |||||
| Suspense liability | |||||
| Derivative liabilities, marked to market | |||||
| Asset retirement obligations | |||||
| Amount attributable to liabilities assumed | $ | ||||
| Net assets acquired | $ | ||||
Approximately $40.4 million of revenues and $13.6 million of direct operating expenses attributed to the Stronghold Acquisition were included in the Company’s Statements of Operations for the period from September 1, 2022 through December 31, 2022.
Delaware Basin Divestiture
On May 11, 2023, the Company completed the divestiture of its Delaware Basin assets to an unaffiliated party for $8.3 million. The sale had an effective date of March 1, 2023. The final cash consideration was approximately $7.6 million. As part of the divestiture, the buyer assumed an asset retirement obligation balance of approximately $2.3 million.
Founders Acquisition
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On July 10, 2023, the Company, as buyer, and Founders Oil & Gas IV, LLC (“Founders”), as seller, entered into an Asset Purchase Agreement (the “Founders Purchase Agreement”). Pursuant to the closing of the Purchase Agreement, on August 15, 2023 the Company acquired (the “Founders Acquisition”) interests in oil and gas leases and related property of Founders located in the Central Basin Platform of the Texas Permian Basin in Ector County, Texas, for a purchase price (the “Purchase Price”) of (i) a cash deposit of $7.5 million paid on July 11, 2023 into a third-party escrow account as a deposit pursuant to the Founders Purchase Agreement, (ii) approximately $42.5 million in cash paid on the closing date, net of approximately $10 million of preliminary and customary purchase price adjustments with an effective date of April 1, 2023, and (iii) a deferred cash payment of approximately $11.9 million paid on December 18, 2023, net of customary purchase price adjustments.
The Founders Acquisition has been accounted for as an asset acquisition in accordance with ASC 805. The fair value of the consideration paid by Ring and allocation of that amount to the underlying assets acquired, on a relative fair value basis, was recorded on Ring’s books as of the date of the closing of the Founders Acquisition. Additionally, costs directly related to the Founders Acquisition were capitalized as a component of the purchase price. Determining the fair value of the assets and liabilities acquired required judgment and certain assumptions to be made, the most significant of these being related to the valuation of Founder’s oil and gas properties. The inputs and assumptions related to the oil and gas properties are categorized as level 3 in the fair value hierarchy.
The following table represents the final allocation of the total cost of the Founders Acquisition to the assets acquired and liabilities assumed as of the Founders Acquisition date:
| Consideration: | ||||||||
| Cash consideration | ||||||||
| Escrow deposit released at closing | $ | |||||||
| Closing amount paid to Founders | ||||||||
| Interest from escrow deposit | ||||||||
| Fair value of deferred payment liability | ||||||||
| Post-close adjustments | ( | |||||||
| Total cash consideration | $ | |||||||
| Direct transaction costs | ||||||||
| Total consideration | $ | |||||||
| Fair value of assets acquired: | ||||||||
| Oil and natural gas properties | $ | |||||||
| Amount attributable to assets acquired | $ | |||||||
| Fair value of liabilities assumed: | ||||||||
| Suspense liability | $ | |||||||
| Asset retirement obligations | ||||||||
| Ad valorem tax liability | ||||||||
| Amount attributable to liabilities assumed | $ | |||||||
| Net assets acquired | $ | |||||||
Approximately $18.0 million of revenues and $5.0 million of direct operating expenses attributed to the Founders Acquisition are included in the Company’s Statements of Operations for the period from August 16, 2023 through December 31, 2023.
New Mexico Divestiture
On September 27, 2023, the Company completed the divestiture of its operated New Mexico assets to an unaffiliated party for $4.5 million, resulting in preliminary cash consideration of approximately $3.7 million, subject to customary final purchase price adjustments. The sale had an effective date of June 1, 2023. As part of the divestiture, the buyer assumed an asset retirement obligation balance of approximately $2.4 million.
F-23
Gaines County Texas Sale
On December 29, 2023, the Company completed the sale of specified oil and gas properties within Gaines County, Texas to an unaffiliated party for $1.5 million, which resulted in cash proceeds of $1.4 million, net of $0.1 million in commission fees. The sale had an effective date of December 1, 2023. As part of the sale, the buyer assumed an asset retirement obligation balance of approximately $0.5 million.
NOTE 6 — OIL AND NATURAL GAS PRODUCING ACTIVITIES
Set forth below is certain information regarding the aggregate capitalized costs of oil and natural gas properties and costs incurred by the Company for its oil and natural gas property acquisitions, development and exploration activities:
Capitalized Costs
| As of December 31, | 2023 | 2022 | ||||||||||||
| Oil and natural gas properties, full cost method | ||||||||||||||
Proved properties | ||||||||||||||
Unproved properties | ||||||||||||||
Total oil and natural gas properties, full cost method | ||||||||||||||
Accumulated depletion of oil and natural gas properties | ( | ( | ||||||||||||
Net oil and natural gas properties capitalized | $ | $ | ||||||||||||
Costs Incurred in Oil and Gas Producing Activities
| For the years Ended December 31, | 2023 | 2022 | 2021 | |||||||||||||||||
Payments to acquire oil and natural gas properties | $ | $ | $ | |||||||||||||||||
Payments to explore oil and natural gas properties | ||||||||||||||||||||
| Payments to develop oil and natural gas properties | ||||||||||||||||||||
Total costs incurred | $ | $ | $ | |||||||||||||||||
NOTE 7 — DERIVATIVE FINANCIAL INSTRUMENTS
The Company is exposed to fluctuations in crude oil and natural gas prices on its production. It utilizes derivative strategies that consist of either a single derivative instrument or a combination of instruments to manage the variability in cash flows associated with the forecasted sale of our future domestic oil and natural gas production. While the use of derivative instruments may limit or partially reduce the downside risk of adverse commodity price movements, their use also may limit future income from favorable commodity price movements.
From time to time, the Company enters into derivative contracts to protect the Company’s cash flow from price fluctuation and maintain its capital programs. The Company has historically used costless collars, deferred premium puts, or swaps for this purpose. Oil derivative contracts are based on WTI crude oil prices and natural gas contacts are based on the Henry Hub. A “costless collar” is the combination of two options, a put option (floor) and call option (ceiling) with the options structured so that the premium paid for the put option will be offset by the premium received from selling the call option. Similar to costless collars, there is no cost to enter into the swap contracts. A deferred premium put contract has the premium established upon entering the contract, and due upon settlement of the contract.
The use of derivative transactions involves the risk that the counterparties, which generally are financial institutions, will be unable to meet the financial terms of such transactions. All of our derivative contracts are with lenders under our Credit Facility. Non-performance risk is incorporated in the discount rate by adding the quoted bank (counterparty) credit default swap (CDS) rates to the risk free rate. Although the counterparties hold the right to offset (i.e. netting) the settlement amounts with the Company, in accordance with ASC 815-10-50-4B, the Company classifies the fair value of all its derivative positions on a gross basis in its Balance Sheets.
F-24
The Company’s derivative financial instruments are recorded at fair value and included as either assets or liabilities in the accompanying Balance Sheets. The Company has not designated its derivative instruments as hedges for accounting purposes, and, as a result, any gains or losses resulting from changes in fair value of outstanding derivative financial instruments and from the settlement of derivative financial instruments are recognized in earnings and included as a component of "Other Income (Expense)" under the heading "Gain (loss) on derivative contracts" in the accompanying Statements of Operations.
The following presents the impact of the Company’s contracts on its Balance Sheets for the periods indicated.
| As of December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| Commodity derivative instruments, marked to market: | |||||||||||
| Derivative assets, current | |||||||||||
| Discounted deferred premiums | ( | ( | |||||||||
| Derivatives assets, current, net of premiums | $ | $ | |||||||||
| Derivative assets, noncurrent | |||||||||||
| Discounted deferred premiums | ( | ||||||||||
| Derivative assets, noncurrent, net of premiums | $ | $ | |||||||||
| Derivative liabilities, current | $ | $ | |||||||||
| Derivative liabilities, noncurrent | $ | $ | |||||||||
The components of “Gain (loss) on derivative contracts” from the Statements of Operations are as follows for the respective periods:
| For the years ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Oil derivatives: | |||||||||||||||||
Realized loss on oil derivatives | $ | ( | $ | ( | $ | ( | |||||||||||
| Unrealized gain (loss) on oil derivatives | ( | ||||||||||||||||
Loss on oil derivatives | $ | ( | $ | ( | $ | ( | |||||||||||
| Natural gas derivatives: | |||||||||||||||||
| Realized gain (loss) on natural gas derivatives | ( | ||||||||||||||||
| Unrealized gain (loss) on natural gas derivatives | ( | ||||||||||||||||
| Gain (loss) on natural gas derivatives | $ | $ | ( | $ | ( | ||||||||||||
| Gain (loss) on derivative contracts | $ | $ | ( | $ | ( | ||||||||||||
The components of “Cash (paid) received for derivative settlements, net” within the Statements of Cash Flows are as follows for the respective periods:
F-25
| For the years ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Cash flows from operating activities | |||||||||||||||||
Cash paid for oil derivatives | $ | ( | $ | ( | $ | ( | |||||||||||
| Cash (paid) received on natural gas derivatives | ( | ||||||||||||||||
| Cash paid for derivative settlements, net | $ | ( | $ | ( | $ | ( | |||||||||||
The following tables reflect the details of current derivative contracts as of December 31, 2023 (Quantities are in barrels (Bbl) for the oil derivative contracts and in million British thermal units (MMBtu) for the natural gas derivative contracts):
| Oil Hedges (WTI) | |||||||||||||||||||||||||||||||||||||||||||||||
Q1 2024 | Q2 2024 | Q3 2024 | Q4 2024 | Q1 2025 | Q2 2025 | Q3 2025 | Q4 2025 | ||||||||||||||||||||||||||||||||||||||||
| Swaps: | |||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (Bbl) | |||||||||||||||||||||||||||||||||||||||||||||||
| Weighted average swap price | $ | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||
| Deferred premium puts: | |||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (Bbl) | |||||||||||||||||||||||||||||||||||||||||||||||
| Weighted average strike price | $ | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||
| Weighted average deferred premium price | $ | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||
| Two-way collars: | |||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (Bbl) | |||||||||||||||||||||||||||||||||||||||||||||||
| Weighted average put price | $ | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||
| Weighted average call price | $ | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||
| Gas Hedges (Henry Hub) | |||||||||||||||||||||||||||||||||||||||||||||||
Q1 2024 | Q2 2024 | Q3 2024 | Q4 2024 | Q1 2025 | Q2 2025 | Q3 2025 | Q4 2025 | ||||||||||||||||||||||||||||||||||||||||
| NYMEX Swaps: | |||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (MMBtu) | |||||||||||||||||||||||||||||||||||||||||||||||
| Weighted average swap price | $ | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||
Two-way collars: | |||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (MMBtu) | |||||||||||||||||||||||||||||||||||||||||||||||
| Weighted average put price | $ | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||
| Weighted average call price | $ | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||
| Oil Hedges (basis differential) | |||||||||||||||||||||||||||||||||||||||||||||||
Q1 2024 | Q2 2024 | Q3 2024 | Q4 2024 | Q1 2025 | Q2 2025 | Q3 2025 | Q4 2025 | ||||||||||||||||||||||||||||||||||||||||
Argus basis swaps: | |||||||||||||||||||||||||||||||||||||||||||||||
Hedged volume (Bbl) | |||||||||||||||||||||||||||||||||||||||||||||||
Weighted average spread price (1) | $ | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||
(1) The oil basis swap hedges are calculated as the fixed price (weighted average spread price above) less the difference between WTI Midland and WTI Cushing, in the issue of Argus Americas Crude.
F-26
NOTE 8 — FAIR VALUE MEASUREMENTS
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The authoritative guidance requires disclosure of the framework for measuring fair value and requires that fair value measurements be classified and disclosed in one of the following categories:
| Level 1: | Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis. | ||||
| Level 2: | Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that we value using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. | ||||
| Level 3: | Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). | ||||
Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy. We continue to evaluate our inputs to ensure the fair value level classification is appropriate. When transfers between levels occur, it is our policy to assume that the transfer occurred at the date of the event or change in circumstances that caused the transfer.
The fair values of the Company’s derivatives are not actively quoted in the open market. The Company uses a market approach to estimate the fair values of its derivative instruments on a recurring basis, utilizing commodity futures pricing for the underlying commodities provided by a reputable third party, a Level 2 fair value measurement.
The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments if events or changes in certain circumstances indicate that adjustments may be necessary.
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The following table summarizes the valuation of our assets and liabilities that are measured at fair value on a recurring basis (further detail in "Note 7 — DERIVATIVE FINANCIAL INSTRUMENTS").
| Fair Value Measurement Classification | |||||||||||||||||||||||
| Quoted prices in Active Markets for Identical Assets or (Liabilities) (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Total | ||||||||||||||||||||
| As of December 31, 2022 | |||||||||||||||||||||||
| $ | $ | $ | $ | ||||||||||||||||||||
| ( | ( | ||||||||||||||||||||||
| Total | $ | $ | ( | $ | $ | ( | |||||||||||||||||
| As of December 31, 2023 | |||||||||||||||||||||||
| $ | $ | $ | $ | ||||||||||||||||||||
| ( | ( | ||||||||||||||||||||||
| Total | $ | $ | ( | $ | $ | ( | |||||||||||||||||
The carrying amounts reported for the revolving line of credit approximates fair value because the underlying instruments are at interest rates which approximate current market rates. The carrying amounts of receivables and accounts payable and other current assets and liabilities approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities.
NOTE 9 — REVOLVING LINE OF CREDIT
On July 1, 2014, the Company entered into a Credit Agreement with SunTrust Bank (now Truist), as lender, issuing bank and administrative agent for several banks and other financial institutions and lenders (the “Administrative Agent”), (which was amended several times) that provided for a maximum borrowing base of $1 billion with security consisting of substantially all of the assets of the Company. In April 2019, the Company amended and restated the Credit Agreement with the Administrative Agent (as amended and restated, the “Credit Facility”).
On August 31, 2022, the Company modified its Credit Facility through a Second Amended and Restated Credit Agreement (the "Second Credit Agreement"), extending the maturity date of the facility to August 2026 and the syndicate was modified to add five lenders, replacing five lenders. In conjunction with the Stronghold Acquisition, with the newly acquired assets put up for collateral, the Company established a borrowing base of $600 million. The borrowing base is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time. The borrowing base is redetermined semi-annually each May and November. The borrowing base is subject to reduction in certain circumstances such as the sale or disposition of certain oil and gas properties of the Company or its subsidiaries and cancellation of certain hedging positions.
Rather than Eurodollar loans, the reference rate on the Second Credit Agreement is the SOFR. Also, the Second Credit Agreement permits the Company to declare dividends for its equity owners, subject to certain limitations, including (i) no default or event of default has occurred or will occur upon such payments, (ii) the pro forma Leverage Ratio (outstanding debt to adjusted earnings before interest, taxes, depreciation and amortization, exploration expenses, and all other non-cash charges acceptable to the Administrative Agent) does not exceed 2.00 to 1.00, (iii) the amount of such payments does not exceed Available Free Cash Flow (as defined in the Second Credit Agreement), and (iv) the Borrowing Base Utilization Percentage (as defined in the Second Credit Agreement) is not greater than 80 %.
The interest rate on each SOFR Loan will be the adjusted term SOFR for the applicable interest period plus a margin between 3.0 % and 4.0 % (depending on the then-current level of borrowing base usage). The annual interest rate on each
F-28
base rate Loan is (a) the greatest of (i) the Administrative Agent’s prime lending rate, (ii) the Federal Funds Rate (as defined in the Second Credit Agreement) plus 0.5 % per annum, (iii) the adjusted term SOFR determined on a daily basis for an interest period of one month, plus 1.00 % per annum and (iv) 0.00 % per annum, plus (b) a margin between 2.0 % and 3.0 % per annum (depending on the then-current level of borrowing base usage).
The Second Credit Agreement contains certain covenants, which, among other things, require the maintenance of (i) a total Leverage Ratio of not more than 3.0 to 1.0 and (ii) a minimum ratio of Current Assets to Current Liabilities (as such terms are defined in the Second Credit Agreement) of 1.0 to 1.0. The Second Credit Agreement also contains other customary affirmative and negative covenants and events of default. The Company is required to maintain on a rolling 24 months basis, hedging transactions in respect of crude oil and natural gas, on not less than 50 % of the projected production from its proved, developed, producing oil and gas. However, if the borrowing base utilization is less than 25 % at the hedge testing date and the Leverage Ratio is not greater than 1.25 to 1.00, the required hedging percentage for months 13 through 24 of the rolling 24 month period provided for will be 0 % from such hedge testing date to the next succeeding hedge testing date and if the borrowing base utilization percentage is equal to or greater than 25 %, but less than 50 % and the Leverage Ratio is not greater than 1.25 to 1.00, the required hedging percentage for months 13 through 24 of the rolling 24 month period provided for will be 25 % from such hedge testing date to the next succeeding hedge testing date.
As of December 31, 2023, $425 million was outstanding on the Credit Facility and the Company was in compliance with all covenants contained in the Second Credit Agreement.
Under the Second Credit Agreement, the applicable percentage for the unused commitment fee is 0.5 % per annum for all levels of borrowing base utilization. As of December 31, 2023, the Company's unused line of credit was $174.2 million, which was calculated by subtracting the outstanding Credit Facility balance of $425 million and standby letters of credit of $760,438 in total ($260,000 with state and federal agencies and $500,438 with an insurance company for New Mexico surety bonds) from the $600 million borrowing base. Note 14 — COMMITMENTS AND CONTINGENCIES describes changes in the surety bonds which did not yet affect the letters of credit (collateral) aforementioned.
F-29
NOTE 10 — ASSET RETIREMENT OBLIGATION
A reconciliation of the asset retirement obligation for the years ended December 31, 2023, 2022 and 2021 is as follows:
| Balance, December 31, 2020 | $ | ||||
Liabilities acquired | |||||
| Liabilities incurred | |||||
Liabilities sold | ( | ||||
| Liabilities settled | ( | ||||
Revision of estimate (1) | |||||
| Accretion expense | |||||
| Balance, December 31, 2021 | $ | ||||
| Liabilities acquired | |||||
| Liabilities incurred | |||||
| Liabilities sold | |||||
| Liabilities settled | ( | ||||
Revision of estimate (1) | |||||
| Accretion expense | |||||
| Balance, December 31, 2022 | $ | ||||
| Liabilities acquired | |||||
| Liabilities incurred | |||||
Liabilities sold | ( | ||||
| Liabilities settled | ( | ||||
Revision of estimate (1) | |||||
| Accretion expense | |||||
| Balance, December 31, 2023 | $ | ||||
(1)Several factors are considered in the annual review process, including current estimates for removal cost and estimated remaining useful life of the assets. The 2021 revision of estimates primarily reflect updated interests for our working interest partners.
The following table presents the Company's current and non-current asset retirement obligation balances as of the periods specified.
| December 31, 2023 | December 31, 2022 | ||||||||||
| Asset retirement obligations, current | $ | $ | |||||||||
| Asset retirement obligations, non-current | |||||||||||
| Asset retirement obligations | $ | $ | |||||||||
NOTE 11 — STOCKHOLDERS' EQUITY
The Company was authorized to issue 225,000,000 shares of common stock, with a par value of $0.001 per share, and 50,000,000 shares of preferred stock with a par value per share of $0.001 per share. On May 25, 2023, at the Company's annual meeting of stockholders, the Company's stockholders approved an amendment (the "Charter Amendment") to the Articles of Incorporation of the Company to increase the authorized shares of common stock from 225,000,000 to 450,000,000 .
Issuance of equity instruments in public and private offerings – In October 2020, the Company closed on an underwritten public offering of (i) 9,575,800 shares of common stock, (ii) 13,428,500 Pre-Funded Warrants and (iii) 23,004,300 warrants to purchase common stock (the “Common Warrants”) at a combined purchase price of $0.70 . This includes a
F-30
partial exercise of the over-allotment. The Common Warrants have a term of five years ending in October 2025 and an exercise price of $0.80 per share. Gross proceeds totaled $16,089,582 .
Concurrently with the underwritten public offering, the Company closed on a registered direct offering of (i) 3,500,000 shares of common stock, (ii) 3,300,000 Pre-Funded Warrants and (iii) 6,800,000 Common Warrants at a combined purchase price of $0.70 per share of common stock and Pre-Funded Warrants. The Common Warrants have a term of five years ending in October 2025 and an exercise price of $0.80 per share. Gross proceeds totaled $4,756,700 .
Total gross proceeds from the 2020 underwritten public offering and the registered direct offering aggregated $20,846,282 19,379,832 .
Common stock issued pursuant to warrant exercise - In December 2020, the Company issued 3,300,000 shares of common stock pursuant to the exercise of Pre-Funded Warrants issued in the October 2020 registered direct offering. Gross and net proceeds were $3,300 . In January 2021, the remaining 13,428,500 Pre-Funded Warrants were exercised. During the year ended December 31, 2021, 442,600 of the Common Warrants were exercised. Accordingly, the number of Common Warrants outstanding as of December 31, 2021 was 29,361,700 . During the year ended December 31, 2022, a total of 10,253,907 Common Warrants were exercised, leaving 19,107,793 Common Warrants outstanding as of December 31, 2022.
During February and March 2023, a total of 4,517,427 Common Warrants were exercised, at the exercise price of $0.80 per share. On April 11 and 12, 2023, the Company and certain holders of the common warrants (the “Participating Holders”) entered into a form of Warrant Amendment and Exercise Agreement (the “Exercise Agreement”) pursuant to which the Company agreed to reduce the exercise price of an aggregate of 14,512,166 common warrants held by such Participating Holders from $0.80 to $0.62 per share (the “Reduced Exercise Price”) in consideration for the immediate exercise of the common warrants held by such Participating Holders in full at the Reduced Exercise Price in cash. The Company received aggregate gross proceeds of $8,997,543 from the exercise of the common warrants by the Participating Holders pursuant to the Exercise Agreement, which was recognized as an equity issuance cost in accordance with ASC 815-40-35-17(a). In the Statements of Stockholders' Equity, the net impact to Stockholders' Equity is $8,687,655 , which is net of $309,888 in advisory fees. As of December 31, 2023, a total of 78,200 Common Warrants remained outstanding.
Common stock issued for Stronghold acquisition - As part of the Stronghold Acquisition, 21,339,986 shares of common stock were issued to the sellers. Also as part of the Stronghold Acquisition, 153,176 shares of Preferred Stock were issued to the sellers. Each share of Preferred Stock was automatically convertible into 277.7778 shares of common stock upon stockholder approval of the conversion. On October 27, 2022, the Company’s stockholders approved the issuance of, 42,548,892 shares of common stock upon conversion of the 153,176 shares of our Preferred Stock. The preferred shares were automatically converted into such common shares as of October 27, 2022. Refer to "Note 5 — ACQUISITIONS & DIVESTITURES" for the purchase price consideration allocated to the aforementioned stock issuances.
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Common stock issued for option exercises – During the years ended December 31, 2022 and 2021, the Company issued 52,494 and 100,000 shares of common stock as a result of stock option exercises, respectively. No stock options were exercised in 2023. The following tables present the details of the exercises:
| Options exercised | Exercise price ($) | Shares issued | Shares retained | Cash paid at exercise ($) | Stock price on date of exercise ($) | Aggregate value of shares retained ($) | |||||||||||||||||||||||||||||||||||
| 2021 | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||
| 2021 Totals | $ | ||||||||||||||||||||||||||||||||||||||||
| 2021 Weighted Averages | $ | $ | |||||||||||||||||||||||||||||||||||||||
| Options exercised | Exercise price ($) | Shares issued | Shares retained | Cash paid at exercise ($) | Stock price on date of exercise ($) | Aggregate value of shares retained ($) | |||||||||||||||||||||||||||||||||||
| 2022 | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||
| 2022 Totals | $ | ||||||||||||||||||||||||||||||||||||||||
| 2022 Weighted Averages | $ | $ | |||||||||||||||||||||||||||||||||||||||
NOTE 12 — EMPLOYEE STOCK OPTIONS, RESTRICTED STOCK AWARD PLAN, AND 401(K)
Compensation expense charged against income for share-based awards during the years ended December 31, 2023, 2022, and 2021 was $8,833,425 , $7,162,231 , and $2,418,323 , respectively. These amounts are included in General and administrative expense in the Statements of Operations.
In 2011, the Board approved and adopted a long-term incentive plan (the “2011 Plan”), which was subsequently approved and amended by the shareholders. There were 536,755 shares eligible for grant, either as stock options or as restricted stock, as of December 31, 2023.
In 2021, the Board approved and adopted the Ring Energy, Inc. 2021 Omnibus Incentive Plan (the “2021 Plan”), which was subsequently approved by the shareholders at the 2021 Annual Meeting. The 2021 Plan provides that the Company may grant options, stock appreciation rights, restricted shares, restricted stock units, performance-based awards, other share-based awards, other cash-based awards, or any combination of the foregoing. At the 2023 Annual Meeting, the shareholders approved an amendment to the 2021 Plan to increase the number of shares available under the 2021 Plan by 6.0 million. Accordingly, there were 8,224,394 shares available for grant as of December 31, 2023 under the 2021 Plan.
Employee Stock Options – No 20 % each year over five years beginning one year from the date granted
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and expire ten years from the grant date. A summary of the status of the stock options as of December 31, 2023, 2022, and 2021 and changes during the years ended December 31, 2023, 2022, and 2021 is as follows:
| 2023 | 2022 | 2021 | |||||||||||||||||||||||||||||||||
| Options | Weighted- Average Exercise Price | Options | Weighted- Average Exercise Price | Options | Weighted- Average Exercise Price | ||||||||||||||||||||||||||||||
| Outstanding at beginning of year | $ | $ | $ | ||||||||||||||||||||||||||||||||
Granted | |||||||||||||||||||||||||||||||||||
Forfeited | |||||||||||||||||||||||||||||||||||
Expired | ( | ||||||||||||||||||||||||||||||||||
| Exercised | ( | ( | |||||||||||||||||||||||||||||||||
| Outstanding at end of year | $ | $ | $ | ||||||||||||||||||||||||||||||||
| Exercisable at end of year | $ | $ | $ | ||||||||||||||||||||||||||||||||
For the years ended December 31, 2023, 2022, and 2021, the Company incurred share-based compensation expense related to stock options of $0 , $0 , and $20,934 , respectively. As of December 31, 2023, the Company had $0 of unrecognized compensation cost related to stock options. The aggregate intrinsic value of options vested and expected to vest as of December 31, 2023 was $0 . The aggregate intrinsic value of options exercisable at December 31, 2023 was $0 . The year-end intrinsic values are based on a December 31, 2023 closing stock price of $1.46 .
No stock options were exercised during 2023. Stock options exercised of 100,000 shares in 2022 had an aggregate intrinsic value on the date of exercise of $221,000 . Stock options exercised of 100,000 shares in 2021 had an aggregate intrinsic value on the date of exercise of $114,000 .
The following table summarizes information related to the Company’s stock options outstanding as of December 31, 2023:
| Options Outstanding | ||||||||||||||||||||
| Exercise price | Number Outstanding | Weighted- Average Remaining Contractual Life (in years) | Number Exercisable | |||||||||||||||||
| $ | ||||||||||||||||||||
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Restricted stock unit grants – Following is a table reflecting the restricted stock unit grants during 2023, 2022 and 2021:
| Grant date | # of restricted stock units | |||||||
| April 30, 2021 | ||||||||
| June 17, 2021 | ||||||||
| July 6, 2021 | ||||||||
| July 12, 2021 | ||||||||
| September 1, 2021 | ||||||||
| September 8, 2021 | ||||||||
| February 9, 2022 | ||||||||
| April 13, 2022 | ||||||||
| May 10, 2022 | ||||||||
| June 16, 2022 | ||||||||
| July 14, 2022 | ||||||||
| August 29, 2022 | ||||||||
| September 1, 2022 | ||||||||
| September 19, 2022 | ||||||||
| February 16, 2023 | ||||||||
Restricted stock unit grants issued prior to 2020 vest at the rate of 20 % each year over five years beginning one year from the date granted. Restricted stock unit grants issued during 2020 and in following years vest at a rate of 33 % each year over three years beginning one year from the date granted for all employees; for members of the Board, the 2021 restricted stock unit grants vest on the earliest of (i) the day before the next shareholder meeting or (ii) the first anniversary of the date of the award for 2022 restricted stock units. Forfeitures are recognized as a reduction to share-based compensation expense in the period of occurrence. A summary of the status of restricted stock unit grants and changes during the years ended December 31, 2023, 2022 and 2021 is as follows:
| 2023 | 2022 | 2021 | |||||||||||||||||||||||||||||||||
| Restricted stock units | Weighted- Average Grant Date Fair Value | Restricted stock units | Weighted- Average Grant Date Fair Value | Restricted stock units | Weighted- Average Grant Date Fair Value | ||||||||||||||||||||||||||||||
| Outstanding at beginning of year | $ | $ | $ | ||||||||||||||||||||||||||||||||
| Granted | |||||||||||||||||||||||||||||||||||
| Forfeited or rescinded | ( | ( | |||||||||||||||||||||||||||||||||
| Vested | ( | ( | ( | ||||||||||||||||||||||||||||||||
| Outstanding at end of year | $ | $ | $ | ||||||||||||||||||||||||||||||||
For the years ended December 31, 2023, 2022 and 2021, the Company incurred share-based compensation expense related to restricted stock unit grants of $4,537,026 , $4,148,639 , and $2,225,895 , respectively. As of December 31, 2023, the Company had $2,778,549 of unrecognized compensation cost related to restricted stock unit grants that will be recognized over a weighted average period of 1.72 years.
During 2023, 2022, and 2021, 1,680,232 , 1,310,894 , and 785,357 restricted stock units vested, respectively. At the dates of vesting those restricted stock units had an aggregate intrinsic value of $3,203,568 , $3,807,996 , and $2,049,603 , respectively.
Performance Stock Units - In accordance with the 2021 Plan, as of November 22, 2021, the Company entered into performance stock unit (“PSU”) agreements (the “PSU Agreement”) with certain employees. The PSUs are performance-based restricted stock units subject to the terms of the 2021 Plan and the PSU Agreement. Upon Board approval, a total of
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A summary of the status of the PSU awards and changes during the years ended December 31, 2023, 2022 and 2021 are as follows:
| 2023 | 2022 | 2021 | ||||||||||||||||||||||||||||||||||||
| Performance Stock Units | Weighted- Average Grant Date Fair Value | Performance Stock Units | Weighted- Average Grant Date Fair Value | Performance Stock Units | Weighted- Average Grant Date Fair Value | |||||||||||||||||||||||||||||||||
| Outstanding at beginning of year | $ | $ | $ | |||||||||||||||||||||||||||||||||||
| Granted | ||||||||||||||||||||||||||||||||||||||
Incremental performance stock units vested | ||||||||||||||||||||||||||||||||||||||
| Forfeited or rescinded | ||||||||||||||||||||||||||||||||||||||
| Vested | ( | |||||||||||||||||||||||||||||||||||||
| Outstanding at end of year | $ | $ | $ | |||||||||||||||||||||||||||||||||||
No forfeitures for the PSU awards have been recognized as of December 31, 2023, but the Company would recognize any such forfeitures in the period of occurrence as a reduction to share-based compensation expense. For the years ended December 31, 2023, 2022 and 2021, the Company incurred share-based compensation expense related to the PSU Awards of $4,296,399 , $3,013,592 , and $171,494 , respectively. As of December 31, 2023, the Company had $4,015,133 of unrecognized compensation cost related to the PSU Awards that will be recognized over a weighted average period of 1.57 years.
During 2023, 1,170,024 PSUs vested. At the dates of vesting those PSUs had an aggregate intrinsic value of $1,708,235 .
401(k) Plan - In 2019, the Company initiated a sponsored 401(k) plan that is a defined contribution plan for the benefit of all eligible employees. The plan allows eligible employees, after a three-month waiting period, to make pre-tax or after-tax contributions, not to exceed annual limits established by the federal government. The Company makes matching contributions of up to 6 % of any employee’s compensation. Employees are 100 % vested in the employer contribution upon receipt.
The following table presents the matching contributions expense recognized for the Company’s 401(k) plan for the years ended December 31, 2023, 2022, and 2021:
| 2023 | 2022 | 2021 | |||||||||||||||
| Employer safe harbor match | $ | $ | $ | ||||||||||||||
NOTE 13 — RELATED PARTY TRANSACTIONS
The Company leased office space in Tulsa, Oklahoma, from Arenaco, LLC (“Arenaco”), a company that was owned by
two stockholders of the Company, Mr. Rochford, former Chairman of the Board, and Mr. McCabe, a former director of the
Company. During the year ended December 31, 2021, the Company paid $10,000 to Arenaco. The month-to-month
Arenaco lease was terminated as of March 31, 2021.
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During June 2021, the Company began using Pro-Ject Chemicals, LLC (“PJ Chemicals”) to perform various chemical services on its wells. As publicly disclosed on the Company’s website, Paul D. McKinney, Chief Executive Officer and Chairman of the Board, was a member of the board of directors of Pro-Ject Holdings, LLC, a privately owned oil field chemical services company and parent of PJ Chemicals. Mr. McKinney owned 0.34 % of the shares of Pro-Ject Holdings, LLC. During the year ended December 31, 2021, the Company paid $117,830 to PJ Chemicals. As of December 31, 2021 the Company had accounts payable of $37,641 due to PJ Chemicals. As of 2022, Mr. McKinney was no longer on the board of directors of Pro-Ject Holdings, LLC.
NOTE 14 — COMMITMENTS AND CONTINGENCIES
Standby Letters of Credit – A commercial bank issued standby letters of credit on behalf of the Company totaling $260,000 to state and federal agencies and $500,438 to an insurance company to secure the surety bonds described below. The standby letters of credit are valid until cancelled or matured and are collateralized by the revolving credit facility with the bank. The terms of the letters of credit to the state and federal agencies are extended for a term of one year at a time. The Company intends to renew the standby letters of credit to the state and federal agencies for as long as the Company does business in the State of Texas. The letters of credit to the insurance company will be renewed if the insurance requires them to retain the surety bonds; however, as the Company no longer operates any wells in the State of New Mexico, these standby letters of credit will not be renewed. No amounts have been drawn under the standby letters of credit.
Surety Bonds – An insurance company issued surety bonds on behalf of the Company totaling $500,438 to various State of New Mexico agencies in order for the Company to do business in the State of New Mexico. The surety bonds are valid until canceled or matured. The terms of the surety bonds are extended for a term of one year at a time. The Company does not intend to renew the surety bonds in the State of New Mexico, as these operated assets have now been sold to a third party. As of December 31, 2023, the Company had remaining surety bonds in total of $25,000 .
NOTE 15 — INCOME TAXES
For the years ended December 31, 2023, 2022, and 2021, components of our provision for income taxes are as follows:
Provision for Income Taxes: | 2023 | 2022 | 2021 | |||||||||||||||||
| Federal deferred tax | $ | ( | $ | $ | ||||||||||||||||
State current tax | ||||||||||||||||||||
| State deferred tax | ||||||||||||||||||||
Provision for Income Taxes | $ | $ | $ | |||||||||||||||||
The following is a reconciliation of income taxes computed using the U.S. federal statutory rate to the provision for income taxes:
Rate Reconciliation: | 2023 | 2022 | 2021 | |||||||||||||||||
Pre-tax book income (1) | $ | $ | $ | |||||||||||||||||
| Tax at federal statutory rate | $ | $ | $ | |||||||||||||||||
| Excess tax benefit from stock option exercises and restricted stock vesting | ( | ( | ||||||||||||||||||
| Adjust prior estimates to tax return | ( | |||||||||||||||||||
| States taxes, net of federal benefit | ||||||||||||||||||||
| Valuation allowance | ( | ( | ( | |||||||||||||||||
| Non-deductible expenses and other | ||||||||||||||||||||
| Provision for Income Taxes | $ | $ | $ | |||||||||||||||||
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The Company's deferred tax position reflects the net tax effects of the temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax reporting. The net deferred taxes consisted of the following as of December 31, 2023 and 2022:
| 12/31/2023 Total | 12/31/2022 Total | ||||||||||
| Deferred Tax Assets | |||||||||||
| Net operating loss (NOL) carryforward | |||||||||||
| Equity compensation | |||||||||||
| Asset retirement obligation | |||||||||||
| Fair market value of derivatives | |||||||||||
| §163(j) business interest expense carryforward | |||||||||||
| Others | |||||||||||
| Gross Deferred Tax Assets | |||||||||||
| Less: valuation allowance | ( | ||||||||||
| Net Deferred Tax Assets | |||||||||||
| Deferred Tax Liabilities | |||||||||||
| Property and equipment | ( | ( | |||||||||
| Other | ( | ( | |||||||||
| Net Deferred Liabilities | ( | ( | |||||||||
| Net Deferred Tax Liabilities | ( | ( | |||||||||
As of December 31, 2023, the Company had net operating loss carryforwards for federal income tax reporting purposes of approximately $109.3 million which, if unused, will begin to expire in 2027 and fully expire in 2037 and an additional $279.2 million that can be carried forward indefinitely. The shares issued for the Stronghold Acquisition (further discussed in Note 5 — ACQUISITIONS & DIVESTITURES) resulted in the Company having an ownership change under Section 382 of the Internal Revenue Code of 1986, as amended. Section 382 limits the availability of certain tax attributes, including net operating losses and disallowed interest carryforwards, to offset future taxable income of the Company. In evaluating its need for a valuation allowance against its deferred tax assets, the Company has estimated the amount of tax attributes related to the pre-ownership change period to be available under Section 382 in periods in which it expects deferred tax liabilities to be realized based on currently available information. Based on its current analysis, the Company does not anticipate any material tax attributes to expire unused as result of the Section 382 ownership change; however, the ultimate timing in the amount of tax attributes available in future periods may be different than the Company's current estimate and will be determined in each year as new information becomes available. Changes in expectation in the timing of the availability of the Company's tax attributes could result in adjustments to the valuation allowance in future years as it updates its analysis based on new information.
As of December 31, 2023, we carried a valuation allowance against our federal and state deferred tax assets of $0 . We have considered both the positive and negative evidence in determining whether it was more likely than not that some portion or all of our deferred tax assets will be realized. The amount of deferred tax assets considered realizable could, however, be adjusted if estimates of future taxable income during the carryforward period are reduced or increased or if objective negative evidence is no longer present and additional weight is given to subjective positive evidence, including projections for growth. As of June 30, 2023, the Company was no longer in a cumulative loss position. As a result, future forecasted pre-tax book income was considered as positive evidence in assessing the valuation allowance. Based on the change in judgment on the realizability of the related federal deferred tax assets in future years, the Company released $24.2 million of valuation allowance as a benefit during the year ended December 31, 2023. This resulted in an ending federal net deferred tax liability of $5,536,158 . Additionally, the Company reported a net state deferred tax liability at December 31, 2023 of $3,015,887 attributable to certain state deferred tax liabilities mainly associated with property and equipment.
NOTE 16 — LEGAL MATTERS
The Company is a defendant in a lawsuit in Harris County District Court, Houston, Texas, styled EPUS Permian Assets, LLC, v. Ring Energy, Inc., that was filed in July 2021. The plaintiff, EPUS Permian Assets, LLC, claims breach of
F-37
contract, money had and received by fraudulent inducement, unjust enrichment and constructive trust. The plaintiff is requesting its forfeited deposit of $5,500,000 in connection with a proposed property sale by the Company plus related damages, and attorneys’ fees and costs. The action relates to a proposed property sale by the Company to the plaintiff, which was extended by the Company on several occasions with the plaintiff ultimately failing to perform on the agreement and the Company keeping the deposit. The Company believes that the claims by the plaintiff are entirely without merit and is conducting a vigorous defense and counterclaim. The Company has filed an answer and a counterclaim denying the allegations and asserting affirmative defenses that would bar or substantially limit the plaintiff’s claims, asserting breach of contract and requesting a declaratory judgment and attorneys’ fees and costs. The parties have begun taking depositions and are conducting discovery.
NOTE 17 — SUBSEQUENT EVENTS
Surety Bonds - On January 10, 2024, two insurance companies issued surety bonds on behalf of the Company, one for $250,000 , an RRC required blanket performance bond to operate 100 wells or more in the State of Texas, and one for $2,000,000 , an RRC required blanket plugging extension bond, each with zero collateral requirements. The term for these two surety bonds ends on July 1, 2025 and can be renewed at that time.
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RING ENERGY, INC.
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES
(Unaudited)
Results of Operations from Oil and Natural Gas Producing Activities – The Company’s results of operations from oil and natural gas producing activities exclude interest expense, gain from change in fair value of derivatives, and other financing expense.
| For the years ended December 31, | 2023 | 2022 | 2021 | |||||||||||||||||
Oil, natural gas, and natural gas liquids sales | $ | 361,056,001 | $ | 347,249,537 | $ | 196,305,966 | ||||||||||||||
| Lease operating expenses | (70,158,227) | (47,695,351) | (30,312,399) | |||||||||||||||||
| Gathering, transportation and processing costs | (457,573) | (1,830,024) | (4,333,232) | |||||||||||||||||
| Ad valorem taxes | (6,757,841) | (4,670,617) | (2,276,463) | |||||||||||||||||
| Production taxes | (18,135,336) | (17,125,982) | (9,123,420) | |||||||||||||||||
Depreciation, depletion, and amortization | (88,610,291) | (55,740,767) | (37,167,967) | |||||||||||||||||
| General and administrative (exclusive of corporate overhead) | (2,839,401) | (1,617,095) | (2,003,876) | |||||||||||||||||
Income tax expense | (208,917) | (12,502,187) | (2,943,848) | |||||||||||||||||
Results of Oil and Natural Gas Producing Operations | $ | 173,888,415 | $ | 206,067,514 | $ | 108,144,761 | ||||||||||||||
Costs Incurred in Oil and Gas Producing Activities
| For the years Ended December 31, | 2023 | 2022 | 2021 | |||||||||||||||||
Payments to acquire oil and natural gas properties | $ | 82,900,900 | $ | 179,387,490 | $ | 1,368,437 | ||||||||||||||
Payments to explore oil and natural gas properties | — | — | — | |||||||||||||||||
| Payments to develop oil and natural gas properties | 152,559,314 | 129,332,155 | 51,302,131 | |||||||||||||||||
Total costs incurred | $ | 235,460,214 | $ | 308,719,645 | $ | 52,670,568 | ||||||||||||||
Capitalized Costs
| As of December 31, | 2023 | 2022 | ||||||||||||
| Oil and natural gas properties, full cost method | ||||||||||||||
Proved properties | 1,663,548,249 | 1,463,838,595 | ||||||||||||
Unproved properties | — | — | ||||||||||||
Total oil and natural gas properties, full cost method | 1,663,548,249 | 1,463,838,595 | ||||||||||||
Accumulated depletion of oil and natural gas properties | (373,280,583) | (287,052,595) | ||||||||||||
Net oil and natural gas properties capitalized | $ | 1,290,267,666 | $ | 1,176,786,000 | ||||||||||
Reserve Quantities Information – The following estimates of proved and proved developed reserve quantities and related standardized measure of discounted future net cash flow are estimates only, and do not purport to reflect realizable values or fair market values of the Company’s reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available. All of the Company’s reserves are located in the United States of America.
The proved reserves estimates shown herein for the years ended December 31, 2023, 2022 and 2021 have been prepared by Cawley, Gillespie & Associates, Inc., independent petroleum engineers. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first-day-of-the-month prices.
The reserve information in these Financial Statements represents only estimates. There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the Company’s control, such as commodity pricing. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural
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gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. As a result, estimates by different engineers may vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may lead to revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Except to the extent the Company acquires additional properties containing proved reserves or conducts successful exploration and development activities or both, the Company’s proved reserves will decline as reserves are produced.
The oil prices as of December 31, 2023, 2022 and 2021 are based on the respective 12-month unweighted average of the first of the month prices of the WTI spot prices which equates to $74.70 per barrel, $90.15 per barrel and $63.04 per barrel, respectively. The natural gas prices as of December 31, 2023, 2022 and 2021 are based on the respective 12-month unweighted average of the first of month prices of the Henry Hub spot price which equates to $2.637 per MMBtu, $6.358 per MMBtu and $3.598 per MMBtu, respectively. Prices are adjusted by local field and lease level differentials and are held constant for life of reserves in accordance with SEC guidelines.
Proved reserves are estimated reserves of crude oil (including condensate and NGLs) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment and methods.
| For the Year Ended December 31, | 2023 | |||||||||||||||||||||||||
Oil (1) | Natural Gas (1) | Natural Gas Liquids (1) | Boe | |||||||||||||||||||||||
| Proved Developed and Undeveloped Reserves | ||||||||||||||||||||||||||
| Beginning of year | 88,704,743 | 157,870,449 | 23,105,658 | 138,122,143 | ||||||||||||||||||||||
| Purchase of minerals in place | 6,543,640 | 3,372,965 | 1,089,382 | 8,195,183 | ||||||||||||||||||||||
| Extensions, discoveries and improved recovery | 3,098,845 | 4,113,480 | 1,014,343 | 4,798,768 | ||||||||||||||||||||||
| Sales of minerals in place | (4,897,921) | (2,674,955) | (392,953) | (5,736,700) | ||||||||||||||||||||||
| Production | (4,579,942) | (6,339,158) | (976,852) | (6,613,320) | ||||||||||||||||||||||
| Revisions of previous quantity estimates | (6,728,088) | (9,946,459) | (621,014) | (9,006,845) | ||||||||||||||||||||||
| End of year | 82,141,277 | 146,396,322 | 23,218,564 | 129,759,229 | ||||||||||||||||||||||
| Proved Developed at beginning of year | 57,012,137 | 106,399,050 | 15,332,804 | 90,078,116 | ||||||||||||||||||||||
| Proved Undeveloped at beginning of year | 31,692,606 | 51,471,399 | 7,772,854 | 48,044,027 | ||||||||||||||||||||||
| Proved Developed at end of year | 56,029,039 | 99,896,022 | 15,449,907 | 88,128,284 | ||||||||||||||||||||||
| Proved Undeveloped at end of year | 26,112,238 | 46,500,300 | 7,768,657 | 41,630,945 | ||||||||||||||||||||||
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| For the Year Ended December 31, | 2022 | |||||||||||||||||||||||||
Oil (1) | Natural Gas (1) | Natural Gas Liquids (1) | Boe | |||||||||||||||||||||||
| Proved Developed and Undeveloped Reserves | ||||||||||||||||||||||||||
| Beginning of year | 65,838,609 | 71,773,789 | — | 77,800,907 | ||||||||||||||||||||||
| Purchase of minerals in place | 28,086,920 | 108,456,107 | 16,715,626 | 62,878,564 | ||||||||||||||||||||||
| Extensions, discoveries and improved recovery | 628,978 | 522,178 | 52,810 | 768,818 | ||||||||||||||||||||||
| Sales of minerals in place | — | — | — | — | ||||||||||||||||||||||
| Production | (3,459,477) | (4,088,642) | (371,337) | (4,512,254) | ||||||||||||||||||||||
| Revisions of previous quantity estimates | (2,390,287) | (18,792,983) | 6,708,559 | 1,186,108 | ||||||||||||||||||||||
| End of year | 88,704,743 | 157,870,449 | 23,105,658 | 138,122,143 | ||||||||||||||||||||||
| Proved Developed at beginning of year | 36,820,824 | 39,748,880 | — | 43,445,637 | ||||||||||||||||||||||
| Proved Undeveloped at beginning of year | 29,017,785 | 32,024,909 | — | 34,355,270 | ||||||||||||||||||||||
| Proved Developed at end of year | 57,012,137 | 106,399,050 | 15,332,804 | 90,078,116 | ||||||||||||||||||||||
| Proved Undeveloped at end of year | 31,692,606 | 51,471,399 | 7,772,854 | 48,044,027 | ||||||||||||||||||||||
(1) Oil reserves are stated in barrels; natural gas reserves are stated in thousand cubic feet; NGL reserves are stated in
barrels.
Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.
Notable changes in proved reserves for the year ended December 31, 2023 included the following:
•Extensions. In 2023, extensions of 4.8 MMBoe were primarily the result of the successful operated drilling program and non-operated activity in the Northwest Shelf and Central Basin Platform.
•Purchase of minerals in place. In 2023, the Company completed the acquisition of Founders oil and gas leases and related property within Ector County that resulted in 8.2 MMBoe in additional reserves.
•Sales of minerals in place. In 2023, the Company sold 5.7 MMBoe from the divestiture of the Delaware Basin assets (30%), the New Mexico operated assets (57%), and part of the Company's assets in Gaines County (13%).
•Revision of previous estimates. In 2023, the negative revisions of prior reserves of 9.0 MMBoe consisted of 5.3 MMBoe (59%) related to changes in price and 3.7 MMBoe (41%) related to changes in performance and other economic factors.
Standardized Measure of Discounted Future Net Cash Flows – The standardized measure of discounted future net cash flows is computed by applying the price according to the SEC guidelines for oil and natural gas to the estimated future production of proved oil and natural gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on year-end statutory tax rates) to be incurred on pretax net cash flows less tax basis of the properties and available credits, and assuming continuation of existing economic conditions. The estimated future net cash flows are then discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows.
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Standardized Measure of Discounted Future Net Cash Flows
| December 31, | 2023 | 2022 | 2021 | |||||||||||||||||
| Future cash inflows | $ | 6,622,410,752 | $ | 9,871,961,000 | $ | 4,853,709,000 | ||||||||||||||
| Future production costs | (2,413,303,488) | (2,751,896,250) | (1,395,437,250) | |||||||||||||||||
Future development costs (1) | (562,063,424) | (647,196,750) | (347,757,000) | |||||||||||||||||
| Future income taxes | (548,664,988) | (1,142,147,641) | (501,586,949) | |||||||||||||||||
| Future net cash flows | 3,098,378,852 | 5,330,720,359 | 2,608,927,801 | |||||||||||||||||
| 10% annual discount for estimated timing of cash flows | (1,699,193,661) | (3,058,606,841) | (1,471,562,953) | |||||||||||||||||
| Standardized Measure of Discounted Future Net Cash Flows | $ | 1,399,185,191 | $ | 2,272,113,518 | $ | 1,137,364,848 | ||||||||||||||
(1) Future development costs include not only development costs but also future asset retirement costs.
The following is a summary of the changes in the Standardized Measure for the Company’s proved oil and natural gas reserves during each of the years in the three-year period ended December 31, 2023:
Changes in Standardized Measure of Discounted Future Net Cash Flows
| 2023 | 2022 | 2021 | |||||||||||||||
| Beginning of the year | $ | 2,272,113,518 | $ | 1,137,364,848 | $ | 555,871,253 | |||||||||||
| Purchase of minerals in place | 141,738,066 | 996,313,882 | 33,688,718 | ||||||||||||||
| Extensions, discoveries and improved recovery | 57,607,609 | 20,447,842 | 79,003,885 | ||||||||||||||
| Development costs incurred during the year | 70,697,664 | 67,454,522 | 17,513,180 | ||||||||||||||
| Sales of oil and gas produced, net of production costs | (266,004,598) | (283,588,498) | (154,615,685) | ||||||||||||||
| Sales of minerals in place | (59,600,128) | — | (2,523,746) | ||||||||||||||
| Accretion of discount | 277,365,650 | 133,209,763 | 63,810,764 | ||||||||||||||
| Net changes in price and production costs | (1,181,594,019) | 646,819,172 | 636,884,944 | ||||||||||||||
| Net change in estimated future development costs | 37,865,811 | (53,253,626) | (44,357,751) | ||||||||||||||
| Revisions of previous quantity estimates | (187,443,783) | 33,583,837 | (22,259,508) | ||||||||||||||
| Changes in estimated timing of cash flows | (17,257,348) | (119,428,019) | 86,845,188 | ||||||||||||||
| Net change in income taxes | 253,696,749 | (306,810,205) | (112,496,394) | ||||||||||||||
| End of the Year | $ | 1,399,185,191 | $ | 2,272,113,518 | $ | 1,137,364,848 | |||||||||||
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