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United States

Securities and Exchange Commission

Washington, D.C. 20549

Form 10-K

(Mark One)

xAnnual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

xAnnual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2017

2023

Or

¨Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

oTransition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from ___________to ___________

______ to ______

Commission file number 001-36057

Ring Energy, Inc.

(Exact name of registrant as specified in its charter)

Nevada90-0406406

(State or other jurisdiction of


incorporation or organization)

(I.R.S. Employer


Identification Number)

No.)
1725 Hughes Landing Blvd., Suite 900
The Woodlands, TX
77380

901 West Wall St, 3rd Floor

Midland, TX

79702
(Address of principal executive offices)(Zip Code)
(281) 397-3699
(Registrant’s telephone number, including area code)

(432) 682-7464

(Registrant’s telephone number, including area code)

Securities registered under Section 12(b) of the Exchange Act:

Title of Each ClassTrading SymbolName of Each Exchange on Which Registered
Common Stock, par value $0.001REINYSE MKTAmerican

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 Nox

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 Nox

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. Yesx. No¨

o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files). Yesx. No¨

Indicate by check mark if disclosure of delinquent filers in response to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.x

o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer”,filer,” “accelerated filer,” “smaller reporting company,” and emerging"emerging growth company”company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer¨oAccelerated filerx
Non-accelerated filer¨o(Do not check if a smaller reporting company)Smaller reporting company¨o
Emerging growth company¨o

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 Nox

As of June 30, 2017,2023, the aggregate market value of the common voting stock held by non-affiliates of the issuer,registrant, based upon the closing stock price on that day on the NYSE MKTAmerican of $13.00$1.71 per share, was approximately $586,591,070.

$227,493,793.

As of March 14, 2018,7, 2024, the issuerregistrant had outstanding 60,388,029197,934,202 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.

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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 on Form 10-K (herein, “Annual Report”) regarding our strategy, future operations, financial position, estimated revenues and losses,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,” “project” and“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. You should not place undue reliance on these forward-looking statements. 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 discloseare 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 our actual results to differ materially from those contemplated. Such factors include:
•declines or volatility in the prices we receive for our expectationsoil 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,” “Management’s DiscussionFactors” in this Annual Report, as well as in our financial statements, related notes, and Analysis of Financial Condition and Results of Operations” andthe other financial information appearing elsewhere in this Annual Report. These cautionary statements qualify allReport 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, attributablewhich speak only as of the date that such statements are made. We undertake no obligation to uspublicly update or persons acting on our behalf.

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,” “the Company,“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 orJOA – 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 liquidsor 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 ornet 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 orP&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 orPDNP– 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 orPD– 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 orPUD– 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 orWI– 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

Item 1:     Business
General

Ring was incorporated in the State ofEnergy, Inc., a Nevada in 2004 as “Blanca Corp.” The name of the corporation was changed to “Transglobal Mining Corp.(“Ring,” in 2007 before being changed to “Ring Energy, Inc.” in 2008. We arethe “Company,” “we,” “us,” “our,” or similar terms), is a Midland-basedgrowth oriented independent oil and natural gas exploration and production company thatbased in The Woodlands, Texas and is engaged in oil and natural gas development, production, acquisition, and exploration development and production activities. Our exploration and production interests areactivities currently focused in the Permian Basin of Texas. The Company takes a conventional approach to its drilling program and seeks to develop its traditional core areas, as well as look for new growth opportunities.

The Company’s primaryOur drilling operations target the oil and liquids rich producing formations in the Northwest Shelf and the Central Basin Platform, in Andrews County and Gaines County, Texas and the DelawarePermian Basin in Reeves County and Culberson County, Texas.

As of December 31, 2017, Ring had 102,7772023, our leasehold acreage positions totaled 96,127 gross (69,874(80,535 net) acres and we held interests in Andrews and Gaines counties and 20,2181,043 gross (19,917(864 net) acres in Reeves and Culberson counties.

Asproducing wells. Proved reserves as of December 31, 2017, Ring’s proved reserves2023 (based upon the report of our independent petroleum engineer of that date) were approximately 31.9129.8 million BOE (barrelBoe, of oil equivalent)which we are the operator of approximately 98%. All of its reserves (based on the estimates above) relate toour properties are located in Texas. The Company’sthe Permian Basin and our proved reserves are oil-weighted, with 91% of proved reservesapproximately 63% consisting of oil, and 9%19% consisting of natural gas. Of those reserves, 45%gas, and 18% consisting of NGLs. Approximately 68% of the proved reserves are classified as proved developed producing, or “PDP,” 10%PD and 32% are classified as proved developed non-producing, or “PDNP,”PUD. Within the PD reserve category, 242 recompletion and approximately 45%re-activation opportunities are classified as PDNP and within the PUD reserve category, we have a total of 211 proved undeveloped, or “PUD.”

Production forlocations (33% horizontal and 67% vertical) based on the year endedreserve report as of December 31, 2017, was 1,438,647 BOE, as compared2023. 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 878,066 BOE18,119 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 year ended December 31, 2016,world’s health and welfare.
Our Key Principles
Successfully achieving Ring’s mission requires a 64% increasefirm commitment to operating safely in BOE. The stateda 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 amount reflects onlyand 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 thatleases 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 producedaccomplished by the exercise of 4,517,427 common warrants at an exercise price of $0.80 per share and shipped priorthe 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 endCompany 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 fourth quarter. Any oil and gas produced in the fourth quarter but still held on site after December 31, 2017, will be credited inlong term.
In the first quarter of 2018.

Ring believes that there is significant value to be created2023, 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 drilling the identified undeveloped opportunities on its Texas properties. As ofquarter, and full year total through December 31, 2017, 2023.
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QuarterAreaWells DrilledWells CompletedRecompletions
1Q 2023Northwest Shelf (Horizontal)4 4 — 
Central Basin Platform (Horizontal)— — — 
Central Basin Platform (Vertical)3 3 6 
Total7 7 6 
2Q 2023Northwest Shelf (Horizontal)4 4 — 
Central Basin Platform (Horizontal)— — — 
Central Basin Platform (Vertical)2 2 3 
Total6 6 3 
3Q 2023Northwest Shelf (Horizontal)5 2 — 
Central Basin Platform (Horizontal)3 3 — 
Central Basin Platform (Vertical)3 3 — 
Total11 8 — 
4Q 2023Northwest Shelf (Horizontal)1 4 — 
Central Basin Platform (Horizontal)3 3 — 
Central Basin Platform (Vertical)3 3 — 
Total (1)
7 10 — 
FY 2023Northwest 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 owned interestsEnergy’s Strengths
Our strengths include:
•high quality asset base in a totalone of 11,917 gross (8,102 net) developed acres and 90,860 gross (61,772 net) undeveloped acres in Andrews and Gaines County, Texas. In these counties, the Company has 140 identified proven vertical drilling locations and 11 identified proven horizontal locations based on the reserve reports as of December 31, 2017, and an additional 396 potential vertical drilling locations based on 10-acre downspacing and 796 potential horizontal drilling locations based on 6 wells per section or 106 acres per well. Also as of December 31, 2017, Ring owned interests in a total of 10,390 gross (10,235 net) developed acres and 9,828 (9,682 net) undeveloped acres in Culberson and Reeves County, Texas. In these counties, the Company has 39 identified proven vertical drilling locations based on the reserve reports as of December 31, 2017 and an additional 452 potential vertical drilling locations based on 20-acre downspacing. Ring intends to grow its reserves and production through development, drilling, exploitation and exploration activities on this multi-year project inventory of identified potential drilling locations and through acquisitions that meet the Company’s strategic and financial objectives, targeting oil-weighted reserves.

Business Segments

Our operations are allNorth America’s leading oil and gas explorationproducing 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 related activitiesand development activities; and
•commitment to cost efficient operations, health, safety, protecting the environment, our employees, and the communities in the United States.

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which we work and operate.

Principal Executive Office

Our principal executive offices are located at 901 West Wall St., 3rd Floor, Midland, TX 79702, and our telephone number is (432) 682-7464. Our Internet website can be found at www.ringenergy.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act of 1934 will be available through our Internet website 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.

Ring Energy’s Business Strategy and Development

·Pursue strategic acquisitions with exceptional upside potential.Ring has a history of acquiring leasehold positions that it believes to have substantial resource potential and to meet its targeted returns on invested capital. Ring has historically pursued acquisitions of properties that it believes to have exploitation and development potential comparable to its existing inventory of drilling locations. The Company has developed and refined an acquisition program designed to increase reserves and complement existing core properties. Ring’s experienced team of management and engineering professionals identify and evaluate acquisition opportunities, negotiate and close purchases and manage acquired properties. Management intends to continue to pursue strategic acquisitions that meet the Company’s operational and financial targets. The executive team, with its extensive experience in the Permian Basin, has many relationships with operators and service providers in the region. Ring believes that leveraging its relationships will be a competitive advantage in identifying acquisition targets. Management’s proven ability to evaluate resource potential will allow Ring to successfully acquire acreage and bring out more value in the assets.
·Growing production and reserves by developing our oil-rich resource base through conventional and horizontal drilling.Over the long-term, Ring intends to drill and develop its acreage base in an effort to maximize its value and resource potential.  Ring’s portfolio of proved oil and natural gas reserves consists of 91% oil and 9% natural gas. Of those reserves, 45% of the proved reserves are classified as proved developed producing, or “PDP,” 10% are classified as proved developed non-producing, or “PDNP,” and approximately 45% are classified as proved undeveloped, or “PUD.” Through the conversion of undeveloped reserves to developed reserves, Ring will seek to increase production, reserves and cash flow while gaining favorable returns on invested capital.  Recently, Ring has been employing horizontal drilling to some of its acreage with success and plans to continue to do so under appropriate circumstances.

Through December 31, 2017, we increased our proved reserves to approximately 31.9 million BOE (barrel of oil equivalent). As of December 31, 2017, our estimated proved reserves had a pre-tax “PV10” (present value of future net revenues before income taxes discounted at 10%) of approximately $382.1 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $322.5 million. The difference between these two amounts is the effect of income taxes. The Company presents the pre-tax PV10 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 Annual Report when comparing our asset base and performance to other comparable oil and gas exploration and production companies.

·Employ industry leading drilling and completion techniques.Ring’s executive team, which has over 100 years combined experience in the oil and gas industry, intends to utilize new and innovative technological advancements and careful geological evaluation in reservoir engineering to generate value for its stockholders and to build development opportunities for years to come. Improved efficiency through employing technological advancements can provide a significant benefit in a continuous drilling program such as the one Ring contemplates for its current inventory of drilling locations. Additionally, Ring believes that the experience of its executive team will help reduce the time and cost associated with drilling and completing both conventional and horizontal wells, while potentially increasing recovery.

Ring Energy’s Strengths

·High quality asset base in one of North America’s leading resource plays. Ring’s acreage in the Permian Basin is located in Andrews and Gaines Counties, which is in the heart of the Central Basin Platform, and in Culberson and Reeves Counties, which is in the Delaware Basin. As of December 31, 2017, Ring has drilled 243 wells, with 193 being vertical wells and 50 being horizontal wells in its Central Basin acreage and has drilled 10 vertical wells on its Delaware Basin acreage. As of December 31, 2017, estimated net proved reserves were comprised of approximately 91% oil and 9% natural gas.

·De-risked Permian acreage position with multi-year drilling inventory. As of December 31, 2017, Ring has drilled 253 gross operated wells across its leasehold position with a 99.5% success rate. Ring has identified a multi-year inventory of potential drilling locations that will drive reserves and production growth and provide attractive return opportunities. As of December 31, 2017, Ring has 140 identified proven vertical drilling locations and 11 identified proven horizontal locations in Andrews and Gaines Counties and 39 identified proven vertical drilling locations in Culberson and Reeves Counties in its proved undeveloped reserves. It believes it has an additional 396 potential vertical locations based on 10-acre downspacing and an additional 796 potential horizontal drilling locations based on 6 wells per acre or 106 acres per well in Andrews and Gaines Counties and 452 potential vertical locations based on 20-acre downspacing in Culberson and Reeves Counties. The Company views this drilling inventory as de-risked because of the significant production history in the area and well-established industry activity surrounding the acreage.

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·Experienced and proven management team focused on the Permian Basin. The executive team has an average of approximately 25 years of industry experience per person, most of which has been focused in the Permian Basin. The Company believes its management and technical team is one of the principal competitive strengths due to the team’s proven ability to identify and integrate acquisitions, focus on cost efficiencies while managing a large-scale development program and disciplined allocation of capital to high-returning projects. Ring’s Chief Executive Officer Kelly Hoffman has had a successful career in the Permian Basin since 1975 when he started with Amoco Production Company and found further success in West Texas when he co-founded AOCO. In addition, Chairman of the Board, Lloyd T. Rochford, and Director, Stanley M. McCabe, formed Arena Resources, Inc. (“Arena”) in 2001, which operated in the same proximate area as Ring’s Andrews and Gaines County acreage. Arena eventually sold to SandRidge Energy, Inc., in July 2010 for $1.6 billion. Ring’s management team aims to execute a similar growth strategy and development plan by leveraging its industry relationships and significant operational experience in these regions.

·Concentrated acreage position with high degree of operational control. Ring operates essentially 100% of its acreage positions. The operating control allows Ring to implement and benefit from its strategy of enhancing returns through operational and cost efficiencies. Additionally, as the operator of substantially all of its acreage, Ring retains the ability to adjust its capital expenditures based on well performance and commodity price forecasts.

Competitive Business Conditions

We operate in a highly competitive environment for acquiring properties, marketing oil and natural gas, and securing trainedcompetent 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. ThoseIn 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 athis highly competitive environment. Also, there is substantial competition for capital available for investment in the oil
Marketing, Pricing, and natural gas industry.

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. Thereproducers in our areas of operation. We believe there is little risk in our ability to sell all our current production at current prices with a reasonable profit margin. The risk of domestic overproduction at current prices is not deemed significant.prevailing prices. We view our primary pricing risk to be related to a potential declinedeclines in oil and gas prices to a level which could render our current production uneconomical.

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, This commitmentwhich potentially gives such gathering companies certain short-term relative monopolistic powers to set gathering and transportation costs, because obtainingcosts. 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 partythird-party gathering systems forwith respect to our oil production. Some of our oil production is sold through a third party pipelinethird-party pipelines which hashave no regional competition. Allcompetition 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. Our marketing of oil and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted.
For the fiscal year ended December 31, 2017,2023, sales to twothree customers, Occidental Energy Marketing (“Oxy”Phillips 66 Company ("Phillips") and, Enterprise Crude Oil LLC (“Enterprise”("Enterprise"), and NGL Crude Partners ("NGL Crude"), and represented 76%66%, 12%, and 18%10%, respectively, of our oil, natural gas, and natural gas liquids revenues. AtAs of December 31, 2017, Oxy2023, Phillips represented 88%65% of our accounts receivable, Enterprise represented 11% of our accounts receivable and Plains Marketing, L.P. (“Plains”)NGL Crude represented 10%. Effective December 1, 2017, the production previously being sold to Enterprise was sold to Plains.8% of our accounts receivable. We believe that the loss of any of these customerspurchasers would not materially impact our business because we could readily find other purchasers for our oil and gas produced.

natural gas.

Delivery Commitments

As of December 31, 2017,2023, we were not committed to providing a fixed quantity of oil or natural gas under any existing contracts.

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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, affectscan 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. AllThe 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 statesfederal 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 we own and operate properties havehas regulations governing conservation matters, including provisions forsuch 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, each state generallyTexas imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquidsNGLs within its jurisdiction.

jurisdictions.

The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Regulation of Transportation of Oil

Sales of crude oil, condensate, and natural gas liquidsNGLs are not currently regulated and are made at negotiated prices. Nevertheless,prices; however, Congress could reenact price controls in the future.

Our sales of crude oil are affected by the availability, terms, and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The Federal Energy Regulatory Commission, or the FERC,(“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.

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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. Historically, mostAt 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 has been left toby state regulatory boards or agenciesand local governments in thosethe jurisdictions where there is significant gas and oil production, with limited direct regulation by such federal agencies as the Environmental Protection Agency. However, while we believe this generally to be the case for our production activities in Texas,operate. As described below, there are various regulations issued by the Environmental Protection Agency (“EPA”)EPA and other governmental agencies pursuant to these federal statutes that would govern significant spills, blow-outs, or uncontrolled emissions.

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 salt water.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: The Comprehensive Environmental Response, Compensation
Hazardous Substances and Liability Act of 1980,Wastes
CERCLA, also known as “CERCLA” or “Superfund; the Oil Pollution ActSuperfund law, and analogous state laws impose liability on certain classes of 1990; the Resource Conservation and Recovery Act, alsopersons, known as “RCRA,“potentially responsible parties,”; for the Clean Air Act;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 Water Pollution Control Actand 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 1972,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 the Clean Water Act;remediate environmental impacts on properties we currently own and the Safe Drinking Water Actlease or formerly owned or leased (including hazardous substances or wastes disposed of 1974.

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 regulationslaws 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 breachcrude 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 environmentalthe 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 these environmentalimpose 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 broad range“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 cumulative remediesoil 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 include: orderingbecame 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 clean-upnumber 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 spillslaws or wasteregulations 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 restorationother sources of the soilcapital restricting or watereliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to conditions existing priorsecure 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 violation; fines;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 enjoiningthreatened 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 drilling, completionmaterial restrictions to land use and may materially delay or production activities. In certain egregious situationsprohibit 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 agencies may also pursue criminal remedies against usability 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 principal officers.

leases.

Operational Hazards and Insurance

The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow outs,well blow-outs, pipe failures, industrial accidents, and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil spills,releases, chemical releases, natural gas leaks and the discharge of toxic gases. If any
Any of these should occur,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 incur legal defense costs andbe subject to liability under environmental law or common law theories. In addition, these operational risks could be required to pay amounts due to injury, lossresult in the suspension or delay of life, damage or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations.

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.

Current Employees

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, 2017,2023, we had thirty seven108 full-time employees. Our employees are notextremely 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 labor union. 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 considerrecognize that attracting, retaining and developing our relationsemployees 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 be satisfactoryadvance in their technical and have never experienced amanagerial 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 stoppage to attend and/or strike.

We also retain certain engineers, geologists, landmen, pumpersprepare 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 other personnelprofessional challenges. Frequent and transparent communications are the focus at every level of the organization from those on a contract or fee basis as necessarythe 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 our operations.

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 or hotand 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.

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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.

Financial

Available Information

Financial

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 geographic area in which we operate is incorporated herein by reference to Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8, “Financial Statements and Supplementary Data.” We conduct our oil and natural gas activities entirely in the United States.

SEC.
Item 1A:Risk Factors

The following

Item 1A:     Risk Factors
We are subject to various risks and uncertainties may affect our performance, results of operations andin the trading priceordinary course of our common stock.

Risks Relating to the Oilbusiness. The following summarizes significant risks and Natural Gas Industry and Our Business

A substantial or extended decline in oil and natural gas pricesuncertainties that may adversely affect our business, financial condition, or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rateoperations. We cannot assure you that any 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. These markets will likely continue to be volatileevents discussed in the future. The prices we receive for our production,risk factors below will not occur. Further, the risks and the levels of our production, depend on numerous factors beyond our control. These factors include, butuncertainties described below are not limitedthe only ones we face. Additional risks not presently known to the following:

·changes in global supply and demand for oil and natural gas;
·the actions of the Organization of Petroleum Exporting Countries,us or OPEC;
·the price and quantity of imports of foreign oil and natural gas;
·political conditions, including embargoes, in or affecting other oil-producing activity;
·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 unit basis but also may reduce the amount of oil and natural gas that we can produce economically. Lower prices willcurrently deem immaterial may 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 or ability to finance planned capital expenditures.

A substantial percentage of our proven properties are undeveloped; therefore,business. Readers should carefully consider the risk associated with our success is greater than would be the case if the majority of our properties were categorizedfactors included below as proved developed producing.

Because a substantial percentage of our proven properties are proved undeveloped (approximately 45%) or proved developed non-producing (approximately 10%), we will require significant additional capitalwell 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 develop such properties before they may become productive. Further, because of the inherent uncertainties associated with drilling for oilOur Business, Operations, and gas, some of these properties may never be developed to the extent that they result in positive cash flow. Even if we are successful in our development efforts, it could take several years for a significant portion of our undeveloped properties to be converted to positive cash flow.

While our current business plan is to 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.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future success will depend on the success of 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. 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 project uneconomical. Further, many factors may curtail, delay or cancel drilling, including the following:

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Strategy

·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.

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 if compared to conventionalvertical drilling.

Our operations utilizeuse 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 more conventional wells;
·landing our wellbore in the desired drilling zone;
·staying in the desired drilling zone while drilling horizontally through the formation;
·running our casing the entire length of the wellbore; and
·being able to run tools and other equipment consistently through the horizontal wellbore.

•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 stimulate the planned number of stages in a horizontal or lateral well bore;
·the ability to run tools the entire length of the wellbore during completion operations; and
·the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

•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 recently purchased properties are materially inaccurate, it could have a significant impact on future operations and earnings.

We have aggressively expanded our base of producing properties.

The successful acquisition of producing properties requires assessments of many factors, which are inherently inexact and may be inaccurate, including the following:

·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; and
·potential environmental and other liabilities.

•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 assessmentassessments will not reveal all existing or potential problems, nor will itthey permit us to become familiar enough with the potential properties we may acquire to assess fully their capabilities and deficiencies. As noted previously, weWe 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.

Decreases in oil and natural gas prices may require us to take write-downs of the carrying values of our oil and natural gas properties, potentially requiring earlier than anticipated debt repayment and negatively impacting the trading value of our securities.

Accounting rules require that we review periodically the 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 carrying value of our oil and natural gas properties. Because our properties serve as collateral for advances under our existing credit facility, a write-down in the carrying values of our properties could require us to repay any outstanding debt earlier than we would otherwise be required. A write-down could also constitute a non-cash charge to earnings. It is likely the cumulative effect of a write-down could also negatively impact the trading price of our securities.

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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 materially 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 on the date of the estimate. 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 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 securities. These factors could also result in the acceleration of debt repayment and a reduction in our borrowing base under our credit facility.

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. There is no wayWe 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 (45%) 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 underinsuredunder insured events could materially and adversely affect our business, financial condition orand 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 and shoreline contamination;
·abnormally pressured formations;
·mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;
·fires and explosions;
·personal injuries and death; and
·natural disasters.

•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 to 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.

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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. We may be required to make large expenditures to comply with governmental regulations. 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 the 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 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 or 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.

If our indebtedness increases, it could reduce our financial flexibility.

We have a credit facility in place with $60 million in commitments for borrowings and letters of credit. As of December 31, 2017, no amount was outstanding on our credit facility. If in the future we 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 could be used to service the indebtedness;
·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 quarterly redeterminations. If we use our credit facility, we could be forced to repay a portion of our bank borrowings due to redeterminations of our borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

Unless we replace our oil and natural gas reserves, our reserves and production will decline which would adversely affect our cash flows and income.

as reserves are produced.

Unless we conduct successful development, exploitationexploration and explorationdevelopment 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 exploitingproducing our current reserves and economically finding or acquiring additional recoverable reserves. If we are unable to develop, exploit, 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.

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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 ultimately 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, the majoritysome of our production is sold to marketers and other purchasers that have access to nearby pipeline facilities. However, as we begin to further developMuch of our properties, we may find production is in areas with limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking or requiring compression facilities.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 price)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.

Hedging transactions

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 potential gains.

In orderability to reduce commodity price uncertaintyoperate 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 flow predictabilityflows.
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 marketingrelease 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 crudeoperations. 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 enter into crudehave 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 price hedging arrangementsproduction 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
31
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 expected production. While intendedbank borrowings due to reduceredeterminations 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 effects of volatile crude oil and natural gas prices, such transactionsequity or debt capital markets to meet our obligations.
Our plans for growth may limit our potential gains if crude oil and natural gas prices rise overinclude accessing the price established by the arrangements. As of December 31, 2017, we had hedging arrangements in place covering 2,000 barrels of oil per day for calendar year 2018. The hedges we have in place arecapital markets. Recent reluctance to invest in the form of costless collars. “Costless collars” are the combination of two options, a put option (floor)exploration and call option (ceiling) with the options structured so that the premium paidproduction sector based on market volatility, historically perceived underperformance, and ESG trends, among other things, has raised concerns regarding capital availability for the put optionsector. 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 be offset, bylargely or at all, the premium received from selling the call option. We had one costless collar for 1,000 barrelsimpacts of oil per day with a put priceany future inflationary pressures on our operating costs and capital expenditures and, in turn, our cash flows and results of $49.00operations.
Risks Relating to Technology and a call price of $54.60. We had another costless collar for 1,000 barrels of oil per day with a put price of $51.00 and a call price of $54.80.

Cybersecurity

We rely on computer and telecommunications systems, and failures in our systems or cyber security attacks or breaches could materially disrupt our business operations.

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, process and record financial and operating data, 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 cyber securitycybersecurity attacks or breaches, computer viruses or malware. We believemalware that could result in disruption of our business operations and/or financial loss. Although we have positive relations withutilize various procedures and controls to monitor and protect against these threats and mitigate our vendorsexposure to such threats, there can be no assurance that these procedures and maintain satisfactory anti-viruscontrols will be sufficient in preventing security threats from materializing and malware software and controls.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.

Competition is intense in the oil and gas industry.

We operate in a highly competitive environment for acquiring properties and marketing oil and natural gas. Our competitors include multinational oil and gas companies, major oil and gas companies, independent oil and 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, stiff 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 gas reserves or in our marketing of production, then our financial condition and operation results may be adversely affected.

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If oil and natural gas prices decrease, we may be required to record additional write-downs of the carrying value of our oil and gas properties in the future.

We follow the full cost method of accounting for our oil and 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 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 un-weighted, 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 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 expense. During the year ended December 31, 2016, we recorded a non-cash write down of $56.5 million, respectively. We did not record a write down during 2017. 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 carrying value of such assets and an equivalent charge to earnings.

It is difficult to predict with reasonable certainty the amount of expected 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.

Risks Relating to Our Common Stock

We have no plansrecently 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. Shareholders may not receive funds without selling their shares.

We do not anticipate paying any cash dividends on our common stock in the foreseeable future.

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 credit facility prohibits us from paying dividends.

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 shareholderstockholder 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’sboard 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 companyCompany 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 stock holdersstockholders 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:
Item 1B: Unresolved Staff Comments

None.

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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

Item 2:     Properties
General Background

Ring is currently engaged in oil and natural gas development, production, acquisition, exploration, development and production, withexploration activities currently focused in Texas. Our focus will be on developing our existing properties, while continuing to pursue acquisitionsthe Permian Basin of oil and gas properties with significant upside potential.

Texas.

Management’s Business Strategy Related to Properties

Our goal is to increase shareholderstockholder value by investing in oil and natural gas projects with attractive rates of return on capital employed. We plan to achieve this goal by exploiting and developing our existing oil and natural gas properties and pursuing strategic acquisitions of additional properties. Specifically, we have focused, and plan to continue to focus, on the following:

Developing and Exploiting Existing Properties

We believe that there is significant value to be created by drilling the identified undeveloped opportunities on our properties. As of December 31, 2017,2023, we owned interests in a total of 22,30776,484 gross (18,337(65,462 net) developed acres and operate essentially allthe vast
35
majority of our proved undeveloped reserves.acreage position. In addition, as of December 31, 2017,2023, we owned interests in approximately 100,68819,643 gross (71,454(15,073 net) undeveloped acres. While our focus will be toward growth through additional acquisitions and leasing, our long termnear-term plans includeare focused on drilling wells on our existing acreage to develop the potential contained therein.

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 developed and refined an acquisition program designed to increase reserves and complement our existing core properties. We have an experienced team of management, engineering, geoscience, and engineeringland 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 Operations

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 Gaines County leasesWard Counties, Texas –In 2011, we acquired a 100% working interest and a 75% net revenue interest in theour 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 leases. The working interests range from 1-100% and the net revenue interests range from 1-80%. In total as of December 31, 2017, we own 102,777 gross (69,874 net), acres with 11,917 gross (8,102 net) acres developed and held by production and the remaining 90,860 gross acres (61,772 net) being undeveloped. We believe the Andrews and Gaines County leases contain a considerable number of remaining potential drilling locations. Our reserve estimates include 140 proven vertical and 11 horizontal PUD wells. Our reserve estimates include the capital costs required to develop these wells. Our reserve estimates also include secondary recovery (waterflood) reserves in relation to some of our Andrews County acreage.

Culberson and Reeves County leases –leases. In 2015,2022, we acquired properties consisting of 19,983 grossapproximately 37,000 net acres, (19,679 net) with an average working interest of 98%99% and an average net revenue interest of 79%. Since that time,88% for oil and 96% for natural gas in our initial leases in Crane, Winkler, and Ward counties. In 2023, we have acquired additional undeveloped acreageproperties in and around our Culberson and Reeves County leases. In total asEctor County. As of December 31, 2017,2023, we own 20,218owned interests in a total of 63,912 gross (19,917(56,711 net) developed acres and 3,385 gross (2,668 net) undeveloped acres with 10,390an 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 (10,235 net) acres developedvertical and held by production197 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 remaining 9,828 gross (9,682 net) acres being undeveloped. We believe the Culbersonverticals produce from a variety of conventional pay sands including Holt, Glorieta, Clear Fork, Wichita Albany, Tubb, Wolfcamp and Reeves County leases contain a considerable number of remaining potential drilling locations. Our reserve estimates include 39 vertical PUD wells. Our reserve estimates include the capital costs required to develop these wells.

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 willis usually be conducted and any significant defects will beare 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 instead 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 will materially interfere with our use of these properties.

Summary of Oil and Natural Gas Reserves

As of December 31, 2017,2023, our estimated proved reserves had a pre-tax PV10PV-10 value (present value discounted at 10%) of approximately $382.1$1,647.0 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $322.5$1,399.2 million, 100%over 99.6% of which relates to our properties in the Permian Basin in Texas. We spent approximately $190.1$544.2 million on acquisitions and capital projects during 20162023 and 2017.2022. We expect to further develop these properties through additional drilling.

The following table summarizes our total net proved reserves, pre-tax PV10PV-10 value and Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2017. All2023. 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 
_____________________________
(1)Six Mcf is deemed the Stateequivalent of Texas.

Oil
(Bbl)		  Natural Gas
(Mcf)		  Total
(Boe)		  Pre-Tax PV10
Value		  Standardized
Measure of
Discounted Future
Net Cash Flows		 
 28,943,742   18,037,489   31,949,990  $382,101,384  $322,465,119 

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 wereare based on internallyreports independently determined and prepared reports and audited by Cawley, Gillespie & Associates, Inc. or Williamson Petroleum Consultants, Inc.("CGA"), independent petroleum engineers. The estimatesThese 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) 
Balance, December 31, 2015  22,312,450   12,539,600 
Purchase of minerals in place  -   - 
Improved recovery  79,130   60,847 
Extensions and discoveries  3,635,312   2,305,548 
Production  (728,051)  (900,089)
Revisions of estimates  (299,741)  2,448,943 
Balance, December 31, 2016  24,999,100   16,454,849 
         
Purchase of minerals in place  21,855   - 
Improved recovery  624,660   865,178 
Extensions and discoveries  8,127,609   4,258,474 
Sale of minerals in place  (26,593)  (251,071)
Production  (1,311,727)  (761,517)
Revisions of estimates  (3,491,162)  (2,528,424)
Balance, December 31, 2017  28,943,742   18,037,489 

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Oil (Bbl)
Gas (Mcf)(2)
Natural Gas Liquids (Bbl)(2)
Boe(1)
Balance, December 31, 202165,838,60971,773,789—77,800,907
Purchase of minerals in place28,086,920108,456,10716,715,62662,878,564
Extensions, discoveries and improved recovery628,978522,17852,810768,818
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)6,708,5591,186,108
Balance, December 31, 202288,704,743157,870,44923,105,658138,122,143
Purchase of minerals in place6,543,6403,372,9651,089,3828,195,183
Extensions, discoveries and improved recovery3,098,8454,113,4801,014,3434,798,768
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, 202382,141,277146,396,32223,218,564129,759,229

_____________________________
(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, 
  2016  2017 
       
Oil (Bbls)        
Developed  8,479,000   15,321,600 
Undeveloped  16,520,100   13,622,142 
         
Total  24,999,100   28,943,742 
         
Natural Gas (Mcf)        
Developed  10,481,300   12,674,200 
Undeveloped  5,973,549   5,363,289 
         
Total  16,454,849   18,037,489 
         
Total (Boe)        
Developed  10,225,883   17,433,967 
Undeveloped  17,515,691   14,516,023 
         
Total  27,741,575   31,949,990 

For the years ended December 31,
20232022
Oil (Bbl)
Developed56,029,03957,012,137
Undeveloped26,112,23831,692,606
Total82,141,27788,704,743
Natural Gas (Mcf)
Developed99,896,022106,399,050
Undeveloped46,500,30051,471,399
Total146,396,322157,870,449
Natural Gas Liquids (Bbl)
Developed15,449,90715,332,804
Undeveloped7,768,6577,772,854
Total23,218,56423,105,658
Total (Boe) (1)
Developed88,128,28490,078,116
Undeveloped41,630,94548,044,027
Total129,759,229138,122,143
(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 generally accepted accounting principles.

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 or the present value of our oil and natural gas properties.

Our reserve estimates of reserves and future cash flow as of December 31, 2017 are2023 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 $47.934 for$74.70 per Bbl of WTI oil posted and $3.614 for gas compared to $39.169 for oil and $2.426 for gas as$2.637 per MMBtu of Henry Hub natural gas. As of December 31, 2016.

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.

39
The standardized measure of discounted future net cash flows relating to the proved oil, and natural gas and NGLs reserves are shown below.

December 31, 2017  2016 
Future cash flows $1,452,588,325  $1,019,179,570 
Future production costs  (476,753,026)  (318,378,291)
Future development costs  (132,347,551)  (140,511,904)
Future income taxes  (131,646,889)  (150,765,686)
Future net cash flows  711,840,859   409,523,689 
10% annual discount for estimated timing of cash flows  (389,375,740)  (249,728,651)
         
Standardized Measure of Discounted Cash Flows $322,465,119  $159,795,038 

16

Standardized Measure of Discounted Future Net Cash Flows

December 31,202320222021
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 flows3,098,378,852 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.

  2017  2016 
Beginning of the year $159,795,038  $172,686,441 
Purchase of minerals in place  179,441   - 
Extensions, discoveries and improved recovery, less related costs  77,967,484   42,388,078 
Development costs incurred during the year  181,887,252   43,085,217 
Sales of oil and gas produced, net of production costs  (50,721,338)  (19,477,828)
Sales of minerals in place  (508,331)  - 
Accretion of discount  22,991,164   11,995,583 
Net changes in price and production costs  108,595,790   (59,100,870)
Net change in estimated future development costs  (60,604,384)  (13,064,453)
Revision of previous quantity estimates  (56,812,326)  1,619,437 
Revision of estimated timing of cash flows  (58,123,153)  (30,342,680)
Net change in income taxes  (2,181,518)  10,006,113 
         
End of the Year $322,465,119  $159,795,038 

Proved Reserves

We have approximately 31.9 million BOE of proved reserves, which consist of approximately 91% oil and 9% natural gas, are summarized below as of December 31, 2017, on a net pre-tax PV10 value and

Changes in Standardized Measure of Discounted Future Net Cash Flows basis.
202320222021
Beginning of the year$2,272,113,518 $1,137,364,848 $555,871,253 
Purchase of minerals in place141,738,066 996,313,882 33,688,718 
Extensions, discoveries and improved recovery57,607,609 20,447,842 79,003,885 
Development costs incurred during the year70,697,664 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 discount277,365,650 133,209,763 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 costs37,865,811 (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 taxes253,696,749 (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
PD55,820,27599,572,22115,413,05587,828,70168 %$1,256,679 $1,067,574 $145,470 
PUD26,112,23846,500,3007,768,65741,630,94532 %384,353 326,515 416,478 
Total Proved:81,932,513146,072,52123,181,712129,459,646100 %$1,641,032 $1,394,089 $561,948 
New Mexico
PD208,764323,80136,852299,583— %$5,999 $5,097 $115 
PUD————— %— — — 
Total Proved:208,764323,80136,852299,583— %$5,999 $5,097 $115 
Total
PD56,029,03999,896,02215,449,90788,128,28468 %$1,262,679 $1,072,670 $145,586 
PUD26,112,23846,500,3007,768,65741,630,94532 %384,353 326,515 416,478 
Total Proved:82,141,277146,396,32223,218,564129,759,229100 %$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, 2017, all of our reserves are in Texas. Proved reserves had a net pre-tax PV10 value of2023, approximately $382.1 million and Standardized Measure of Discounted Future Net Cash Flows of approximately $322.5 million.

As of December 31, 2017, approximately 45%68% of the proved reserves have been classified as proved developed producing, or “PDP”. Proved developed non-producing, or “PDNP” reserves constitute approximately 10%PD and proved undeveloped, or “PUD”, reserves constitute approximately 45%,the remaining 32% are PUD.

As of the proved reserves.

TotalDecember 31, 2023, our total proved reserves had a net pre-tax PV10PV-10 value as of December 31, 2017 of approximately $382.1$1,647.0 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $322.5$1,399.2 million. Approximately $218.9$1,262.7 million and $184.7$1,072.7 million, respectively, of total proved reserves are associated with the PDPPD reserves, which is approximately 45%77% of the total proved reserves’ pre-tax PV10 value. An additional $59.4 million and $50.1 million, respectively, are associated with the PDNP reserves, which is approximately 10% of total proved reserves’ pre-tax PV10PV-10 value. The remaining $103.8$384.4 million and $87.6$326.5 million, respectively, are associated with PUD reserves.

Proved Undeveloped Reserves

Our reserve estimates as of December 31, 20172023 include 14.5 million BOEapproximately 41.6 MMBoe as proved undeveloped reserves.PUDs. As of December 31, 2016,2022, our reserve estimates included approximately 17.5 million BOE48.0 MMBoe as proved undeveloped reserves. FollowingIn 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, 20162022 to December 31, 2017.

Conversion2023.

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 2,994,453 BOE of reservesapproximately $90.3 million to convert 27 properties from PUD to PDP or PDNPPD through development.

Net downward revision These 27 properties produced 573 MBoe during the year ended December 31, 2023, and have reserves of 1,874,828 BOE primarily as a result of reduction in waterflood area.

Improved Recovery and Extension of approximately 1,869,614, primarily resulting from the addition of new horizontal reserves..

17

Our proved reserves7,068 MBoe as of December 31, 2017 are summarized2023.

41
•Extensions. In 2023, extensions of 3.7 MMBoe were primarily the result of the successful operated drilling program and non-operated activity in the table below.

  Oil
(Bbl)		  Gas
(Mcf)		  Total
(Boe)		  % of Total
Proved		  Pre-tax PV10
(In thousands)		  Standardized
Measure of
Discounted Future
Net Cash Flows (In
thousands)		  Future Capital
Expenditures
(In thousands)		 
                      
PDP  12,515,600   11,274,200   14,394,633   45% $218,905  $184,740  $- 
PDNP  2,806,000   1,400,000   3,039,333   10%  59,390   50,120   5,376 
PUD  13,622,142   5,363,289   14,516,024   45%  103,806   87,605   115,171 
                             
Total Proved:  28,943,742   18,037,489   31,949,990   100% $382,101  $322,465  $120,547 

Estimated Costs RelatedNorthwest 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 Conversion of Proved Undeveloped Reserveschanges in price and 4.1 MMBoe (84%) related to Proved Developed Reserves

changes in performance and other economic factors.

The following table indicates projected reserves that we currently estimate will be converted from proved undeveloped or proved developed non-producing to proved developed, as well as the estimated costs per year involved in such development.

Year Estimated Oil
Reserves
Developed (Bbls)		  Estimated Gas
Reserves
Developed (Mcf)		  Total Boe  Estimated
Development Costs		 
             
2018  6,702,408   4,695,800   7,485,041  $57,789,006 
2019  4,459,768   2,058,502   4,802,852   58,614,753 
2020  5,265,966   8,987   5,267,464   15,943,792 
                 
   16,428,142   6,763,289   17,555,357  $132,347,551 

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
YearEstimated Oil
Reserves
Developed (Bbl)		Estimated Gas
Reserves
Developed (Mcf)		Estimated NGL
Reserves
Developed (Bbl)		Total BoeEstimated
Development Costs
202410,512,0718,637,0301,538,11713,489,693$157,234,213 
20258,815,1367,676,5961,838,16711,932,736126,315,450
20264,047,98015,057,9842,286,8118,844,45573,672,123
20272,737,05115,128,6902,105,5627,364,06151,012,096
Total26,112,23846,500,3007,768,65741,630,945$408,233,882 
Preparation and Internal Controls Over Reserves Estimates

Our

All the proved oil and natural gas reserves data anddisclosed in this Report are based on reserve estimates were compileddetermined and prepared internally and audited by third partyour independent consultants,reserve engineers, Cawley, Gillespie & Associates, Inc. or Williamson Petroleum Consultants, Inc.(“CGA”), as describeda leader of petroleum property analysis for industry and financial institutions. CGA was founded in more detail herein, in compliance with SEC definitions1960 and guidance and in accordance with generally acceptedperforms consulting petroleum engineering principles. Theservices under Texas Board of Professional Engineers Registration No. F-693. Within CGA, the technical persons employed by Cawley, Gillespie & Associates, Inc.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 Williamsonhas 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 Consultants, Inc., metEngineering. Mr. Meekins meets or exceeds the requirements regarding qualifications, independence, objectivityeducation, training, and confidentialityexperience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Natural Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our reserves estimates are prepared by examinationEngineers; he is proficient in judiciously applying industry standard practices to engineering and evaluation of production data, production decline curves, reservoir pressure data, logs, geological data,geoscience evaluations as well as applying SEC and offset analogies. other industry reserve definitions and guidelines.
The third party independent consultants are provided full access to complete and accurate information pertaining to the property, and to all applicable personnel of the Company. Our reserves estimates and process for developing such estimates are reviewed and approved by its Vice President of Operations, Daniel D. Wilson, a petroleum engineer, and Chief Executive Officer, Kelly Hoffman, to ensure compliance with SEC disclosure and internal control requirements and to verify the independence of the third party consultants. Mr. Daniel Wilson, a petroleum engineer and businessman, has over 30 years of experience in operating, evaluating and exploiting oil and gas properties. Mr. Kelly Hoffman has over 40 years of well-rounded experience in the oil and gas industry. Our management is ultimately responsible for reserve estimates and reserve disclosures and ensuring that they are in accordance with the applicable regulatory requirements and industry standards and practices.

Estimates ofproved oil and natural gas reserves disclosed in this Annual Report are projections based on a process involving anreserve estimates determined and prepared by our independent third party engineering firm’s collectionreserve engineers primarily using decline curve analysis to determine the reserves of all required geologic, geophysical, engineeringindividual 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 such firm’s complete external preparationcost information and property ownership interests. This data was reviewed by various levels of all requiredmanagement 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 are forward-lookingconclusions before the reserves were included in nature. These reports rely upon various assumptions,this Annual Report. The accuracy of the reserve estimates is dependent on many factors, including assumptions required by the SEC, such as constant oilfollowing:
•the quality and natural gas prices, operating expensesquantity of available data and future capital costs. The process also requires assumptions relating to availabilitythe engineering and geological interpretation of fundsthat data;
•estimates regarding the amount and timing of capital expendituresfuture 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 developmentoverseeing the preparation of our proved undeveloped reserves. These reports should not be construed asreserves estimates. He has a Bachelor of Science degree in Petroleum Engineering from the current market valueUniversity of our reserves. The processTexas with over 17 years of practical industry experience, including over 13 years of estimating oil and natural gas reserves is also dependent on geological, engineering and economic data for each reservoir. Becauseevaluating reserve information. He has been a member of the uncertainties inherentSociety 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 interpretationinternally 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 this data, we cannot be certainEngineering 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 the reserves will ultimately be realized. Our actual results could differ materially.

18
prepare estimates of proved reserves.

Summary of Oil and Natural Gas Properties and Projects

Production Summary

Our estimated average daily production for the month

43
Acreage

The following table summarizes our gross and net developed and undeveloped acreage atas of December 31, 20172023 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.

  Developed Acreage  Undeveloped Acreage  Total Acreage 
  Gross  Net  Gross  Net  Gross  Net 
Total  22,307   18,337   100,688   71,454   122,995   89,791 

excluded, as it is de minimis.

Developed AcreageUndeveloped AcreageTotal Acreage
GrossNetGrossNetGrossNet
Central Basin Platform63,91256,7113,3852,66867,29759,379
Northwest Shelf12,5728,75116,25812,40528,83021,156
Total76,48465,46219,64315,07396,12780,535
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
202420252026
GrossNetGrossNetGrossNet
Central Basin Platform1,8001,0461,240100720239
Northwest Shelf8,4751,4818,9463,4963,015454
Total10,2752,52710,1863,5963,735693
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Production History

The following table presents the historical information aboutregarding our produced oil, natural gas and natural gas liquid volumes for the years ended December 31, 2023, 2022, and 2021:
Years ended December 31,
202320222021
Oil (Bbls)
Central Basin Platform2,347,0681,409,211867,835
Delaware Basin (2)
25,74381,936104,129
Northwest Shelf2,207,1311,968,6931,714,976
Total4,579,9423,459,8402,686,940
Natural Gas (Mcf)(1)
Central Basin Platform3,940,1071,563,808171,690
Delaware Basin (2)
11,26596,516288,918
Northwest Shelf2,387,7862,428,3182,074,580
Total6,339,1584,088,6422,535,188
Natural Gas Liquids (Bbls)(1)
Central Basin Platform703,818227,996—
Delaware Basin (2)
2,8673,718—
Northwest Shelf270,167139,615—
Total976,852371,329—
Total production (Boe)
Central Basin Platform3,707,5711,897,842896,087
Delaware Basin (2)
30,488101,740152,282
Northwest Shelf2,875,2622,513,0282,060,739
Total6,613,3214,512,6103,109,108
Daily production (Boe/d)
Central Basin Platform10,1585,2002,455
Delaware Basin (2)
84279417
Northwest Shelf7,8776,8855,646
Total18,11912,3648,518
(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, volumes.

  Years Ended December 31, 
  2015  2016  2017 
          
Oil production (Bbls)  664,612   728,051   1,311,727 
Natural gas production (Mcf)  472,509   900,089   761,517 
Total production (Boe)  743,363   878,066   1,438,647 
Daily production (Boe/d)  2,037   2,406   3,941 
Average sales price:            
Oil (per Bbl) $44.90  $39.28  $48.97 
Natural gas (per Mcf)  2.48   2.50   3.23 
Total (per Boe)  41.72   35.13   46.36 
Average production cost (per Boe) $13.40  $11.24  $11.11 
Average production taxes (per Boe)  1.97   1.71   2.19 

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.
45
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,
202320222021
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,
202320222021
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 barrels “Bbl”.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 thousand cubic feet “Mcf”.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.Boe. The average production costs above are calculated by dividing production costs by total production in BOE.

Boe.

Productive Wells

The following table presents our ownership atas of December 31, 2017,2023 in productive oil and natural gas wells (a net well is our percentage ownership of a gross well). AllOver 99.8% of such wells are in the Permian Basin in Texas.

Oil Wells  Gas wells  Total Wells 
Gross  Net  Gross  Net  Gross  Net 
 409   290   -   -   409   290 

19

Oil WellsGas wellsTotal Wells
GrossNetGrossNetGrossNet
1,02384720171,043864

Drilling Activity

During 2017,2023, as operator, we drilled 47a total of 31.00 gross (29.75 net) wells. Of this, 14.00 gross (12.75 net) horizontal developmentSan Andres wells were in the Northwest Shelf (nine 1.0-mile laterals and 5 vertical developmentfive 1.5-mile laterals.) and 17.00 gross (17.00 net) wells and 3 sciencewere in the Central Basin Platform, of which six were horizontal San Andres wells in Texas. We completedAndrews County, Texas (two 1.0-mile laterals and placed on production the 27 horizontal wellsfour 1.5-mile laterals) and 711.00 were vertical wells leaving 20 horizontalin 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.
46
The table below contains information regarding the number of operated wells drilled but not yetand/or participated in during the periods indicated.
For the year ended December 31,
202320222021
GrossNetGrossNetGrossNet
Exploratory
Productive——————
Dry——————
Development
Productive31.0029.7532.0031.3511.009.91
Dry——————
Total
Productive31.0029.7532.0031.3511.009.91
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,
202320222021
GrossNetGrossNetGrossNet
Exploratory
Productive——————
Dry——————
Development
Productive5.000.593.000.332.000.23
Dry——————
Total
Productive5.000.593.000.332.000.23
Dry——————
Present Activities
We had no operated wells in the process of being drilled or completed and on production as of December 31, 2017.

During 2016, we drilled 3 horizontal development wells and 9 vertical development wells in Texas. We completed and placed on production the 3 horizontal wells and 8 vertical wells, leaving 2 vertical wells drilled but not yet completed and on production as of December 31, 2016.

During 2015, we drilled 9 vertical development wells in Texas. We completed and placed on production 20 wells, leaving 1 well drilled but not yet completed and on production as of December 31, 2015. All of the wells drilled in 2015 were successful.

2023.

Cost Information

We conduct our oil and natural gas activities entirely in the United States. As noted previously in the table appearing under “Production History”Prices and Production Costs”, our average production costs including lease operating expenses, gathering, processing and transportation ("GPT") and ad valorem, per BOE,Boe, were $13.40, $11.24$11.70 and $11.11 during$12.02 for the years ended December 31, 2015, 20162023 and 2017,2022, respectively, and our average production taxes, per BOE,Boe, were $1.97, $1.71$2.74 and $2.19$3.80 for the years ended December 31, 2015, 20162023 and 2017,2022, respectively. These amounts are calculated by dividing our total production costs or total production taxes by our total volume sold, in BOE.

Boe.

47
Costs incurred for property acquisition, exploration and development activities during the years ended December 31, 2016 and 2017 are shown below.

  2016  2017 
       
Acquisition of proved properties $10,193,927  $28,682,298 
Acquisition of unproved properties  -   - 
Exploration costs  -   - 
Development costs  26,554,171   124,680,469 
Total Costs Incurred (1) $36,748,098  $153,362,767 

(1) Total costs incurred include $168,618 and ($224,562) for the years ended December 31, 20162023, 2022 and 2017, respectively, for Kansas properties that were sold during 2017.

2021 are shown below:

202320222021
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 properties152,559,314 129,332,155 51,302,131 
Total costs incurred$235,460,214 $308,719,645 $52,670,568 

Other Properties and Commitments

Our

Effective January 1, 2021, the Company moved its corporate headquarters to The Woodlands, Texas. Prior to this, our principal executive offices are in leased office spacewere in Midland, Texas. The leasedThose offices now serve as an operations office. Our office space consists of approximately 15,000 square feet. Additionally, we lease office space in Tulsa, Oklahoma which serveswas terminated as our primary accounting office consisting of approximately 3,700 square feet. We also lease office space in Andrews, Texas for a field office consisting of approximately 2,000 square feet. We expect our current office space to be adequate as we move forward.

March 31, 2021.
Item 3:Legal Proceedings

In the ordinary course of business, we may be, from time to time, a claimant or

Item 3:     Legal Proceedings
The Company is a defendant in various legal proceedings. We do not presentlya 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 any material litigation pending or threatened requiring disclosure under this item.

begun taking depositions and are conducting discovery.

Item 4:Mine safety disclosures

Item 4:     Mine Safety Disclosures
Not applicable.

20

PART II

Item 5:Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

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 MKTAmerican under the trading symbol “REI.” We have only one class of common stock, and we have 50,000,000 authorized but unissued shares of preferred stock. The table below sets forth for the periods indicated the quarterly high and low sale prices of our common stock as reported on the NYSE MKT.

NYST MKT

Period High Sale  Low Sale 
1st Quarter 2016 $6.83  $4.04 
2nd Quarter 2016  9.85   4.96 
3rd Quarter 2016  11.01   7.59 
4th Quarter 2016  13.36   9.23 
         
1st Quarter 2017 $13.81  $9.44 
2nd Quarter 2017  13.75   10.70 
3rd Quarter 2017  14.49   11.86 
4th Quarter 2017  14.80   11.87 
         
1st Quarter 2018 (through March 13) $15.83  $13.04 

Performance Graph

The following graph comparesreflects a comparison of the cumulative 5-year total stockholder return attained by stockholders on Ring’sof our common stock relative to the cumulative total returns of the S&P 500 indexIndex and that of a selected peer group, named below.the S&P Oil and Gas Exploration and Production Select Industry Index ("SPSIOP"). The graph assumes athe investment of $100 investment at the closing price on December 31, 2012,2018 in our common stock and each index and the reinvestment of all dividends, on the date of payment without commission.if any. This table is not intended to forecast future performance of our common stock.

*The peer group consists of: Callon Petroleum Company, Rex Energy Corporation, Approach Resources, Inc., Resolute Energy Corporation and Earthstone Energy, Inc., all of which are in the oil and gas exploration and production industry.

48
1223
The performance graph above is furnished and not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and will not be incorporated by reference into any registration statement filed under the Securities Act of 1933 unless specifically identified therein as being incorporated by reference. The performance graph is not solicitation material subject to Regulation 14A.

21
14A of the Exchange Act.

Record Holders

As of February 23, 2018,March 7, 2024, there arewere approximately 9,04684 holders of record of our common stock. AsThis is the number of March 12, 2018, 3,667,628record holders in the records of our transfer agent. It does not include holders of shares or approximately 6.1%, of the 60,388,029 shares issued and outstanding as of such date are held by management or affiliated parties.

via brokerage accounts.

Dividend Policy

We have not paid any dividends on our common stock during the last three years, and we do not currently anticipate paying any cash dividends on our common stock in the foreseeable future.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 boardBoard of directorsDirectors and will depend upon various factors, including our business, financial condition, results of operations, financial condition, capital requirements and investment opportunities. In addition, our credit facility prohibits us from paying dividends.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table sets forth information concerningcontains provisions limiting our executive stock compensation plans as of December 31, 2017.

  Restricted
stock granted
that has not
vested		  Number of securities
to be issued upon
exercise of
outstanding options		  Weighted-average
exercise price of
outstanding options		  Number of securities remaining
available for future issuance under
compensation plans (excluding
securities in column (a))		 
             
Equity compensation plans approved by security holders  330,900   3,193,000  $6.07   1,040,200 
                 
Equity compensation plans not approved by security holders  -   -   -   - 
                 
Total  330,900   3,193,000  $6.07   1,040,200 

Description of Our Long Term Incentive Plan

The Ring Energy, Inc. Long Term Incentive Plan (the “Plan”) was in existence with Stanford Energy, Inc. (“Stanford”) and was adopted by the Board of Directors on June 27, 2012, and assumed by the Company upon the acquisition of Stanford. The Plan was also approved by vote of a majority of shareholders on January 22, 2013. The following is a summary of the material terms of the Plan.

Shares Available

Our Plan currently authorizes 5,000,000 shares of our common stock for issuance under the Plan. If any shares of common stock subjectability to an Awardpay dividends unless certain conditions are forfeited or if any Award based on shares of common stock is otherwise terminated without issuance of such shares of common stock or other consideration in lieu of such shares of common stock, the shares of common stock subject to such Award shall to the extent of such forfeiture or termination, again be available for Awards under the Plan if no participant shall have received any benefits of ownership in respect thereof. The shares to be delivered under the Plan shall be made available from (a) authorized but unissued shares of common stock, (b) common stock held in the treasury of the Company, or (c) previously issued shares of common stock reacquired by the Company, including shares purchased on the open market, in each situation as the Board of Directors or the Compensation Committee may determine from time to time at its sole option.

Administration

The Committee shall administer the Plan with respect to all eligible individuals or may delegate all or part of its duties under the Plan to a subcommittee or any executive officer of the Company, subject in each case to such conditions and limitations as the Board of Directors may establish. Under the Plan, “Committee” can be either the Board of Directors or a committee approved by the Board of Directors.

22
met.

Eligibility

Awards may be granted pursuant to the Plan only to persons who are eligible individuals at the time of the grant thereof or in connection with the severance or retirement of Eligible Individuals. Under the Plan, “Eligible Individuals” means (a) employees, (b) non-employee Directors and (c) any other person that the Committee designates as eligible for an Award (other than for Incentive Options) because the Person performs bona fide consulting or advisory services for the Company or any of its Subsidiaries (other than services in connection with the offer or sale of securities in a capital raising transaction).

Stock Options

Under the Plan, the plan administrator is authorized to grant stock options. Stock options may be either designated as non-qualified stock options or incentive stock options. Incentive stock options, which are intended to meet the requirements of Section 422 of the Internal Revenue Code such that a participant can receive potentially favorable tax treatment, may only be granted to employees. Therefore, any stock option granted to consultants and non-employee directors are non-qualified stock options.

Options granted under the Plan become exercisable at such times as may be specified by the plan administrator. In general, options granted to participants become exercisable in five equal annual installments, subject to the optionee’s continued employment or service with our company. However, the aggregate value (determined as of the grant date) of the shares subject to incentive stock options that may become exercisable by a participant in any year may not exceed $100,000.

Each option will be exercisable on such date or dates, during such period, and for such number of shares of common stock as shall be determined by the plan administrator on the day on which such stock option is granted and set forth in the option agreement with respect to such stock option; provided, however, the maximum term of options granted under the Plan is ten years.

Restricted Stock

Under the Plan, the plan administrator is also authorized to make awards of restricted stock. Before the end of a restricted period and/or lapse of other restrictions established by the plan administrator, shares received as restricted stock will contain a legend restricting their transfer, and may be forfeited in the event of termination of employment or upon the failure to achieve other conditions set forth in the award agreement.

An award of restricted stock will be evidenced by a written agreement between us and the participant. The award agreement will specify the number of shares of common stock subject to the award, the nature and/or length of the restrictions, the conditions that will result in the automatic and complete forfeiture of the shares and the time and manner in which the restrictions will lapse, subject to the participant’s continued employment by us, and any other terms and conditions the plan administrator imposes consistent with the provisions of the Plan. Upon the lapse of the restrictions, any legends on the shares of common stock subject to the award will be re-issued to the participant without such legend.

The plan administrator may impose such restrictions or conditions, to the vesting of such shares as it, in its absolute discretion, deems appropriate. Prior to the vesting of a share of restricted stock granted under the Plan, no transfer of a participant’s rights to such share, whether voluntary or involuntary, by operation of law or otherwise, will vest the transferee with any interest, or right in, or with respect to, such share, but immediately upon any attempt to transfer such rights, such share, and all the rights related thereto, will be forfeited by the participant and the transfer will be of no force or effect; provided, however, that the plan administrator may, in its sole and absolute discretion, vest in the participant all or any portion of shares of restricted stock which would otherwise be forfeited.

Fair Market Value

Under the Plan, “Fair Market Value” means, for a particular day, the value determined in good faith by the plan administrator, which determination shall be conclusive for all purposes of the Plan. For purposes of valuing incentive options, the fair market value of stock: (i) shall be determined without regard to any restriction other than one that, by its terms, will never lapse; and (ii) will be determined as of the time the option with respect to such stock is granted.

Transferability Restrictions

Notwithstanding any limitation on a holder’s right to transfer an award, the plan administrator may (in its sole discretion) permit a holder to transfer an award, or may cause the Company to grant an award that otherwise would be granted to an eligible individual, in any of the following circumstances: (a) pursuant to a qualified domestic relations order; (b) to a trust established for the benefit of the eligible individual or one or more of the children, grandchildren or spouse of the eligible individual; (c) to a limited partnership or limited liability company in which all the interests are held by the eligible individual and that person’s children, grandchildren or spouse; or (d) to another person in circumstances that the plan administrator believes will result in the award continuing to provide an incentive for the eligible individual to remain in the service of the Company or its subsidiaries and apply his or her best efforts for the benefit of the Company or its subsidiaries. If the plan administrator determines to allow such transfers or issuances of awards, any holder or eligible individual desiring such transfers or issuances shall make application therefore in the manner and time that the plan administrator specifies and shall comply with such other requirements as the plan administrator may require to assure compliance with all applicable laws, including securities laws, and to assure fulfillment of the purposes of this Plan. The plan administrator shall not authorize any such transfer or issuance if it may not be made in compliance with all applicable federal and state securities laws. The granting of permission for such an issuance or transfer shall not obligate the Company to register the shares of stock to be issued under the applicable award.

23

Termination and Amendments to the Plan

The Board of Directors may (insofar as permitted by law and applicable regulations), with respect to any shares which, at the time, are not subject to awards, suspend or discontinue the Plan or revise or amend it in any respect whatsoever, and may amend any provision of the Plan or any award agreement to make the Plan or the award agreement, or both, comply with Section 16(b) of the Exchange Act and the exemptions therefrom, the Internal Revenue Code, as amended (the “Code”), the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), the regulations promulgated under the Code or ERISA, or any other law, rule or regulation that may affect the Plan. The Board of Directors may also amend, modify, suspend or terminate the Plan for the purpose of meeting or addressing any changes in other legal requirements applicable to the Company or the Plan or for any other purpose permitted by law. The Plan may not be amended without the consent of the holders of a majority of the shares of common stock then outstanding to materially increase the aggregate number of shares of stock that may be issued under the Plan except for certain adjustments.

Recent Sales of Unregistered Securities and Use of Proceeds from Registered Securities

None.

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 ending December 31, 2017.

Item 6:Selected Financial Data

The selected financial information set forth below is derived from our balance sheets and statements of operations as of and for the years ended December 31, 2017, 2016, 2015, 2014 and 2013. The data set forth below should be read in conjunction with “Management’s Discussion and Analysis2023.

Item 6:    Reserved
49
Table of Financial Condition and Results of Operations” and the financial statements and related notes thereto included in this Annual Report.

  For the years ended December 31, 
  2017  2016  2015  2014  2013 
Statement of Operations Data:                    
Revenues $66,699,700  $30,850,248  $31,013,892  $38,089,443  $10,315,701 
Cost of revenues  19,130,924   11,372,420   11,426,453   6,753,372   1,684,493 
Depreciation, depletion and amortization  20,517,780   11,483,314   15,175,791   11,807,794   2,284,091 
Ceiling test impairment  -   56,513,016   9,312,203   -   - 
Accretion  567,968   487,182   418,384   154,973   53,681 
General and administrative  10,515,887   8,027,077   7,995,395   6,803,029   6,682,760 
Net income (loss)  1,753,869   (37,637,687)  (9,052,771)  8,420,500   (452,209)
                     
Basic income (loss) per common share $0.03  $(0.97) $(0.32) $0.34  $(0.03)
Diluted income (loss) per common share $0.03  $(0.97) $(0.32) $0.33  $(0.03)

  As of December 31, 
  2017  2016  2015  2014  2013 
Balance Sheet Data:                    
Current assets $29,123,924  $75,220,915  $8,714,491  $15,083,298  $56,305,036 
Oil and gas properties subject to amortization  433,591,134   250,133,965   269,590,374   166,036,400   58,040,724 
Total assets  414,102,486   307,597,399   250,866,245   167,641,640   111,723,418 
Total current liabilities  48,443,449   9,099,391   11,333,167   16,263,051   7,231,643 
Total long-term liabilities  9,055,697   7,957,035   53,301,950   8,835,879   1,886,061 
Total Stockholders Equity  356,603,340   290,540,973   186,231,128   142,542,530   102,605,714 

24
Contents

Item 7:Management’s Discussion and Analysis of Financial Condition and Results of Operations

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. Ourbeliefs 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”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 Midland-basedgrowth oriented independent oil and natural gas exploration and production company thatbased in The Woodlands, Texas and is engaged in oil and natural gas development, production, acquisition, and exploration development and production activities. Our exploration and production interests areactivities currently focused in the Permian Basin of Texas. We take a conventional approach to ourOur drilling programoperations target the oil and seek to develop our traditional core areas, as well as look for new growth opportunities.

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

Ring

The Company is currently engaged in oilfocused on balancing the need to reduce long-term debt and natural gas acquisition, exploration, development and production, with activities in Texas. We focus onfurther developing our existing properties, while continuing to pursue acquisitions of 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.

Our goal is 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 stockholder value by investing in oilreserves at attractive finding costs and gas projects with attractive rates of return on capital employed. We plancomplement existing core properties. Management intends to achieve this goal by exploiting and developing our existing oil and natural gas properties and pursuingcontinue 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 additional properties. Specifically,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
50
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 business strategy is to increase our stockholders valuedrilling and completion activities for 2023 by quarter, and full year total through December 31, 2023.
51
QuarterAreaWells DrilledWells CompletedRecompletions
1Q 2023Northwest Shelf (Horizontal)4 4 — 
Central Basin Platform (Horizontal)— — — 
Central Basin Platform (Vertical)3 3 6 
Total7 7 6 
2Q 2023Northwest Shelf (Horizontal)4 4 — 
Central Basin Platform (Horizontal)— — — 
Central Basin Platform (Vertical)2 2 3 
Total6 6 3 
3Q 2023Northwest Shelf (Horizontal)5 2 — 
Central Basin Platform (Horizontal)3 3 — 
Central Basin Platform (Vertical)3 3 — 
Total11 8 — 
4Q 2023Northwest Shelf (Horizontal)1 4 — 
Central Basin Platform (Horizontal)3 3 — 
Central Basin Platform (Vertical)3 3 — 
Total (1)
7 10 — 
FY 2023Northwest 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 following:

·Growing production and reserves by developing our oil-rich resource base.Our long term plan is to actively drill and develop our acreage base in an effort to maximize its value and resource potential.  Ring’s portfolio of proved oil and natural gas reserves consists of 91% oil and 9% natural gas. Of those reserves, 45% of the proved reserves are classified as proved developed producing, or “PDP,” 10% are classified as proved developed non-producing, or “PDNP,” and approximately 45% are classified as proved undeveloped, or “PUD.” Through the conversion of undeveloped reserves to developed reserves, Ring seeks to increase production, reserves and cash flow while gaining favorable returns on invested capital. Through December 31, 2017, we increased our proved reserves to approximately 31.9 million BOE. All of our reserves relate to properties located in Texas. We spent approximately $190.1 million on acquisitions and capital projects during 2016 and 2017.

·Employ industry leading drilling and completion techniques.Ring’s executive team, which has over 100 years combined experience in the oil and gas industry, intends to utilize new and innovative technological advancements and careful geological evaluation in reservoir engineering to generate value for its stockholders and to build development opportunities for years to come. Improved efficiency through employing technological advancements can provide a significant benefit in a continuous drilling program such as the one Ring contemplates for its current inventory of drilling locations. Additionally, Ring believes that the experience of its executive team will help reduce the time and cost associated with drilling and completing both conventional and horizontal wells, while potentially increasing recovery.

·Pursue strategic acquisitions with exceptional upside potential. Ring has a history of acquiring leasehold positions that it believes to have substantial resource potential and to meet its targeted returns on invested capital. Ring has historically pursued acquisitions of properties that it believes to have exploitation and development potential comparable to its existing inventory of drilling locations. The Company has developed and refined an acquisition program designed to increase reserves and complement existing core properties. Ring’s experienced team of management and engineering professionals identify and evaluate acquisition opportunities, negotiate and close purchases and manage acquired properties. Management intends to continue to pursue strategic acquisitions that meet the Company’s operational and financial targets. The executive team, with its extensive experience in the Permian Basin, has many relationships with operators and service providers in the region. Ring believes that leveraging its relationships will be a competitive advantage in identifying acquisition targets. We believe that management’s proven ability to evaluate resource potential will allow Ring to successfully acquire acreage and bring out more value in the assets.

Northwest Shelf.

Market Conditions and Commodity Prices

Our financial results depend on many factors, particularly the price of crude oil and natural gas and crude oil 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 weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials and othermany 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. We expect
Average oil and natural gas prices received through 2022 and 2023 continued to remain volatile. Additionally,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 and crude oil reserves at economical costs are critical to our long-term success.

25

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
52

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.
53
Results of Operations

The following table sets forth selected operating data for the periods indicated:

For the Years Ended December 31, 2015  2016  2017 
          
Net production:            
Oil (Bbls)  664,612   728,051   1,311,727 
Natural gas (Mcf)  472,509   900,089   761,517 
             
Net sales:            
Oil $29,839,852  $28,599,140  $64,236,490 
Natural gas  1,174,040   2,251,108   2,463,210 
             
Average sales price:            
Oil (per Bbl) $44.90  $39.28  $48.97 
Natural gas (per Mcf)  2.48   2.50   3.23 
             
Production costs and expenses            
Oil and gas production costs $9,958,380  $9,867,800  $15,978,362 
Production taxes  1,468,073   1,504,620   3,152,562 
Depreciation, depletion and amortization expense  15,175,791   11,483,214   20,517,780 
Ceiling test impairment  9,312,203   56,513,016   - 
Realized loss on derivatives  -   -   119,897 
Accretion expense  418,384   487,182   567,968 
General and administrative expenses  7,995,395   8,027,077   10,515,887 

For the years ended December 31,202320222021
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 gas334,175 18,693,631 14,772,873 
Natural gas liquids11,676,963 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 costs457,573 1,830,024 4,333,232 
Ad valorem taxes6,757,841 4,670,617 2,276,463 
Oil and natural gas production taxes18,135,336 17,125,982 9,123,420 
Other costs and operating expenses:
Depreciation, depletion and amortization$88,610,291 $55,740,767 $37,167,967 
Asset retirement obligation accretion1,425,686 983,432 744,045 
Operating lease expense541,801 363,908 523,487 
General and administrative expense ("G&A")29,188,755 27,095,323 16,068,105 
Share-based compensation8,833,425 7,162,231 2,418,323 
G&A excluding share-based compensation20,355,330 19,933,092 13,649,782 
Other income (expense):
Interest income257,155 4 1 
Interest (expense)$(43,926,732)$(23,167,729)$(14,490,474)
Gain (loss) on derivative contracts2,767,162 (21,532,659)(77,853,141)
Loss on disposal of assets(87,128)— — 
Other income198,935 — — 
Provision for Income Taxes$(125,242)$(8,408,724)$(90,342)
Year Ended December 31, 20172023 Compared to Year Ended December 31, 2016

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 salesproduction taxes.Oil and natural gas sales revenue increased approximately $35.8 million to $66.7 million in 2017. Oil sales increased approximately $35.6 million whileproduction 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 $0.2 million.$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 oil salesWoodlands 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 increaseunrealized gain of $11.9 million during 2023 and an unrealized gain of $41.0 million during 2022. This change of $29.1 million in sales volumeunrealized derivatives was from 728,051 barrels$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 oilassets. 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 2016the 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 1,311,727 barrelsnet 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 2017 andNGL 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 $39.28$67.56 in 20162021 to $48.97$92.80 in 2017. These2022 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 amounts are calculated by dividing revenueoil 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 oil sales by the volume of oil sold,capital expenditures that were $78.0 million greater in barrels. 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 decreasedincreased from 900,0892,535,188 Mcf in 20162021 to 761,5174,088,642 Mcf in 20172022 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 $2.50$30,312,399 in 20162021 to $3.23$47,695,351 in 2017.2022 and increased on a Boe basis from $9.75 in 2021 to $10.57 in 2022. These per Mcf amounts are calculated by dividing revenue from gas sales by the volume of gas sold, in Mcf. The oil volume increase is the result of our ongoing development of existing properties.

Oil and gas production costs. Our aggregate oil and gas production costs increased from $9,867,800 in 2016 to $15,978,362 in 2017 and decreased on a BOE basis from $11.24 in 2016 to $11.11 in 2017. These per BOEBoe amounts are calculated by dividing our total production costsLOE by our total volume sold, in BOE. The decreaseBoe. 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 cost per BOE is the result of increased production.

Stronghold Acquisition.

Oil and natural gas production taxes.Oil and natural gas production taxes as a percentage of oil and natural gas sales were 4.88%4.65% during 20162021 and decreasedincreased to 4.73%4.93% in 2017.2022. 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.

tax rates.

Depreciation, depletion and amortization.Our depreciation, depletion and amortization expense increased by $9,034,566from $37,167,967 in 2021 to $20,517,780$55,740,767 in 2017. The increase was primarily the result of increased production volumes but was also affected by2022 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 rateper Boe increased from $13.08$11.95 per BOEBoe during 20162021 to $14.15$12.35 per BOEBoe during 2017.2022. These per BOEBoe amounts are calculated by dividing our total depreciation, depletion and amortization expense by our total volume sold,Boe volumes sold.
Asset retirement obligation accretion. Our ARO accretion increased from $744,045 in BOE.

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Ceiling Test Write-Down.    The Company did not have any write-downs for the period ended December 31, 2017. The Company recorded a non-cash write-downs of the carrying value of its proved oil and natural gas properties of $56,513,016 for the period ended December 31, 2016 as2021 to $983,432 in 2022. This was a result of ceiling test limitations, which is reflectedthe 32 additional wells added from 2022 drilling activities as ceiling test impairmentswell as ARO accretion associated with the properties acquired in the accompanying Statements of Operations.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 ceiling test was calculatedoffice equipment and compressors are not subject to ASU 2016-02 based upon the average of quoted market prices in effect on the first dayagreement and nature of the month for the preceding twelve month period at December 31, 2016, adjusted for market differentials, per SEC guidelines.use. The write-down reduced earningscosts have been recorded as short-term lease costs and amounts included in lease operating expenses beginning in the period and will result in a lower depreciation, depletion and amortization rate in future periods.

second quarter of 2021.

General and administrative expenses (including share-based compensation).General and administrative expenses increased from $8,027,077$16,068,105 in 20162021 to $10,515,887$27,095,323 in 2017.2022. The increase was primarily related to a $4,743,908 increase in share-based compensation, as well as increases in salaries and employee benefits.

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 incomeexpense. Interest income was $291,083expense increased from $14,490,474 in 2017 as compared2021 to $56,498$23,167,729 in 2016.2022. The increase was the result of a combination of higher interest rates during the second half of 2022, with a weighted average cashinterest rate of 5.8% in 2022 and 4.4% in 2021, and having higher amounts outstanding on handour 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 2017.

Interest expense. Interest expense decreased from $649,0092021 and a realized loss of $62,525,954 during 2022, The increase of $9,757,800 in 2016 to $0 in 2017. This decreasethe realized loss was thea result of not having any debt outstandingthe rise of crude oil prices during 2017.

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 negative provision of $19,987,585 in 2016$90,342 for 2021 to a positive provision of $10,416,171$8,408,724 for 2017.2022. The change is due tocurrent year federal tax expense was the Company having a pre-tax net income in 2017 versus a net loss in 2016 and an adjustment to the valueresult of ourcertain existing deferred tax assetassets that will not be offset by existing deferred tax liabilities as a result of a change in our future effective tax rate that is reflected in our current period expense.

the 80% limitation on the utilization of net operating losses incurred after 2017.

Net income (loss).The Company hadachieved net income of $1,753,869$3,322,892 in 2017 as2021 compared to a net lossincome of $37,637,687$138,635,025 in 2016.2022. The primary reasons were increasedincrease in net income was due primarily to the increase in oil, natural gas, and NGL revenues, and not having a ceiling test write downas well as the reduction in 2017, partiallyderivative contract losses, offset by the additional provision for income taxes recorded for the change in tax rate.

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

Oil and natural gas sales. Oil and natural gas sales revenue decreased approximately $0.2 million to $30.9 million in 2016. Oil sales decreased approximately $1.2 million while natural gas sales increased approximately $1.1 million. The oil sales decrease was the result of a decrease in the average realized per barrel oil price from $44.90 in 2015 to $39.28 in 2016 partially offset by an increase in sales volume from 644,612 barrels of oil in 2015 to 728,051 barrels of oil in 2016. These per barrel amounts are calculated by dividing revenue from oil sales by the volume of oil sold, in barrels. Natural gas sales volume increased from 472,509 Mcf in 2015 to 900,089 Mcf in 2016 and the average realized per Mcf gas price increased from $2.48 in 2015 to $2.50 in 2016. These per Mcf amounts are calculated by dividing revenue from gas sales by the volume of gas sold, in Mcf. The volume increases for both oil and natural gas are the result of both the acquisitions we made during the year and the result of our development of existing properties.

Oil and gas production costs. Our aggregate oil and gas production costs decreased from $9,958,380 in 2015 to $9,867,800 in 2016 and decreased on a BOE basis from $13.40 in 2015 to $11.24 in 2016. These per BOE amounts are calculated by dividing our total production costs by our total volume sold, in BOE. The decrease in the cost per BOE is the result of increased production.

Oil and gas production taxes. Oil and gas production taxes as a percentage of oil and natural gas sales were 4.73% during 2015 and increased to 4.88% in 2016. 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, and on the possibility that any state may raise its production tax.

Depreciation, depletion and amortization. Our depreciation, depletion and amortization expense decreased by $3,692,577 to $11,483,214 in 2016. The decrease was the result of a reduction in our average depreciation, depletion and amortization rate from $20.41 per BOE during 2015 to $13.08 per BOE during 2016, partially offset by increased production volumes. The reduced rate is the result of write downs of our oil and gas properties subject to amortization and increases in our reserve volumes. These per BOE amounts are calculated by dividing our total depreciation,lease operating expenses, depletion, and amortization expense by our total volume sold, in BOE.

Ceiling Test Write-Down.    The Company recorded non-cash write-downs of the carrying value of its proved oil and natural gas properties of $9,312,203 and $56,513,016 for the periods ended December 31, 2015 and 2016, respectively, as a result of ceiling test limitations, which is reflected as ceiling test impairments in the accompanying Statements of Operations. The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve month period at December 31, 2015 and 2016, adjusted for market differentials, per SEC guidelines. The write-down reduced earnings in the period and will result in a lower depreciation, depletion and amortization rate in future periods.

General and administrative expenses. Generalgeneral and administrative expenses, was relatively flat between the periods ended December 31, 2015 and 2016 with the amounts being $7,995,395 and $8,027,077, respectively.

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interest expense.

Interest income. Interest income was $56,498 in 2016 as compared to $6,984 in 2015. The increase was the result of higher average cash on hand during 2016.

Interest expense. Interest expense decreased from $749,134 in 2015 to $649,009 in 2016. This decrease was the result of lower average balances on the credit facility between periods.

Provision for income taxes. The provision for income taxes changed from a negative provision of $5,003,713 in 2015 to a negative provision of $19,987,585 for 2016. The change is due to the Company having a larger net loss in 2016 as compared to 2015.

Net loss. Net loss increased from $9,052,771 in 2015 to $37,637,687 in 2016. The primary reason for this change is the referenced ceiling test write-down.

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 sourcessource of cash in 2017 were2023 was from funds generated from the sale of oil and natural gas production and proceeds from the issuance of common stock.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 (“Administrative(the “Administrative Agent”), which(which was amended on May 18, 2016, June 26, 2015several 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 July 24, 2014restated the Credit Agreement with the Administrative Agent (as amended and restated, the “Credit Facility”).  The
On August 31, 2022, the Company modified its Credit Facility providesthrough 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 senior secured revolving credit facility with a maximum borrowing amountbase of $500$600 million. The Credit Facility matures on June 26, 2020, and is secured by substantially all of the Company’s assets.

In May 2016, the borrowing base (the “Borrowing Base”) was reduced from the initial $100 million to $60 million. The Borrowing Base is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time. The Borrowing Base will beborrowing base is redetermined semi-annually on each May 1 and November 1, beginning November 1, 2015.November. The Borrowing Base will also be reducedborrowing 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.

The

Rather than Eurodollar loans, the reference rate on the Second Credit Facility allowsAgreement is the SOFR. Also, the Second Credit Agreement permits the Company to declare dividends for Eurodollar Loansits 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 Base Rate Loans (each asamortization, 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 Facility)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 EurodollarSOFR Loan will be the adjusted LIBORterm SOFR for the applicable interest period plus a margin between 1.75%3.0% and 2.75%4.0% (depending on the then-current level of borrowing base usage). The annual interest rate on each Base Ratebase rate Loan is (a) the greatest of (i) the Administrative Agent’s prime lending rate, (ii) the federal funds rateFederal Funds Rate (as defined in the Second Credit Agreement) plus 0.5% per annum, or(iii) the (iii) adjusted LIBORterm SOFR determined on a daily basis for an interest period of one-month,one month, plus 1.00% per annum and (iv) 0.00% per annum, plus (b) a margin between 2.75%2.0% and 3.75%3.0% per annum (depending on the then-current level of borrowing base usage).


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The Second Credit FacilityAgreement contains certain covenants, which, among other things, require the maintenance of (i) a total leverage ratioLeverage Ratio of not more than 4.03.0 to 1.0 and (ii) a minimum current 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 FacilityAgreement 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, 2017,2023, $425 million was outstanding on the Credit Facility and the Company was in compliance with all covenants contained in the Second Credit Facility,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 no amounts(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 outstandingissued 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 Credit Facility.

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, our primary sources of cash have been from operations, equity offerings and borrowings on ourthe Credit Facility. During 2017, 20162023, 2022, and 2015,2021 we had net cash inflow from operationsprovided by operating activities of $42,806,224, $11,214,397$198.2 million, $197.0 million, and $9,397,552,$72.7 million, respectively. During the three years ended December 31, 2017,2023, we financed $248,634,788$20.9 million through proceeds from the sale of common stock. During 20162023, 2022, and 2015, we2021, the Company had proceeds from drawdownsa net drawof$10.0 million, a net draw of $125.0 million, and a net repayment of $23.0 million on ourthe Credit Facility, of $52,900,000.respectively. We primarily used this cash to fund our capital expenditures and development aggregating $305,915,895$596.9 million over the three years ended December 31, 20172023. Additionally, during 2023, 2022 and repayment2021, we used cash of debt$215.0 million, $511.0 million and $83.2 million, respectively, to reduce the outstanding balance on our Credit FacilityFacility. As of $52,900,000 in 2016. At December 31, 2017,2023, we had cash on hand of $15,006,581$0.3 million and negative working capital of $19,319,525, as$57.9 million, compared to cash on hand of $71,086,381$3.7 million and negative working capital of $66,121,524 at$78.6 million as of December 31, 20162022 and cash on hand of $8,714,491$2.4 million and negative working capital of $2,618,676 at December 31, 2015.

Schedule of Contractual Obligations. The following table summarizes our contractual obligations for periods subsequent to December 31, 2017. The future estimated office lease payments pertain to approximately 15,000 square feet of space for our corporate headquarters in Midland, Texas, approximately 3,700 square feet for our previous office space in Midland, Texas, approximately 3,700 square feet of office space for our accounting offices in Tulsa, Oklahoma and approximately 2,000 square feet of office space for our field office in Andrews, Texas. The Company incurred lease expenses of $537,582, $526,658 and $149,872 for the years ended December 31, 2017, 2016 and 2015, respectively. The following table reflects the outstanding balance under our Credit Facility and future minimum lease payments under the operating leases$46.9 million as of December 31, 2017.

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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.

  Payment due by period 
Contractual Obligations Total  Less than 1
year		  1-3 years  3-5 years  More than
5 years		 
Credit Facility (1) $-  $-  $-  $-  $- 
Operating Lease Obligations  1,108,950   531,550   577,400   -   - 
                     
Total $1,108,950  $531,550  $577,400  $-  $- 

(1)This table does not include future commitment fees, interest expense or other fees on this facility because they are floating rate instruments, and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged.

Long-term asset retirement obligation is not included

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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 above tableState 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 timingAdministrative 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 these payments cannotFree Cash Flow so amounts used by the Company for acquisitions will no longer be reasonably predicted.

subtracted from the calculation of Free Cash Flow.


Effects of Inflation and Pricing

The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers, and others associated with the industry puts extremesignificant pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Material changes in prices impact theour 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, 20172023, 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"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.We predominantly derive our 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. We receive
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The Company receives payment from one to three months after delivery. AtThe 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 end of each month, we estimate the amount of production delivered to purchasers and thetransaction price we will receive. Variances between our estimated revenue and actual payment are recordedbe fixed or stated in the monthcontract. Estimating the paymentvariable consideration does not require significant judgment and Ring engages third party sources to validate the estimates. Revenue is received; however, differences have been insignificant.

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. We account for our oil and natural gas operations using The Company uses the full cost method of accounting.accounting for oil and natural gas properties. Under this method, all costs (internal or external)(direct and indirect) associated with property acquisition, exploration, and development of oil and natural gas reservesproperties are capitalized. Costs capitalized include acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties and costcosts 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 monthtwelve-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.

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During 2016 and 2015, the Company recorded non-cash write-downs of the carrying value of the Company’s proved oil and gas properties as a result of ceiling test limitations of $56.5 million and $9.3 million, respectively, which are reflected with ceiling test and other impairments in the accompanying Statements of Operations. The Company did not have any write-downs related to the full cost ceiling limitation in 2017.

during the years ended December 31, 2023, 2022, or 2021.

Our reserve estimates of reserves and future cash flow as of December 31, 2017 are2023 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 $47.934$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 oil and $3.614 for gas.

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.

•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 based on internal reportsprepared and auditeddetermined by Cawley, Gillespie & Associates, Inc. and Williamson Petroleum Consultants, 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 for the differenceon differences between the tax basis of assets and liabilities and their carrying amounts in the carrying amount in our financial statements.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 we file ourthe 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 7AQuantitative and Qualitative Disclosures About Market Risk

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 we received during 20172023 ranged from a monthly average low of $39.69$68.72 per barrel to a monthly average high of $56.31$89.13 per barrel. Natural gas prices we receivedrealized during 20172023 ranged from a monthly average low of $1.43$(0.94) per Mcf to a monthly average high of $5.63$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 couldwould 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 may enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production. As of December 31, 2017, we had hedging arrangementsThe following table summarizes the Company's hedges in place covering 2,000 barrelson 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)
MonthAverage BBL/dayAverage MMBtu/day
January 20246,475 — 
February 20246,457 8,999 
March 20246,438 8,311 
April 20245,921 8,383 
May 20245,906 7,999 
June 20245,891 8,124 
July 20245,575 7,704 
August 20245,575 7,590 
September 20245,575 7,722 
October 20245,400 7,336 
November 20245,400 7,467 
December 20245,400 7,133 
January 20255,275 7,023 
February 20255,275 7,633 
March 20255,275 6,831 
April 20255,100 6,961 
May 20255,100 6,662 
June 20255,100 6,790 
July to September 20254,450 6,450 
October to December 20254,400 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 $12.8$37.9 million atas of December 31, 2017)2023). We are subject to credit risk due to the concentration of our oil and natural gas receivables with our most significant customers.customers, or purchasers. We do not require our customerspurchasers to post collateral, and the inability of our significant customerspurchasers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. ForThe following table sets forth certain information regarding the fiscaltop three purchasers of our oil, natural gas, and NGLs for the year 2016, sales to two customers, Oxy and Enterprise represented 76% and 18%, respectively, of oil and gas revenues. Atended December 31, 2017, Oxy represented 88% of our accounts receivable and Plains represented 10%. Effective December 1, 2017, Plains began purchasing production previously purchased by Enterprise. Due to availability of other purchasers, we do not2023. We believe that the loss of any singleof these purchasers would not materially impact our business because we could readily find other purchasers for our oil orand natural gas customer would have a material adverse effect on our results of operations.

gas.

For the Year EndedAs of
December 31, 2023December 31, 2023
Percentage of Oil, Natural Gas, and Natural Gas Liquids RevenuesPercentage 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, 2017,2023, we had no amounts$425.0 million outstanding on our Credit Facility. If we draw fundsFacility with a weighted average annual interest rate for the year then ended of 8.8%. A 1% change in the interest rate on thisour Credit Facility would result in an estimated $4.3 million change in our annual interest rate changes will impact future resultsexpense. See "Note 9 — REVOLVING LINE OF CREDIT" in the notes to the financial statements for more information on the Company’s interest rates of operations and cash flows.

our Credit Facility.

Currently, the Company doeswe 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

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 and Accounting and Financial Disclosure

Item 9:    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.

Item 9A:Controls and Procedures

Item 9A:    Controls and Procedures
Evaluation of disclosure controls and procedures.

Our management, with

Under the participationdirection of our chief executive officerChief Executive Officer and chief financial officer, evaluated the effectiveness of ourChief Financial Officer, we have established disclosure controls and procedures, pursuant toas defined in Rule 13a-1513a-15(e) and 15d-15(e) under the Exchange Act. In designing and evaluating the disclosure controls and procedures, management recognizesAct that any controls and procedures, no matter how wellare designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the factto ensure that there are resource constraints and that management isinformation required to apply its judgmentbe disclosed by us in evaluating the benefits of possible controls and procedures relative to their costs.

Based on management’s evaluation, our chief executive officer and chief financial officer concluded that, as of December 31, 2017, our disclosure controls and procedures are designed at a reasonable assurance level and are effective to provide reasonable assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SECthe SEC’s rules and forms,forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to our management, including our chief executive officerChief Executive Officer and chief financial officer,Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.  

We will continuedisclosures. In designing and evaluating the disclosure controls and procedures, management is required to monitorapply judgment in evaluating the benefits of possible controls and evaluateprocedures 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 internaldisclosure controls over financial reporting on an ongoing basis and procedures are committed to taking further action and implementing additional enhancements or improvements, as necessary and as funds allow.

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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, 20172023 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 wasis 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) inInternal Control – Integrated Framework (2013). Based on our assessment, we believe that, as of December 31, 2017,2023, our internal control over financial reporting is effective based on those criteria.

The independent registered public accounting firm, Eide BaillyGrant Thornton LLP, has audited the financial statements included in this annual report and has issued an attestation report on our internal control over financial reporting.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 underbelow.
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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 caption “Reportinternal control over financial reporting of Independent RegisteredRing 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 Firm”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 opinionon 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 Item 8the 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 this annual report.

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
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Item 9B:Other Information

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
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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:
Item 10:     Directors, Executive Officers and Corporate Governance

Executive Officers and Directors

Corporate Governance

The following table sets forth information regarding our executive officers, certain other officers and directors as of March 14, 2018. The Board believes that all the directors named below are highly qualified and have the skills and experience required for effective service on the Board. The directors’ and officers’ individual biographies below contain information about their experience, qualifications and skills that led the Board to nominate them.

NameAgePosition
Kelly Hoffman59Chief Executive Officer, Director
David A. Fowler59President, Director
Daniel D. Wilson57Executive Vice President
William R. Broaddrick40Chief Financial Officer
Lloyd T. Rochford71Chairman of the Board of Directors
Stanley M. McCabe85Director
Anthony B. Petrelli65Director
Clayton E. Woodrum77Director

Each of the directors identified above were appointed for a term of one year (or until their successors are elected and qualified).

Messrs. Rochford and McCabe joined the Board in June 2012 as a part of the merger between Ring and Stanford. Messrs. Hoffman, Fowler, Woodrum and Petrelli joined the Board in January 2013. All of the Board members were re-elected at the Company’s 2017 annual shareholders’ meeting. There are no family relationships between any director or executive officer or person nominated or chosen to become a director or officer of the Company.

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The following biographies describe the business experience of our executive officers and directors:

Kelly Hoffman – Chief Executive Officer and Director

Mr. Hoffman, 59, has organized the funding, acquisition and development of many oil and gas properties. He began his career in the Permian Basin in 1975 with Amoco Production Company. His responsibilities included oilfield construction, crew management, and drilling and completion operations. In the early 1990s, Mr. Hoffman co-founded AOCO and began acquiring properties in West Texas. In 1996, he arranged financing and purchased 10,000 acres in the Fuhrman Mascho field in Andrews, Texas. In the first six months, he organized a 60 well drilling and completion program resulting in a 600% increase in revenue and approximately 18 months later sold the properties to Lomak (Range Resources). In 1999, Mr. Hoffman again arranged financing and acquired 12,000 acres in Lubbock and Crosby counties. After drilling and completing 19 successful wells, unitizing the acreage, and instituting a secondary recovery project he sold his interest in the property to Arrow Operating Company. From April 2009 until December 2011, Mr. Hoffman served as President of Victory Park Resources, a privately held exploration and production company focused on the acquisition of oil and gas producing properties in Oklahoma, Texas and New Mexico. Mr. Hoffman has served as our Chief Executive Officer since January 2013. Mr. Hoffman currently serves as a director of Differential Brands Inc. (NASDAQ: DFBG), a reporting company.

David A. Fowler – President and Director

Mr. Fowler, 59, has served in several management positions for various companies in the insurance and financial services industries. In 1994, he joined Petroleum Listing Service as Vice President of Operations, overseeing oil and gas property listings, information packages, and marketing oil and gas properties to industry players. In late 1998, Mr. Fowler became the Corporate Development Coordinator for the Independent Producer Finance (“IPF”) group of Range Resources Corporation. Leaving Range IPF in April 2001, Mr. Fowler co-founded and became President of Simplex Energy Solutions, LLC (“Simplex”). Representing Permian Basin oil and gas independent operators, Simplex became known as the Permian Basin’s premier oil and gas divestiture firm, closing over 150 projects valued at approximately $675 million. Mr. Fowler has served as President of the Company since January 2013.

Daniel D. Wilson – Executive Vice President

Mr. Wilson, 57, has over 30 years of experience in operating, evaluating and exploiting oil and gas properties. He has experience in production, drilling and reservoir engineering. From 1983 to 2012, Mr. Wilson was employed at Breck Operating Corporation (“Breck”), including 22 years as the Vice President and Manager of Operations. He had the responsibility for overseeing the building, operating and divestiture of two companies duringby this time. At Breck’s peak Mr. Wilson was responsible for over 750 wells in seven states and had an operating staff of 27 including engineers, foremen, pumpers and clerks. Mr. Wilson personally performed or oversaw all of the economic evaluations for both acquisition and banking purposes. Mr. Wilson has served as Vice President of Operations of the Company since January 2013.

William R. Broaddrick – Chief Financial Officer.

Mr. Broaddrick, 40, was employed from 1997 to 2000 with Amoco Production Company, performing lease revenue accounting and state production tax regulatory reporting functions. During 2000, Mr. Broaddrick was employeditem is incorporated by Duke Energy Field Services, LLC performing state production tax functions. From 2001 until 2010, Mr. Broaddrick was employed by Arena as Vice President and Chief Financial Officer. During 2011, Mr. Broaddrick joined Stanford as Chief Financial Officer. As a result of the merger transaction between Stanford and Ring, Mr. Broaddrick became Chief Financial Officer of Ring as of July 2012.

In 1999, Mr. Broaddrick received a Bachelor’s Degree in Accounting from Langston University, through Oklahoma State University – Tulsa. Mr. Broaddrick is a Certified Public Accountant.

Lloyd T. (“Tim”) Rochford – Chairman of the Board of Directors

Mr. Rochford, 71, has been active as an individual consultant and entrepreneur in the oil and gas industry since 1973. During that time, he has been an operator of wells in the mid-continent of the United States, evaluated leasehold drilling and production projects, and arranged and raised in excess of $500 million in private and public financing for oil and gas projects and development.

Mr. Rochford has successfully formed, developed and sold/merged four natural resource companies, two of which were listed on the New York Stock Exchange. The most recent, Arena, was founded by Mr. Rochford and his associate Stanley McCabe in August 2000. From inception until May 2008, Mr. Rochford served as President, Chief Executive Officer and as a director of Arena. During that time, Arena received numerous accolades from publications such as Business Week (2007 Hot Growth Companies), Entrepreneur (2007 Hot 500), Fortune (2007, 2008, 2009 Fastest Growing Companies), Fortune Small Business (2007, 2008 Fastest Growing Companies) and Forbes (Best Small Companies of 2009). In May 2008, Mr. Rochford resignedreference herein from the position of Chief Executive Officer at Arena and accepted the position of Chairman of the Board. In his role as Chairman, Mr. Rochford continuedCompany's 2024 Proxy Statement to pursue opportunities that would enhance the then current, as well as long-term value of Arena. Through his efforts, Arena entered into a merger agreement and was acquired by another New York Stock Exchange company for $1.6 billion in July, 2010.

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Stanley M. McCabe – Director

Mr. McCabe, 85, has been active in the oil and gas industry for over 30 years, primarily seeking individual oil and gas acquisition and development opportunities. In 1979 he founded and served as Chairman and Chief Executive Officer of Stanton Energy, Inc., a Tulsa, Oklahoma natural resource company specializing in contract drilling and operation of oil and gas wells. In 1990, Mr. McCabe co-founded with Mr. Rochford, Magnum Petroleum, Inc., serving as an officer and director. In 2000, Mr. McCabe co-founded Arena with Mr. Rochford and Mr. McCabe served as Chairman of the Board until 2008 and then as a director of Arena until 2010.

Anthony B. Petrelli – Director

Mr. Petrelli, 65, is President, a member of the Board of Directors, and Director of Investment Banking of Neidiger, Tucker, Bruner, Inc., a Denver, Colorado based financial services firm founded in 1977. Beginning his career in 1972, Mr. Petrelli has had extensive experience in the areas of operations, sales, trading, management of sales, underwriting and corporate finance. He has served on numerous regulatory and industry committees including service on the FINRA Corporate Finance Committee, the NASD Small Firm Advisory Board and as Chairman of the FINRA District Business Conduct Committee, District 3. Mr. Petrelli received his Bachelors of Science in Business (Finance) and his Masters of Business Administration (MBA) from the University of Colorado and a Masters of Arts in Counseling from Denver Seminary.

Clayton E. Woodrum – Director

Mr. Woodrum, CPA, 77, is a founding partner of Woodrum, Tate & Associates, PLLC. His financial background encompasses over 40 years of experience from serving as a Partner In Charge of the tax department of a big eight accounting firm to Chief Financial Officer of BancOklahoma Corp. and Bank of Oklahoma. His areas of expertise include business valuation, litigation support (including financial analysis, damage reports, depositions and testimony), estate planning, financing techniques for businesses, asset protection vehicles, sale and liquidation of businesses, debt restructuring, debt discharge and CFO functions for private and public companies.

Our executive officers are elected by, and serve at the pleasure of, our Board of Directors. Our directors serve terms of one year each,be filed with the current directors serving untilSEC no later than 120 days after December 31, 2023. If the next annual meeting of stockholders, and in each case until their respective successors are duly elected and qualified.

Involvement in Certain Legal Proceedings

During the past ten years, there have been no events under any bankruptcy act, no criminal proceedings and no judgments, injunctions, orders or decrees material to the evaluation of the ability and integrity of any of our directors or executive officers, and none of our executive officers or directors has been involved in any judicial or administrative proceedings resulting from involvement in mail or wire fraud or fraud in connection with any business entity, any judicial or administrative proceedings based on violations of federal or state securities, commodities, banking or insurance laws or regulations, and any disciplinary sanctions or orders imposed by a stock, commodities or derivatives exchange or other self-regulatory organization.

Board Committees

Our Board of Directors has established an Audit Committee, a Compensation Committee, a Nominating and Corporate Governance Committee, and an Executive Committee, the composition and responsibilities of which are briefly described below. The charters for each of these committees shall be provided to any person without charge, upon request. The charters are also available on the Company’s website atwww.ringenergy.com. Requests may be directed to Ring Energy, Inc., 6555 S. Lewis Ave., Suite 200, Tulsa, Oklahoma 74136, Attention William R. Broaddrick, or by calling (918) 499-3880.

Audit Committee

The Audit Committee’s principal functions are to assist the Board in monitoring the integrity of our financial statements, the independent auditor’s qualifications and independence, the performance of our independent auditors and our compliance with legal and regulatory requirements. The Audit Committee has the sole authority to retain and terminate our independent auditors and to approve the compensation paid to our independent auditors. The Audit CommitteeProxy Statement is also responsible for overseeing our internal audit function. The Audit Committee is comprised of Messrs. Woodrum, Petrelli and McCabe, with Mr. Woodrum acting as the chairman. Our Board of Directors determined that Mr. Woodrum qualified as “audit committee financial expert” as defined in Item 407 of Regulation S-K promulgated by the Securities and Exchange Commission (see the biographical information for Mr. Woodrum, infra, in this discussion of “Directors and Executive Officers”). Each of Messrs. Woodrum, Petrelli and McCabe further qualified as “independent” in accordancenot filed with the applicable regulations of the NYSE MKT, LLC definition of independent director set forthSEC by such time, such information will be included in the Company Guide, Part 8, Section 803(A). (see the biographical information for Messrs. Woodrum, Petrelli and McCabe, infra, inan amendment to this discussion of “Directors and Executive Officers”).

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Annual Report by such time.

Compensation Committee

The Compensation Committee’s principal function is to make recommendations regarding the compensation of the Company’s officers. In accordance with the rules of the NYSE MKT, LLC, the compensation of our chief executive officer is recommended to the Board (in a proceeding in which the chief executive officer does not participate) by the Compensation Committee. Compensation for all other officers is also recommended to the Board for determination by the Compensation Committee. The Compensation Committee is comprised of Messrs. Rochford and McCabe, with Mr. Rochford acting as the chairman.

Nominating and Corporate Governance Committee

The Nominating and Corporate Governance Committee’s principal functions are to (a) identify and recommend qualified candidates to the Board of Directors for nomination as members of the Board and its committees, and (b) develop and recommend to the Board corporate governance principles applicable to the Company. The Nominating and Corporate Governance Committee is comprised of Messrs. Rochford and McCabe, with Mr. Rochford acting as the chairman.

There have been no material changes to the procedures by which security holders may recommend nominees to our Board of Directors.

Executive Committee

The Executive Committee’s principal function is to exercise the powers and duties of the Board between Board meetings and while the Board is not in session, and implement the policy decisions of the Board. The Executive Committee is comprised of Messrs. Rochford and McCabe.

Our Board may establish other committees from time to time to facilitate our management.

Code of Ethics

We have adopted a Code of Ethics that applies to our Chief Executive Officer, President, Chief Financial Officer, and Corporate Controller, as well as the principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions to ensure the highest standard of ethical conduct and fair dealing.

We have also adopted a Code of Business Conduct covering a wide range of business practices that applies to all of our officers, directors, and employees to help promote honest and ethical conduct. The Code of Business Conduct covers standards for professional conduct, including, among others, conflicts of interest, insider trading, confidential information, protection and proper use of Company assets, and compliance with all laws and regulations applicable to the Company’s business.

These documents are available on the Company’s website atwww.ringenergy.com. We shall also provide any person without charge, upon request, a copy of the Code of Ethics or Code of Business Conduct. Requests may be directed to Ring Energy, Inc., 6555 S. Lewis Ave., Suite 200, Tulsa, Oklahoma 74136, Attention William R. Broaddrick, or by calling (918) 499-3880.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires our officers and directors, and persons who own more than ten percent of a registered class of our equity securities, to file initial reports of ownership and reports of changes in ownership with the SEC. Such persons are required by SEC regulations to furnish us with copies of all Section 16(a) forms they file.

Based solely upon a review of Section 16(a) reports furnished to us for our most recent fiscal year, we know of no director, officer or beneficial owner of more than ten percent of our common stock who failed to file on a timely basis reports of beneficial ownership of the our common stock as required by Section 16(a) of the Securities Exchange Act of 1934, as amended.

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Item 11:     Executive Compensation

Compensation Discussion & Analysis

This Compensation Discussion and Analysis (1) provides an overview of our compensation policies and programs; (2) explains our compensation objectives, policies and practices with respect to our executive officers; and (3) identifies the elements of compensation for each of the individuals identified in the following table, whom we refer to in

The information required by this annual report as our “Named Executive Officers” for the fiscal year ending December 31, 2017.

NamePrincipal Position
Kelly HoffmanChief Executive Officer, effective January 1, 2013
David A. FowlerPresident, effective January 1, 2013
Daniel D. WilsonExecutive Vice President, effective January 1, 2013
William R. BroaddrickChief Financial Officer, effective July 1, 2012

This section contains a discussion of the material elements of compensation awarded to, earneditem is incorporated by or paid to (i) all individuals serving as the Company’s principal executive officer or acting in a similar capacity during the last completed fiscal year (“PEO”), regardless of compensation level, and (ii) all individuals serving as the Company’s principal financial officer or acting in a similar capacity during the last completed fiscal year (“PFO”), regardless of compensation level. As of the end of the last completed fiscal year, the Company had two executive officers other than the PEO and PFO, and this discussion includes the material elements of compensation awarded to, earned by, or paid to such executive officers. This section omits tables and columns if there has been no compensation awarded to, earned by, or paid to any of the Named Executive Officers or directors required to be reported in such table or column in any fiscal year covered by such table.

Objectives and Philosophy of Our Executive Compensation Program

Ring strives to attract, motivate and retain high-quality executives by providing total compensation that is performance-based and competitive within the labor market in which the Company competes for executive talent as a public company. Our compensation program is intended to align the interests of management with the interests of stockholders by linking pay with performance, thereby incentivizing performance and furthering the ultimate goal of increasing stockholder value.

Setting Executive Compensation

Our current executive compensation programs are determined and approved by our Compensation Committee. The Compensation Committee takes into consideration the recommendations by our Chairman of the Board and our Chief Executive Officer as to the compensation of executive officers other than the Chief Executive Officer. None of the Named Executive Officers are members of the Compensation Committee. The Compensation Committee has the direct responsibility and authority to review and approve the Company’s goals and objectives relative to the compensation of the Named Executive Officers, and to determine and approve (either as a committee or with the other members of the Company’s Board of Directors who qualify as “independent” directors under applicable guidelines adopted by the NYSE MKT, LLC) the compensation levels of the Named Executive Officers.

Our current executive compensation programs are intended to achieve two objectives. The primary objective is to enhance the profitability of the Company, and thus, shareholder value. The second objective is to attract, motivate, reward and retain employees, including executive personnel, who contribute to the long-term success of the Company. As described in more detail below, the material elements of our current executive compensation program for Named Executive Officers include three major elements: a base salary, discretionary annual bonuses and discretionary stock options grants.

General

The Company believes that each element of the executive compensation program helps to achieve one or both of the Company’s compensation objectives outlined above. Our executive’s compensation is based on individual and Company performance and designed to attract, retain and motivate highly qualified executives while creating a strong connection to financial and operational performance and stockholder value. The table below lists each material element of our executive compensation program and the compensation objective or objectives that it is designed to achieve.

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Compensation ElementCompensation Objectives
Base SalaryAttract and retain qualified executives Motivate and reward executives performance
Bonus CompensationMotivate and reward executive’s performance Enhance profitability of Company and shareholder value
Equity-Based Compensation – stock options and restricted stock grantsEnhance profitability of Company and shareholder value by aligning long-term incentives with shareholders’ long-term interests

As illustrated by the table above, base salary is primarily intended to attract and retain qualified executives. This is the element of the Company’s current executive compensation program where the value of the benefit in any given year is not wholly dependent on performance. Base salaries are intended to attract and retain qualified executives as well as to reward and/or motivate executives. Base salaries are reviewed annually and take into account: experience and retention considerations; past performance; improvement in historical performance; anticipated future potential performance; and other issues specific to the individual executive.

There are specific elements of the current executive compensation program that are designed to reward performance and enhance profitability and shareholder value, and therefore the value of these benefits is based on performance. The Company’s discretionary annual bonus plan is primarily intended to motivate and reward Named Executive Officers’ performance to achieve specific strategies and operating objectives, as well as improved financial performance. The Company also awards stock options and restricted stock grants to promote long-term value creation for stockholders and to retain talented executives for an extended period.

The Compensation Committee does not currently benchmark executive compensation to any other companies. The Compensation Committee believes that bonuses and equity compensation should fluctuate with the Company’s success in achieving financial, operating and strategic goals. The Committee’s philosophy is that the Company should continue to use long-term compensation such as stock options to align shareholder and executives’ interests and should allocate a portion of long-term compensation to the entire executive compensation package.

The Company has never retained an outside consultant in establishing its compensation program or in establishing any specific compensation for an executive officer.

In determining 2017 executive compensation, the Compensation Committee considered the outcome of the say-on-pay vote at the most recent annual meeting as supportive of our pay practices and programs. As a result, the Compensation Committee concluded that the 2017 compensation paid to our Named Executive Officers and our overall pay practices did not require changes; although the Compensation Committee will continue to evaluate the Company’s compensation program to ensure competitiveness, the alignment of the Company’s executive compensation with stockholders’ interests and to meet other compensation objectives..

Current Executive Compensation Program Elements

Base Salaries

The Compensation Committee believes base salary is an integral element of executive compensation to provide executive officers with a base level of monthly income. Similar to most companies within the industry, our policy is to pay Named Executive Officers’ base salaries in cash. Base salary is reviewed annually by the Compensation Committee. The base salary of each Named Executive Officer is reviewed annually, with the salary of the Chief Executive Officer being established by the Compensation Committee and the salaries of the other executive officers being determined and approved by the Compensation Committee after consideration of recommendations by the Chairman of the Board and Chief Executive Officer.

Effective July 1, 2012, the Compensation Committee designated a salary of $100,000 for Mr. Broaddrick. Effective September 1, 2012 the Compensation Committee recommended an increase of $25,000 for Mr. Broaddrick. Effective January 1, 2017, the Compensation Committee recommended an increase of $20,000 for Mr. Broaddrick.

Mr. Hoffman joined the Company effective January 1, 2013 and the Compensation Committee designated a salary of $175,000. Effective January 1, 2017, the Compensation Committee recommended an increase of $30,000 for Mr. Hoffman.

Mr. Fowler joined the Company effective January 1, 2013 and the Compensation Committee designated a salary of $150,000. Effective January 1, 2017, the Compensation Committee recommended an increase of $25,000 for Mr. Fowler.

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Mr. Wilson joined the Company effective January 1, 2013 and the Compensation Committee designated a salary of $150,000. Effective January 1, 2017, the Compensation Committee recommended an increase of $25,000 for Mr. Wilson.

Annual Bonuses

The Company does not have a formal policy regarding bonuses, and payment of bonuses has been purely discretionary and is largely based on the recommendations of the Compensation Committee. Cash incentive bonuses are designed to provide our executive officers with an incentive to achieve the Company’s business goals and objectives. Cash bonuses are not expected to be a significant portion of the executive compensation package. Cash bonuses are determined for Named Executive Officers based on his or her performance in the prior year, his or her expected future contribution to the performance of the Company, and other competitive data on grant values of peer companies.

Cash bonuses were granted to all employees in December 2013. The annual discretionary bonus is reported in the “Bonus” column of the “Summary Compensation Table” for each Named Executive Officer.

Equity-Based Compensation – Options and Restricted Stock Grants

It is our policy that the Named Executive Officers’ long-term compensation should be directly linked to enhancing profitability and value provided to the Company’s stockholders. Accordingly, the Compensation Committee grants equity awards under the Company’s long term incentive plan designed to link an increase in shareholder value to compensation. Mr. Broaddrick was granted non-qualified stock options in each year from 2012 through 2016 and was granted restricted stock in 2017. Messrs. Hoffman, Fowler and Wilson were granted non-qualified stock options in each year from 2013 to 2016 and were granted restricted stock in 2017.

Stock option grants are valued using the Black-Scholes Model and are calculated as a part of the executive compensation package for the year based on the amount of the requisite service period served. Non-qualified stock options for Named Executive Officers and other key employees generally vest ratably over five years. Restricted stock grants are valued based on the market price of the underlying stock price on the date of grant. Restricted stock grants for Named Executive Officers and other key employees generally vest ratably over five years. The Compensation Committee believes that these awards encourage Named Executive Officers to continue to use their best professional skills and to retain Named Executive Officers for longer terms.

Grants are determined for Named Executive Officers based on his or her performance in the prior year, his or her expected future contribution to the performance of the Company, and other competitive data on grant values of peer companies. Awards may be granted to new key employees or Named Executive Officers on their respective hire dates. Other grant date determinations are made by the Compensation Committee, which are based upon the date the Committee met and proper communication was made to the Named Executive Officer or key employee as defined in the definition of grant date by generally accepted accounting principles. Exercise prices are equal to the value of the Company’s stock on the close of business on the determined grant date. The Company has no program or practice to coordinate timing of grants with release of material, nonpublic information.

The grant date fair value as determined under generally accepted accounting principles is shown in the “Summary Compensation Table” below.

Pension Plans, Non-Qualified Deferred Compensation Plans, Change-In-Control Arrangements and Retirement Plans

The Company does not have any pension plans, non-qualified deferred compensation plans or severance, retirement, termination, constructive termination or change in control arrangements for any of its Named Executive Officers for the year ended December 31, 2017.

Other Benefits

Our Named Executive Officers are eligible to participate in all of our employee benefit plans, such as medical, dental, vision, group life, and short and long-term disability, in each case, on the same basis as other employees, subject to applicable laws. We also provide vacation and other paid holidays to all employees, including our Named Executive Officers.

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Tax Considerations

Although our Compensation Committee considers the tax and accounting treatment associated with the cash and equity grants it makes, these considerations are not dispositive. Section 162(m) of the Code places a limit of $1.0 million per person on the amount of compensation that we may deduct in any year with respect to our chief executive officer, chief financial officer and our three most highly compensated executive officers other than the chief executive officer and the chief financial officer. There is an exemptionreference herein from the $1.0 million limitation for performance-based compensation that meets certain requirements. Our benefit plans are generally designedCompany's 2024 Proxy Statement to permit compensation to be structured to meet the qualified performance-based compensation exception. To maintain flexibility in compensating Named Executive Officers in a manner designed to promote our Company goals and objectives, our Compensation Committee has not adopted a policy requiring all compensation to be deductible. The Compensation Committee retains the ability to evaluate the performance of our executive officers and to pay appropriate compensation, even if some of it may be non-deductible, to ensure competitive levels of total compensation is paid to certain individuals.

We account for stock-based awards based on their grant date fair value, as determined under FASB ASC Topic 718.  In connection with its approval of stock-based awards, the Compensation Committee is cognizant of and sensitive to the impact of such awards on stockholder dilution.  The Compensation Committee also endeavors to avoid stock-based awards made subject to a market condition, which may result in an expense that must be marked to market on a quarterly basis.  The accounting treatment for stock-based awards does not otherwise impact the Compensation Committee’s compensation decisions.

Risk Considerations in our Overall Compensation Program

When establishing and reviewing our executive compensation program, the Compensation Committee has considered whether the program encourages unnecessary or excessive risk taking and has concluded that it does not. While behavior that may result in inappropriate risk taking cannot necessarily be prevented by the structure of compensation practices, we believe that our compensation policies and practices do not create risks that are reasonably likely to have a material adverse effect on us. Our compensation program is comprised of both fixed and incentive-based elements. The fixed compensation (i.e., base salary) provides reliable, foreseeable income that mitigates the focus of our employees on our immediate financial performance or our stock price, encouraging employees to make decisions in our best long-term interests. The incentive components are designed to be sensitive to our short-term and long-term goals, performance and stock price. In combination, we believe that our compensation structures do not encourage our officers and employees to take unnecessary or excessive risks in performing their duties. In conclusion, we believe that our compensation policies and practices for all employees, including executive officers, do not create risks that are reasonably likely to have a material adverse effect on our Company.

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Compensation of Named Executive Officers

The “Summary Compensation Table” set forth below should be read in connection with the tables and narrative descriptions that follow. The “Outstanding Equity Awards at Fiscal Year End Table” and “Option Exercises and Stock Vested Table” provide further information on the Named Executive Officers’ potential realizable value and actual value realized with respect to their equity awards.  

Summary Compensation Table

Name and Principal
Position		 Year Salary ($)  Bonus ($)  Option
Awards
(1) (2) ($)		  All Other
Compensation
($)(3)		  Total ($) 
                  

Kelly Hoffman,

Chief Executive Officer

 2017 $205,000  $-  $618,240  $24,000  $847,240 
 2016  175,000   -   740,283   24,000   939,283 
 2015  175,000   -   260,762   24,000   459,762 
                       

David Fowler,

President

 2017  175,000   -   403,200   24,000   602,200 
 2016  150,000   -   496,650   24,000   670,650 
 2015  150,000   -   260,762   24,000   434,762 
                       

Daniel D. Wilson,

Executive Vice President

 2017  175,000   -   403,200   -   578,200 
 2016  150,000   -   495,477   -   645,477 
 2015  150,000   -   238,167   -   388,167 
                       

William R. Broaddrick,

Chief Financial Officer

 2017  145,000   -   403,200   -   548,200 
 2016  125,000   -   398,024   -   523,024 
 2015  125,000   -   238,167   -   363,167 

(1) See discussion of assumptions made in valuing these awards in the notes to our financial statements.

(2) On December 9, 2015, Ring issued option awards to its named executive officers and directors. On January 13, 2016, upon the recommendation of the Compensation Committee, Ring rescinded the option awards granted to its employees and directors (other than Messrs. McCabe and Rochford, who are the members of the Compensation Committee) as the result of a significant decline in the stock price and re-issued the option awards as of that date to meet the goals and objectives of the Company’s equity based compensation program. The amounts shown as Option Awards include the additional fair value of the new options over the original grant.

(3) Other Compensation for Messrs. Hoffman and Fowler consists of $24,000 in directors fees.

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The Company awards stock options to key employees and the Named Executive Officers either on the initial date of employment or based on performance incentives throughout the year. The following table reflects the restricted stock granted during 2017.

Grants of Plan-Based Awards

Name Grant Date Restricted stock grants (#)  Fair Value on
Grant Date		 
         
Kelly Hoffman 12/19/2017  46,000  $618,240 
David Fowler 12/19/2017  30,000   403,200 
Daniel D. Wilson 12/19/2017  30,000   403,200 
William R. Broaddrick 12/19/2017  30,000   403,200 

Named Executive Officers are not separately entitled to receive dividend equivalent rights with respect to each stock option. Each nonqualified stock option award described in the “Grants of Plan-Based Awards Table” above expires ten years from the grant date and vests in equal installments over the course of five years.

The following table provides certain information regarding unexercised stock options outstanding for each Named Executive Officer as of December 31, 2017.

Outstanding Option Awards

Name Number of Securities
Underlying
Unexercised Options
(#) Exercisable		  Number of Securities
Underlying Unexercised
Options (#)
Unexercisable		  Options
Exercise Price
($)		  Option
Grant
Date		 Option
Expiration
Date
              
Kelly Hoffman  110,000   -  $2.00  12/01/11 12/01/21
   400,000   100,000   4.50  01/01/13 01/01/23
   20,000   5,000   10.00  12/16/13 12/16/23
   18,000   12,000   8.00  12/01/14 12/01/24
   8,000   32,000   5.25  01/13/16 01/13/26
   15,000   60,000   11.75  12/13/16 12/13/26
                 
David Fowler  400,000   100,000   4.50  01/01/13 01/01/23
   20,000   5,000   10.00  12/16/13 12/16/23
   18,000   12,000   8.00  12/01/14 12/01/24
   8,000   32,000   5.25  01/13/16 01/13/26
   10,000   40,000   11.75  12/13/16 12/13/26
                 
Daniel D. Wilson  240,000   60,000   4.50  01/01/13 01/01/23
   16,000   4,000   10.00  12/16/13 12/16/23
   15,000   10,000   8.00  12/01/14 12/01/24
   7,000   28,000   5.25  01/13/16 01/13/26
   10,000   40,000   11.75  12/13/16 12/13/26
                 
William R. Broaddrick  60,000   -   2.00  12/01/11 12/01/21
   40,000   -   4.50  08/15/12 08/15/22
   16,000   4,000   10.00  12/16/13 12/16/23
   15,000   10,000   8.00  12/01/14 12/01/24
   7,000   28,000   5.25  01/13/16 01/13/26
   8,000   32,000   11.75  12/13/16 12/13/26

The following table provides certain information regarding unvested restricted stock outstanding for each Named Executive Officer as of December 31, 2017.

41

All granted options vest at the rate of 20% each year over five years beginning one year from the date granted and expire ten years from the grant date.

Outstanding Unvested Restricted Stock Awards

NameUnvested Restricted
Stock Grants		Grant  Date
Kelly Hoffman46,00012/19/17
David Fowler30,00012/19/17
Daniel D. Wilson30,00012/19/17
William R. Broaddrick30,00012/19/17

The following table provides information regarding options exercised by Named Executive Officers during 2015 and 2017.

Option Exercises and Stock Vesting

    Option Awards 
Name Year Number of Shares
Acquired on Exercise (#)		  Value Realized on
Exercise ($)		 
         
Kelly Hoffman 2015  20,000  $162,800 
  2017  120,000   1,313,100 

There were no option exercises by Named Executive Officers during 2016.

Director Compensation

Inside directors receive a monthly stipend of $2,000. Outside directors receive a monthly stipend of $3,000. In 2017, each outside director also received 30,000 shares of restricted stock as an annual bonus. Mr. Rochford received an additional 400,000 shares of restricted stock as additional compensation as Chairman. Director compensation to Messrs. Fowler and Hoffman is included here but is also included in the executive compensation schedule above. No director receives a salary as a director.

Director Compensation Table

Name   Fees Earned or Paid
in Cash ($)		  Option Awards
($)(1)		    All Other
Compensation ($)		  Total ($) 
Lloyd T. Rochford (2) $36,000  $1,461,797    $-  $1,485,797 
Stanley M. McCabe (3)  36,000   487,266     -   511,266 
David A. Fowler (4)  24,000   496,650  (8)  -   520,650 
Kelly Hoffman (5)  24,000   740,283  (8)  -   764,283 
Clayton E. Woodrum (6)  36,000   487,266  (8)  -   511,266 
Anthony B. Petrelli (7)  36,000   487,266  (8)  -   511,266 

(1)See discussion of assumptions made in valuing these awards in the notes to our financial statements.
(2)Lloyd T. Rochford has 315,000 options to purchase Ring stock and 70,000 shares of unvested restricted stock.
(3)Stanley McCabe has 215,000 options to purchase Ring stock and 30,000 shares of unvested restricted stock.
(4)David A. Fowler has an aggregate of 655,000 options to purchase Ring stock and 30,000 shares of unvested restricted stock.
(5)Kelly Hoffman has an aggregate of 900,000 options to purchase Ring stock and 46,000 shares of unvested restricted stock.
(6)Clayton E. Woodrum has 215,000 options to purchase Ring stock and 30,000 shares of unvested restricted stock.
(7)Anthony B. Petrelli has 215,000 options to purchase Ring stock and 30,000 shares of unvested restricted stock.

42

Compensation Committee Report

Among the duties imposed on our Compensation Committee under its charter, is the direct responsibility and authority to review and approve the Company’s goals and objectives relevant to the compensation of the Company’s Chief Executive Officer and other executive officers, to evaluate the performance of such officers in accordance with the policies and principles established by the Compensation Committee and to determine and approve, either as a Committee, or (as directed by the Board) with the other “independent” Board members (as defined by the NYSE MKT listing standards), the compensation level of the Chief Executive Officer and the other executive officers. During 2017 the Compensation Committee was comprised of the two non-employee Directors named at the end of this report each of whom is “independent” as defined by the NYSE MKT listing standards.

The Compensation Committee has reviewed and discussed with management the disclosures contained in the Compensation Discussion and Analysis section of this Item 11, as required by Item 402(b) of Regulation S-K. Based upon this review and our discussions, the Compensation Committee recommended to its Board of Directors that the Compensation Discussion and Analysis section be included in this annual report on Form 10-K for the fiscal year ended December 31, 2017.

Compensation Committee of the Board of Directors

Lloyd T. Rochford (Chair)

Stanley McCabe

_____________________

(1) SEC filings sometimes “incorporate information by reference.” This means the Company is referring you to information that has previously been filed with the SEC and that this information should be considered as part of the filing you are reading. Unless the Company specifically states otherwise, this Compensation Committee Report shall not be deemed to be incorporated by reference and shall not constitute soliciting material or otherwise be considered filed under the Securities Act of 1933 as amended, or the Securities Exchange act of 1934, as amended.

Compensation Committee Interlocks and Insider Participation

As ofno later than 120 days after December 31, 2017,2023. If the Compensation Committee was comprised of two directors, Messrs. Rochford and McCabe,Proxy Statement is not filed with Mr. Rochford acting as the chairman. Messrs. Rochford and McCabe are currently serving as the members of the Compensation Committee. Neither of our directors who currently serve as members of our Compensation Committee is, or has at anySEC by such time, such information will be included in the past been, an officer or employee of the Company or any of its subsidiaries. The office space being leasedamendment to this Annual Report by the Company in Tulsa, Oklahoma, is owned by Arenaco, LLC, a company that is owned by Mr. Rochford, Chairman of the Board of the Company, and Mr. McCabe, a Director of the Company. During the years ended December 31, 2015 through December 31, 2017, the Company paid an aggregate of $180,000 to Arenaco, LLC.

None of our executive officers serves, or has served, during the last completed fiscal year, on the compensation committee or board of directors of any other company that has one or more executive officers serving on our Compensation Committee or Board.

such time.
Item 12:Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Securities Authorized for Issuance Under Equity Compensation Plan

The following table sets forth information concerning our executive stock compensation plans as of December 31, 2017.

  Restricted
stock granted
that has not
vested		  Number of securities
to be issued upon
exercise of
outstanding options		  Weighted-average
exercise price of
outstanding options		  Number of securities remaining
available for future issuance under
compensation plans (excluding
securities in column (a))		 
             
Equity compensation plans approved by security holders  330,900   3,193,000  $6.07   1,040,200 
                 
Equity compensation plans not approved by security holders  -   -   -   - 
                 
Total  330,900   3,193,000  $6.07   1,040,200 

43

The Plan was in existence with Stanford and was adopted by the Board of Directors on June 27, 2012, and assumed by the Company upon the acquisition of Stanford. The Plan was subsequently approved by vote of a majority of shareholders on January 22, 2013. Information regarding the material terms of this plans may be found in this Annual Report under Part II, Item 5.

12:     Security Ownership of Certain Beneficial Owners and Management

and Related Stockholder Matters

The following table sets forth certain information furnishedrequired by current management and others, concerningthis item is incorporated by reference herein from the ownership of our common stock as of March 14, 2018, of (i) each person who is known to usCompany's 2024 Proxy Statement to be filed with the beneficial owner of moreSEC no later than five percent of our common stock, without regard120 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 any limitations on conversion or exercise of convertible securities or warrants; (ii) all directors and Named Executive Officers; and (iii) our directors and executive officers as a group. The mailing address for each of the persons indicated in the table below is our corporate headquarters. The percentage ownership is based on 60,388,029 shares outstanding at March 14, 2018.

Beneficial ownership is determined under the rules of the Securities and Exchange Commission. In general, these rules attribute beneficial ownership of securities to persons who possess sole or shared voting power and/or investment power with respect to those securities and include, among other things, securities that an individual has the right to acquire within 60 days. Unless otherwise indicated, the stockholders identified in the following table have sole voting and investment power with respect to all shares shown as beneficially ownedthis Annual Report by them.

  Shares of Common Stock
Beneficially Owned		 
Name Number  Percent 
Kelly Hoffman  686,546(1)  1%
         
David A. Fowler  709,200(2)  1%
         
Daniel D. Wilson  420,000(3)  1%
         
William R. Broaddrick  178,000(4)  * 
         
Lloyd T. Rochford  1,764,000(5)  3%
         
Stanley M. McCabe  1,909,634(6)  3%
         
Anthony B. Petrelli  184,000(7)  * 
         
Clayton E. Woodrum  148,248(8)  * 
         
All directors and executive officers as a group (8 persons)  5,999,628(9)  10%

* Represents beneficial ownership of less than 1%

(1)Includes 679,000 shares issuable upon the exercise of stock options that are currently exercisable.
(2)Includes 564,000 shares issuable upon the exercise of stock options that are currently exercisable.
(3)Includes 355,000 shares issuable upon the exercise of stock options that are currently exercisable.
(4)Includes 153,000 shares issuable upon the exercise of stock options that are currently exercisable.
(5)Includes (i) 164,000 shares issuable upon the exercise of stock options that are currently exercisable and (ii) 1,580,000 shares held by a family trust controlled by Mr. Rochford.
(6)Includes (i) 144,000 shares issuable upon the exercise of stock options that are currently exercisable and (ii) 1,646,502 shares held by a family trust controlled by Mr. McCabe.
(7)Includes 144,000 shares issuable upon the exercise of stock options that are currently exercisable.
(8)Includes 129,000 shares issuable upon the exercise of stock options that are currently exercisable.
(9)Includes 2,332,000 shares issuable upon the exercise of stock options that are currently exercisable.

Changes in Control

There are no arrangements known to us, including any pledge by any person of our securities, the operation of which may at a subsequent date result in a change in control of the Company.

44
such time.

Item 13:
Item 13:     Certain Relationships and Related Transactions, and Director Independence

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 Related Persons

The office space being leased by the Company in Tulsa, Oklahoma, is owned by Arenaco, LLC, a company that is owned by Mr. Rochford, Chairman of the Board of the Company, and Mr. McCabe, a Director of the Company. During the years endedSEC no later than 120 days after December 31, 2017, 2016 and 2015,2023. If the Company paidProxy Statement is not filed with the SEC by such time, such information will be included in an aggregate of $180,000 to Arenaco, LLC for the lease of the office space.

The Audit Committee reviews any related party transactions. Annually each Board member is required to submit an Independence Certificate, disclosing any affiliations or relationships for evaluation as related party transactions.

Review, Approval or Ratification of Transactions with Related Parties

The Board of Directors reviews and approves all relationships and transactions in which it and its directors, director nominees and executive officers and their immediate family members, as well as holders of more than 5% of any class of its voting securities and their family members, have a direct or indirect material interest. In approving or rejecting such proposed relationships and transactions, the Board shall consider the relevant facts and circumstances available and deemed relevantamendment to this determination. In each case the standard applied in approving the transaction is the best interests of the Company without regard to the interests of the individual officer or director involved in the transaction. These procedures for reviewing and approving conflict of interest transactions are based on the Company’s past practice and are not contained in any written policy.

Director Independence

The standards relied uponAnnual Report by the Board in determining whether a director is “independent” are those set forth in the rules of the NYSE MKT. The NYSE MKT generally defines the term “independent director” as a person other than an executive officer or employee of a company, who does not have a relationship with the company that would interfere with the director’s exercise of independent judgment in carrying out the responsibilities of a director. Because the Board of Directors believes it is not possible to anticipate or provide for all circumstances that might give rise to conflicts of interest or that might bear on the materiality of a relationship between a director and the Company, the Board has not established specific objective criteria, apart from the criteria set forth in the NYSE MKT, LLC rules, to determine “independence”. In addition to such criteria, in making the determination of “independence”, the Board of Directors considers such other matters including (i) the business and non-business relationships that each independent director has or may have had with the Company and its other Directors and executive officers, (ii) the stock ownership in the Company held by each such Director, (iii) the existence of any familial relationships with any executive officer or Director of the Company, and (iv) any other relevant factors which could cause any such Director to not exercise his independent judgment.

Consistent with these standards, the Board of Directors has determined that Messrs. Woodrum and Petrelli, are each “independent” directors within the meaning the NYSE MKT, LLC definition of independent director set forth in the Company Guide, Part 8, Section 803(A). The Board has also determined that Messrs. Rochford and McCabe are “independent” directors under the same definitions.

time.
Item 14:Principal Accounting Fees and Services

Item 14:     Principal Accountant Fees and Services
The Audit Committee selected Eide Bailly as its independent registered public accounting firm forinformation required by this item is incorporated by reference herein from the fiscal years endedCompany's 2024 Proxy Statement to be filed with the SEC no later than 120 days after December 31, 2015, 2016 and 2017. The Audit Committee has adopted a policy that requires advance approval of all audit, audit-related, tax services and other services performed2023. If the Proxy Statement is not filed with the SEC by the independent auditor.

Fees and Independence

Audit Fees. Eide Bailly billed the Company an aggregate of $105,000 for professional services rendered for the review of the Company’s financial statementssuch time, such information will be included in itsan amendment to this Annual Report by such time.

68
PART IV
Item 15:     Exhibits and Financial Statement Schedules
Incorporated by Reference
Exhibit
Number		Exhibit DescriptionFormFile No.ExhibitFiling DateFiled
Here-with		Furn-ished Here-with
2.18-K001-360572.12/28/19
2.28-K001-360572.17/8/22
2.2(a)8-K001-360572.18/9/22
2.38-K001-360572.17/14/23
3.110-K000-539203.14/1/13
3.1(a)8-K001-360573.112/17/21
3.1(b)8-K001-360573.15/26/23
3.28-K001-360573.14/15/21
3.38-K001-360573.19/6/22
3.48-K001-360573.110/31/22
4.110-Q001-360574.14/12/19
4.2X
4.38-K001-360574.110/29/20
69
Table of Contents
Incorporated by Reference
Exhibit
Number		Exhibit DescriptionFormFile No.ExhibitFiling DateFiled
Here-with		Furn-ished Here-with
10.1*8-K001-3695710.112/4/20
10.2*8-K001-3695710.110/6/20
10.3*8-K001-3605710.112/22/20
10.4*8-K001-3605710.212/22/20
10.5*8-K000-5392099.31/24/13
10.6*10-Q000-5392010.28/14/12
10.710-Q001-3605710.25/8/19
10.88-K001-3605710.112/9/19
10.98-K001-3605710.16/19/20
10.108-K001-3605710.112/29/20
10.118-K001-3605710.16/16/21
10.128-K001-3605710.16/25/21
10.13*8-K001-3605710.13/26/21
10.148-K001-3605710.19/6/22
10.158-K001-3605710.29/6/22
10.168-K001-3605710.39/6/22
70
Table of Contents
Incorporated by Reference
Exhibit
Number		Exhibit DescriptionFormFile No.ExhibitFiling DateFiled
Here-with		Furn-ished Here-with
10.178-K001-3605710.49/6/22
10.18*DEF 14A001-360574/22/21
10.19*8-K001-3605710.15/26/23
10.20*8-K001-3605710.111/30/21
10.21*8-K001-3605710.12/23/23
10.22*8-K001-3605710.22/23/23
10.238-K001-3605710.14/12/23
10.248-K001-3605710.12/16/24
10.25X
14.18-K000-5392014.11/24/13
23.1X
23.2X
24.1X
31.1X
31.2X
32.1X
32.2X
97.1X
99.1X
101.INSInline XBRL Instance DocumentX
101.SCHInline XBRL Taxonomy Extension Schema DocumentX
101.CALInline XBRL Taxonomy Extension Calculation Linkbase DocumentX
101.DEFInline XBRL Taxonomy Extension Definition Linkbase DocumentX
101.LABInline XBRL Taxonomy Extension Label Linkbase DocumentX
71
Table of Contents
Incorporated by Reference
Exhibit
Number		Exhibit DescriptionFormFile No.ExhibitFiling DateFiled
Here-with		Furn-ished Here-with
101.PREInline XBRL Taxonomy Extension Presentation Linkbase DocumentX
104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
*Management contract
Item 16:     Form 10-Q’s for 2016 and the audit10-K Summary
None.
72
SIGNATURES
Pursuant to the Company’s filingrequirements of registration statements.

Tax Fees. Eide Bailly billed the Company $10,980 and $18,250, respectively, for professional services rendered for tax compliance, tax advice and tax planning for the years ended December 31, 2017 and 2016.

All Other Fees. No other fees were billed by Eide Bailly to the Company during 2017 and 2016.

45

The Audit Committee of the Board of Directors has determined that the provision of services by Eide Bailly described above is compatible with maintaining Eide Bailly’s independence as the Company’s principal accountant. The policy of the Audit Committee and our Board, as applicable, is to pre-approve all services by our independent registered public accounting firm. The Audit Committee has adopted a pre-approval policy that provides guidelines for the audit, audit-related, tax and other non-audit services that may be provided by our independent registered public accounting firm. The policy (a) identifies the guiding principles that must be considered by the Audit Committee in approving services to ensure that the independent registered public accounting firm’s independence is not impaired; (b) describes the audit, audit-related, tax and other services that may be provided and the non-audit services that are prohibited; and (c) sets forth the pre-approval requirements for all permitted services. Under the policy, all services to be provided by our independent registered public accounting firm must be pre-approved by the Audit Committee.

PART IV

Item 15:Exhibits, Financial Statement Schedules

(a)Financial Statements

The following financial statements are filed with this Annual Report:

Report of Independent Registered Public Accounting FirmF-2
Balance Sheets at December 31, 2017 and 2016F-4
Statements of Operations for the years ended December 31, 2017, 2016 and 2015F-5
Statements of Stockholders’ Equity for the years ended December 31, 2017, 2016 and 2015F-6
Statements of Cash Flows for the year ended December 31, 2017, 2016 and 2015F-7
Notes to Financial StatementsF-8
Supplemental Information on Oil and Gas Producing ActivitiesF-22

46

    Incorporated by Reference  
Exhibit
Number		 Exhibit Description Form File No. Exhibit Filing Date 

Filed

Here-with

2.1 Stock for Stock Exchange Agreement dated May 3, 2012 8-K 000-53920 2.1 7/5/12  
2.2 Merger Agreement dated November 7, 2012 8-K 000-53920 2.1 11/26/12  
3.1 Articles of Incorporation (as amended) 10-K 000-53920 3.1 4/1/13  
3.2 Current Bylaws 8-K 000-53920 3.2 1/24/13  
10.1 Letter Agreement with Patriot Royalty & Land, LLC entered into on March 1, 2012 10-K 000-53920 10.1 3/20/12  
10.2* Ring Energy Inc. Long Term Incentive Plan, as Amended 8-K 000-53920 99.3 1/24/13  
10.3* Form of Option Grant for Long-Term Incentive Plan 10-Q 000-53920 10.2 8/14/12  
10.4 Executive Committee Charter 10-K 000-53920 3.1 4/1/13  
10.5 Audit Committee Charter 10-K 000-53920 3.1 4/1/13  
10.6 Compensation Committee Charter 10-K 000-53920 3.1 4/1/13  
10.7 Nominating and Corporate Governance Committee Charter 10-K 000-53920 3.1 4/1/13  
10.8 Credit Agreement dated July 1, 2014 with SunTrust Bank 8-K 001-36057 10.1 7/3/14  
10.9 First Amendment to Credit Agreement with SunTrust Bank 8-K 001-36057 10.1 6/29/15  
10.10 Second Amendment to Credit Agreement with SunTrust Bank 8-K 001-36057 10.1 7/29/15  
10.11 Third Amendment to Credit Agreement with SunTrust Bank 8-K 001-36057 10.1 5/20/16  
10.12 Development Agreement with Torchlight Energy Resources, Inc. 8-K 001-36057 10.1 10/18/13  
10.13 Purchase and Sale Agreement, dated February 4, 2014, between Ring Energy, Inc. and Raw Oil & Gas, Inc., JDH Raw LC, and Smith Energy Company 8-K 001-36057 10.1 2/7/14  
10.14 Purchase and Sale Agreement effective May 1, 2015, with Finley Production Co., LP, BDT Oil & Gas, LP, Metcalfe Oil, LP, Grasslands Energy, LP, Buffalo Oil & Gas, LP and Finley Resources, Inc. 8-K 001-36057 2.1 5/22/15  
14.1 Code of Ethics 8-K 000-53920 14.1 1/24/13  
16.1 Letter dated April 19, 2012, from Haynie & Company 8-K 000-53920 16.1 4/19/12  
23.1 Consent of Cawley, Gillespie & Associated, Inc.         X
23.2 Consent of Williamson Petroleum Consultants, Inc.         X
23.3 Consent of Eide Bailly LLC         X
31.1 Rule 13a-14(a) Certification by Chief Executive Officer         X
31.2 Rule 13a-14(a) Certification by Chief Financial Officer         X
32.1 Section 1350 Certification of Chief Executive Officer         X
32.2 Section 1350 Certification Chief Financial Officer         X
99.1 Reserve Report of Cawley, Gillespie & Associates, Inc.         X
99.2 Reserve Report of William Petroleum Consultants, Inc.         X
101. INS XBRL Instance Document         X
101. SCH XBRL Taxonomy Extension Schema Document         X
101. CAL XBRL Taxonomy Extension Calculation Linkbase Document         X
101. DEF XBRL Taxonomy Extension Definition Linkbase Document         X
101. LAB XBRL Taxonomy Extension Label Linkbase Document         X
101. PRE XBRL Taxonomy Extension Presentation Linkbase Document         X

* Management contract

47

SIGNATURES

In accordance with 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/ Kelly HoffmanPaul D. McKinney
Mr. Kelly HoffmanPaul D. McKinney
Chief Executive Officer
Date: March 15, 20187, 2024
By:/s/ William R. Broaddrick
Mr. William R. Broaddrick
Chief Financial Officer
Date:  March 15, 2018

In accordance

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 andindicated on the datedates indicated.

/s/ LloydPaul D. McKinney/s/ Thomas L. Mitchell
Mr. Paul D. McKinneyMr. Thomas L. Mitchell
Chief Executive Officer and DirectorDirector
(Principal Executive Officer)Date: March 7, 2024
Date: March 7, 2024
/s/ Travis T. RochfordThomas/s/ Anthony B. Petrelli
Mr. LloydTravis T. RochfordThomasMr. Anthony B. Petrelli
DirectorChief Financial OfficerDirector
(Principal Financial Officer)Date: March 7, 2024
Date: March 15, 20187, 2024
/s/ Regina RoesenerDate:  March 15, 2018/s/ Clayton E. Woodrum
Mrs. Regina RoesenerMr. Clayton E. Woodrum
/s/ Stanley McCabeDirector/s/ David A. Fowler
Mr. Stanley McCabeMr. David A. Fowler
DirectorDirector
Date: March 15, 20187, 2024Date: March 15, 20187, 2024
/s/ Richard E. Harris/s/ John A. Crum
/s/ ClaytonMr. Richard E. WoodrumHarris/s/ Kelly HoffmanMr. John A. Crum
Mr. Clayton E. WoodrumDirectorMr. Kelly Hoffman
DirectorDirector
Date: March 15, 20187, 2024Date: March 15, 20187, 2024

/s/ Roy I. Ben-Dor48/s/ David S. Habachy
Mr. Roy I. Ben-DorMr. David S. Habachy
DirectorDirector
Date: March 7, 2024Date: March 7, 2024

73

RING ENERGY, INC.

INDEX TO FINANCIAL STATEMENTS

Page
F-F-22
F-4
Balance SheetsF-4
F-F-55
F-F-66
F-F-77
F-F-89
F-F-2239

F-1

F-1

 

ReportTable of Independent Registered Public Accounting Firm

To the Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and
Stockholders of
Ring Energy, Inc.
Midland, Texas

Opinion on the Financial Statements and Internal Control Over Financial Reporting

financial statements


We have audited the accompanying balance sheets of Ring Energy, Inc. (Ring Energy)(a Nevada corporation) (the “Company”) as of December 31, 20172023 and 2016, and2022, the related statements ofoperations,, stockholders’ equity, and cash flows for each of the three years in the three-year period ended December 31, 2017,2023, and the related notes (collectively referred to as the “financial statements”).We also have audited Ring Energy’s internal control over financial reporting as of 2017, based on criteria established in 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the financial statements present fairly, in all material respects, the financial position of Ring Energythe Company as of December 31, 20172023 and 2016,2022, and the results of its operations and its cash flows for each of the three years in the three-year period ended December 31, 2017,2023, in conformity with accounting principles generally accepted in the United States of America. Also
We also have audited, in our opinion, Ring Energy maintained, in all material respects, effectiveaccordance 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, 2017,2023, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

(“COSO”), and our report dated March 7, 2024 expressed an unqualified opinion.

Basis for Opinion

Ring Energy’s management is responsible for theseopinion

These financial statements for maintaining effective internal control over financial reporting, and for its assessmentare the responsibility of the effectiveness of internal control over financial reporting, included in the accompanying Management’ Annual Report on Internal Control Over Financial Reporting appearing under Item 9A.Company’s management. Our responsibility is to express an opinion on the entity’sCompany’s financial statements and an opinion on the entity’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”)PCAOB and are required to be independent with respect to Ring Energythe 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 auditsaudit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

fraud. Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respondsrespond 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

www.eidebailly.com

5 Triad Center, Ste. 600 | Salt Lake City, UT 84180-1128 | T 801.532.2200 | F 801.532.7944 | EOE

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opinion.

Critical audit matters

 

Definition and Limitations of Internal Control Over Financial Reporting

An entity’s internal control over financial reporting

The critical audit matter communicated below is a process designedmatter arising from the current period audit of the financial statements that was communicated or required to provide reasonable assurancebe 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 reliabilityfinancial performance of financial reportingwells associated with proved crude oil and natural gas reserves to determine if wells are expected, with reasonable certainty, to be economical under the preparation of financial statements for external purposes in accordance with accounting principles generally acceptedappropriate pricing assumptions required in the United Statesestimation of America. An entity’s internal control over financial reporting includes those policiesdepletion,
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depreciation and proceduresamortization 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 (1) pertainthe 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 maintenance of records that, in reasonable detail, accuratelyvolume and fairly reflect the transactions and dispositionsfuture net revenues of the assets of the entity; (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 entity are being made only in accordance with authorizations of management and directors of the entity; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the entity’s assets thatCompany’s proved reserves could have a material effectsignificant impact on the financial statements.

Becausemeasurement 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 subjectdepletion, depreciation and amortization expense. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment.

Our audit procedures related to the risk thatestimation of proved crude oil and natural gas reserves included the following, among others.
•We tested the design and operating effectiveness of controls may become inadequate becauserelating to management’s estimation of changesproved 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 conditions, or that the degreereserve 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 compliance withproved undeveloped properties reflected in the policies orreserve 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 may deteriorate.

to production forecasts in the reserve report by comparing to historical actual results.


/s/ Eide BaillyGRANT THORNTON LLP



We have served as Ring Energy’sthe Company’s auditor since 2013.

Salt Lake City, Utah

2021.



Houston, Texas
March 15, 2018

www.eidebailly.com

5 Triad Center, Ste. 600 | Salt Lake City, UT 84180-1128 | T 801.532.2200 | F 801.532.7944 | EOE

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7, 2024

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RING ENERGY, INC.

BALANCE SHEETS

As of December 31, 2017  2016 
ASSETS        
Current Assets        
Cash $15,006,581  $71,086,381 
Accounts receivable  12,833,883   3,453,238 
Joint interest billing receivable  1,054,022   454,461 
Prepaid expenses and retainers  229,438   226,835 
Total Current Assets  29,123,924   75,220,915 
Properties and Equipment        
Oil and natural gas properties subject to amortization  433,591,134   250,133,965 
Inventory for property development  -   1,582,427 
Fixed assets subject to depreciation  1,884,818   1,549,311 
Total Properties and Equipment  435,475,952   253,265,703 
Accumulated depreciation, depletion and amortization  (61,864,932)  (41,347,152)
Net Properties and Equipment  373,611,020   211,918,551 
Deferred Income Taxes  11,232,200   20,051,908 
Deferred Financing Costs  135,342   406,025 
Total Assets $414,102,486  $307,597,399 
         
LIABILITIES AND STOCKHOLDERS' EQUITY        
Current Liabilities        
Accounts payable $44,475,163  $9,099,391 
Derivative liabilities  3,968,286   - 
Total Current Liabilities  48,443,449   9,099,391 
         
Asset retirement obligations  9,055,697   7,957,035 
Total Liabilities  57,499,146   17,056,426 
Stockholders' Equity        
Preferred stock - $0.001 par value; 50,000,000 shares authorized; no shares issued or outstanding  -   - 
Common stock - $0.001 par value; 150,000,000 shares authorized; 54,224,029 shares and 49,113,063 shares issued and outstanding, respectively  54,224   49,113 
Additional paid-in capital  397,904,769   335,197,845 
Accumulated deficit  (41,355,653)  (44,705,985)
Total Stockholders' Equity  356,603,340   290,540,973 
Total Liabilities and Stockholders' Equity $414,102,486  $307,597,399 

As of December 31,20232022
ASSETS
Current Assets
Cash and cash equivalents$296,384 $3,712,526 
Accounts receivable38,965,002 42,448,719 
Joint interest billing receivables, net2,422,274 983,802 
Derivative assets6,215,374 4,669,162 
Inventory6,136,935 9,250,717 
Prepaid expenses and other assets1,874,850 2,101,538 
Total Current Assets55,910,819 63,166,464 
Properties and Equipment
Oil and natural gas properties, full cost method1,663,548,249 1,463,838,595 
Financing lease asset subject to depreciation3,896,316 3,019,476 
Fixed assets subject to depreciation3,228,793 3,147,125 
Total Properties and Equipment1,670,673,358 1,470,005,196 
Accumulated depreciation, depletion and amortization(377,252,572)(289,935,259)
Net Properties and Equipment1,293,420,786 1,180,069,937 
Operating lease asset2,499,592 1,735,013 
Derivative assets11,634,714 6,129,410 
Deferred financing costs13,030,481 17,898,973 
Total Assets$1,376,496,392 $1,268,999,797 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable$104,064,124 $111,398,268 
Financing lease liability956,254 709,653 
Operating lease liability568,176 398,362 
Derivative liabilities7,520,336 13,345,619 
Notes payable533,734 499,880 
Deferred cash payment— 14,807,276 
Asset retirement obligations165,642 635,843 
Total Current Liabilities113,808,266 141,794,901 
Non-current Liabilities
Deferred income taxes8,552,045 8,499,016 
Revolving line of credit425,000,000 415,000,000 
Financing lease liability, less current portion906,330 1,052,479 
Operating lease liability, less current portion2,054,041 1,473,897 
Derivative liabilities11,510,368 10,485,650 
Asset retirement obligations28,082,442 29,590,463 
Total Liabilities589,913,492 607,896,406 
Commitments and Contingencies - See Note
Stockholders' Equity
Preferred stock - $0.001 par value; 50,000,000 shares authorized; no shares issued or outstanding— — 
Common stock - $0.001 par value; 450,000,000 shares authorized; 196,837,001 shares and 175,530,212 shares issued and outstanding, respectively196,837 175,530 
Additional paid-in capital795,834,675 775,241,114 
Accumulated deficit(9,448,612)(114,313,253)
Total Stockholders’ Equity786,582,900 661,103,391 
Total Liabilities and Stockholders' Equity$1,376,496,392 $1,268,999,797 
The accompanying notes are an integral part of these financial statements.

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Table of Contents
RING ENERGY, INC.

STATEMENTS OF OPERATIONS

For the years ended December 31, 2017  2016  2015 
          
Oil and Gas Revenues $66,699,700  $30,850,248  $31,013,892 
             
Costs and Operating Expenses            
Oil and gas production costs  15,978,362   9,867,800   9,958,380 
Oil and gas production taxes  3,152,562   1,504,620   1,468,073 
Depreciation, depletion and amortization  20,517,780   11,483,314   15,175,791 
Ceiling test impairment  -   56,513,016   9,312,203 
Asset retirement obligation accretion  567,968   487,182   418,384 
General and administrative expense  10,515,887   8,027,077   7,995,395 
             
Total Costs and Operating Expenses  50,732,559   87,883,009   44,328,226 
             
Income (Loss) from Operations  15,967,141   (57,032,761)  (13,314,334)
             
Other Income (Expense)            
Interest income  291,083   56,498   6,984 
Interest expense  -   (649,009)  (749,134)
Realized loss on derivatives  (119,897)  -   - 
Unrealized loss on change in fair value of derivatives  (3,968,287)  -   - 
             
Net Other Income (Expense)  (3,797,101)  (592,511)  (742,150)
             
Income (Loss) Before Provision for Income Taxes  12,170,040   (57,625,272)  (14,056,484)
             
(Provision for) Benefit from Income Taxes  (10,416,171)  19,987,585   5,003,713 
           . 
Net Income (Loss) $1,753,869  $(37,637,687) $(9,052,771)
             
Basic Earnings (Loss) per share $0.03  $(0.97) $(0.32)
Diluted Earnings (Loss) per share $0.03  $(0.97) $(0.32)

For the years ended December 31,202320222021
Oil, Natural Gas, and Natural Gas Liquids Revenues$361,056,001 $347,249,537 $196,305,966 
Costs and Operating Expenses
Lease operating expenses70,158,227 47,695,351 30,312,399 
Gathering, transportation and processing costs457,573 1,830,024 4,333,232 
Ad valorem taxes6,757,841 4,670,617 2,276,463 
Oil and natural gas production taxes18,135,336 17,125,982 9,123,420 
Depreciation, depletion and amortization88,610,291 55,740,767 37,167,967 
Asset retirement obligation accretion1,425,686 983,432 744,045 
Operating lease expense541,801 363,908 523,487 
General and administrative expense29,188,755 27,095,323 16,068,105 
Total Costs and Operating Expenses215,275,510 155,505,404 100,549,118 
Income from Operations145,780,491 191,744,133 95,756,848 
Other Income (Expense)
Interest income257,155 4 1 
Interest (expense)(43,926,732)(23,167,729)(14,490,474)
Gain (loss) on derivative contracts2,767,162 (21,532,659)(77,853,141)
Loss on disposal of assets(87,128)— — 
Other income198,935 — — 
Net Other Income (Expense)(40,790,608)(44,700,384)(92,343,614)
Income Before Provision for Income Taxes104,989,883 147,043,749 3,413,234 
Provision for Income Taxes(125,242)(8,408,724)(90,342)
Net Income$104,864,641 $138,635,025 $3,322,892 
Basic Earnings per Share$0.55 $1.14 $0.03 
Diluted Earnings per Share$0.54 $0.98 $0.03 
The accompanying notes are an integral part of these financial statements.

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Table of Contents
RING ENERGY, INC.

STATEMENTS OF STOCKHOLDERS’ EQUITY

        Additional  Retained Earnings  Total 
  Common Stock  Paid-in  (Accumulated  Stockholders' 
  Shares  Amount  Capital  Deficit)  Equity 
Balance, December 31, 2014  25,734,467  $25,734  $140,532,323  $1,984,473  $142,542,530 
Share-based compensation  -   -   2,566,716   -   2,566,716 
Options exercised (cashless exercise)  16,875   17   (17)  -   - 
Options exercised  40,000   41   134,759   -   134,800 
Common stock issued for cash, net  4,600,000   4,600   50,035,253   -   50,039,853 
Net loss  -   -   -   (9,052,771)  (9,052,771)
Balance, December 31, 2015  30,391,342  $30,392  $193,269,034  $(7,068,298) $186,231,128 
Share-based compensation  -   -   2,267,053   -   2,267,053 
Options exercised (cashless exercise)  734   -   -   -   - 
Options exercised  25,600   26   112,474   -   112,500 
Common stock issued for cash, net  18,695,387   18,695   139,549,284   -   139,567,979 
Net loss  -   -   -   (37,637,687)  (37,637,687)
Balance, December 31, 2016  49,113,063  $49,113  $335,197,845  $(44,705,985) $290,540,973 
Modified Retrospective adjustment             $1,596,463   1,596,463 
Share-based compensation  -   -   3,685,079   -   3,685,079 
Options exercised (cashless exercise)  133,308   133   (133)  -   - 
Options exercised  -   -   -   -   - 
Common stock issued for cash, net  4,977,658   4,978   59,021,978   -   59,026,956 
Net income  -   -   -   1,753,869   1,753,869 
Balance, December 31, 2017  54,224,029  $54,224  $397,904,769  $(41,355,653) $356,603,340 

Common StockAdditional
Paid-in
Capital		Retained Earnings
(Accumulated
Deficit)		Total
Stockholders'
Equity
SharesAmount
Balance, December 31, 202085,568,287$85,568 $550,951,415 $(256,271,170)$294,765,813 
Common stock and warrants issued for cash, net— — (65,000)— (65,000)
Exercise of pre-funded warrants issued in offering13,428,50013,429 — — 13,429 
Exercise of common warrants issued in offering442,600443 353,637 — 354,080 
Options exercised100,000100 199,900 — 200,000 
Restricted stock vested785,357785 (785)— — 
Shares to cover tax withholdings for restricted stock vested(132,182)(132)132 — — 
Payments to cover tax withholdings for restricted stock vested, net—— (385,330)— (385,330)
Share-based compensation—— 2,418,323 — 2,418,323 
Net income—— — 3,322,892 3,322,892 
Balance, December 31, 2021100,192,562$100,193 $553,472,292 $(252,948,278)$300,624,207 
Exercise of common warrants issued in offering10,253,90710,254 8,192,872 — 8,203,126 
Options exercised100,000100 (100)— — 
Shares elected to be withheld for options exercised(47,506)(48)48 — — 
Restricted stock vested1,310,8941,311 (1,311)— — 
Shares to cover tax withholdings for restricted stock vested(168,523)(169)169 — — 
Payments to cover tax withholdings for restricted stock vested, net—— (521,199)— (521,199)
Common stock issuance for Stronghold Acquisition21,339,98621,340 69,120,215 69,141,555 
Conversion of mezzanine preferred shares for Stronghold Acquisition42,548,89242,549 137,815,897 137,858,446 
Share-based compensation—— 7,162,231 — 7,162,231 
Net income—— — 138,635,025 138,635,025 
Balance, December 31, 2022175,530,212$175,530 $775,241,114 $(114,313,253)$661,103,391 
Exercise of common warrants issued in offering4,517,427 4,517 3,609,424 — 3,613,941 
Induced exercise of common warrants issued in offering14,512,166 14,512 8,673,143 — 8,687,655 
Restricted stock vested1,680,232 1,680 (1,680)— — 
Shares to cover tax withholdings for restricted stock vested(288,152)(287)287 — — 
Payments to cover tax withholdings for restricted stock vested, net(520,153)(520,153)
Performance stock vested1,170,024 1,170 (1,170)— — 
Shares to cover tax withholdings for performance stock vested(284,908)(285)285 — — 
Share-based compensation8,833,425 8,833,425 
Net income104,864,641 104,864,641 
Balance, December 31, 2023196,837,001$196,837 $795,834,675 $(9,448,612)$786,582,900 
The accompanying notes are an integral part of these financial statements.

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Table of Contents
RING ENERGY, INC.

STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2017  2016  2015 
Cash Flows From Operating Activities            
Net income (loss) $1,753,869  $(37,637,687) $(9,052,771)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:            
Depreciation, depletion and amortization  20,517,780   11,483,314   15,175,791 
Ceiling test impairment  -   56,513,016   9,312,203 
Accretion expense  567,968   487,182   418,384 
Share-based compensation  3,685,079   2,267,053   2,566,716 
Deferred income tax expense (benefit)  3,862,827   (19,987,585)  (5,003,713)
Excess tax benefit related to share-based compensation  (49,896)  -   - 
Adjustment to deferred tax asset for change in effective tax rate  6,603,240         
Change in fair value of derivative instruments  3,968,286   -   - 
Changes in assets and liabilities:            
Accounts receivable  (9,980,206)  229,324   2,163,440 
Prepaid expenses  268,080   334,162   (806,422)
Accounts payable  12,375,772   (2,233,776)  (4,929,884)
Settlement of asset retirement obligation  (766,595)  (240,606)  (446,192)
Net Cash Provided by Operating Activities  42,806,204   11,214,397   9,397,552 
Cash Flows From Investing Activities            
Payments to purchase oil and natural gas properties  (28,682,298)  (10,193,927)  (77,902,553)
Payments to develop oil and natural gas properties  (124,680,469)  (26,554,171)  (31,430,355)
Purchase of inventory for development  (4,214,686)  (1,582,427)  - 
Purchase of equipment, vehicles and leasehold improvements  (335,507)  (9,320)  (330,182)
Net Cash Used in Investing Activities  (157,912,960)  (38,339,845)  (109,663,090)
Cash Flows From Financing Activities            
Proceeds from revolving line of credit  -   7,000,000   45,900,000 
Proceeds from issuance of common stock  59,026,956   139,567,979   50,039,853 
Principal payments on revolving line of credit  -   (52,900,000)  - 
Proceeds from option exercise  -   112,500   134,800 
Net Cash Provided by Financing Activities  59,026,956   93,780,479   96,074,653 
Net Increase (Decrease) in Cash  (56,079,800)  66,655,031   (4,190,885)
Cash at Beginning of Period  71,086,381   4,431,350   8,622,235 
Cash at End of Period $15,006,581  $71,086,381  $4,431,350 
Supplemental Cash Flow Information            
Cash paid for interest $-  $649,010  $426,742 
Noncash Investing and Financing Activities            
Asset retirement obligation incurred during development $1,297,289  $308,509  $171,635 
Asset retirement obligation acquired  -   -   3,361,634 
Use of inventory in property development  5,797,113   -   - 
Capitalized expenditures attributable to drilling projects financed through current liabilities  23,000,000   -   - 

For the Years Ended December 31,202320222021
Cash Flows From Operating Activities
Net income$104,864,641 $138,635,025 $3,322,892 
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization88,610,291 55,740,767 37,167,967 
Asset retirement obligation accretion1,425,686 983,432 744,045 
Amortization of deferred financing costs4,920,714 2,706,021 665,882 
Share-based compensation8,833,425 7,162,231 2,418,323 
Bad debt expense134,007 242,247 — 
Deferred income tax expense (benefit)(425,275)8,720,992 265,479 
Excess tax expense (benefit) related to share-based compensation478,304 (312,268)(175,187)
(Gain) loss on derivative contracts(2,767,162)21,532,659 77,853,141 
Cash paid for derivative settlements, net(9,084,920)(62,525,954)(52,768,154)
Changes in operating assets and liabilities:
Accounts receivable1,154,085 (17,214,150)(9,483,639)
Inventory3,113,782 (5,597,845)— 
Prepaid expenses and other assets226,688 (1,163,509)(541,920)
Accounts payable(1,451,422)50,808,461 15,449,215 
Settlement of asset retirement obligation(1,862,385)(2,741,380)(2,186,832)
Net Cash Provided by Operating Activities198,170,459 196,976,729 72,731,212 
Cash Flows From Investing Activities
Payments for the Stronghold Acquisition(18,511,170)(177,823,787)— 
Payments for the Founders Acquisition(62,227,145)— — 
Payments to purchase oil and natural gas properties(2,162,585)(1,563,703)(1,368,437)
Payments to develop oil and natural gas properties(152,559,314)(129,332,155)(51,302,131)
Payments to acquire or improve fixed assets subject to depreciation(492,317)(319,945)(568,832)
Sale of fixed assets subject to depreciation332,229 134,600 — 
Proceeds from divestiture of oil and natural gas properties1,554,558 23,700 2,000,000 
Proceeds from sale of Delaware properties7,600,699 — — 
Proceeds from sale of New Mexico properties3,891,757 — — 
Net Cash Used in Investing Activities(222,573,288)(308,881,290)(51,239,400)
Cash Flows From Financing Activities
Proceeds from revolving line of credit225,000,000 636,000,000 60,150,000 
Payments on revolving line of credit(215,000,000)(511,000,000)(83,150,000)
Proceeds from issuance of common stock and warrants12,301,596 8,203,126 367,509 
Proceeds from option exercise— — 200,000 
Payments for taxes withheld on vested restricted shares, net(520,153)(521,199)(385,330)
Proceeds from notes payable1,637,513 1,323,354 1,297,718 
Payments on notes payable(1,603,659)(1,409,884)(711,308)
Payment of deferred financing costs(52,222)(18,891,528)(104,818)
Reduction of financing lease liabilities(776,388)(495,098)(325,901)
Net Cash Provided by (Used in) Financing Activities20,986,687 113,208,771 (22,662,130)
Net Increase (Decrease) in Cash(3,416,142)1,304,210 (1,170,318)
Cash at Beginning of Period3,712,526 2,408,316 3,578,634 
Cash at End of Period$296,384 $3,712,526 $2,408,316 
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Table of Contents
RING ENERGY, INC.
STATEMENTS OF CASH FLOWS (CONTINUED)
For the Years Ended December 31,202320222021
Supplemental Cash Flow Information
Cash paid for interest$38,009,164 $19,818,623 $14,110,421 
Cash paid for income taxes72,213 — — 
Noncash Investing and Financing Activities
Asset retirement obligation incurred during development$439,528 $353,008 $171,390 
Asset retirement obligation acquired2,090,777 14,538,550 662,705 
Asset retirement obligation revision of estimate53,826 — 435,419 
Asset retirement obligation sold(5,340,211)— (2,934,126)
Operating lease assets obtained in exchange for new operating lease liability1,713,677 754,894 839,536 
Operating lease asset revision— — (621,636)
Financing lease assets obtained in exchange for new financing lease liability894,996 952,101 — 
Change in capitalized expenditures attributable to drilling projects financed through current liabilities(2,241,192)9,179,003 309,365 
Supplemental Schedule for Founders Acquisition
Investing Activities - Cash Paid
Escrow deposit released at closing$7,500,000 $— $— 
Closing amount paid to Founders42,502,799 — — 
Interest from escrow deposit1,747 — — 
Direct transaction costs1,361,843 — — 
Post-close adjustments(4,139,244)— — 
Payment of deferred cash payment15,000,000 — — 
Payments for the Founders Acquisition$62,227,145 $— $— 
Investing Activities - Noncash
Assumption of suspense liability$677,116 $— $— 
Assumption of asset retirement obligation2,090,777 — — 
Assumption of ad valorem tax liability234,051 — — 
Deferred cash payment at fair value14,657,383 — — 
Supplemental Schedule for Stronghold Acquisition
Investing Activities - Cash Paid
Cash paid by bank to Stronghold on closing$— $121,392,455 $— 
Deposit in escrow— 46,500,000 — 
Direct transaction costs— 9,162,143 — 
Cash paid for realized August oil derivative losses— 1,777,925 — 
Cash paid for inventory and fixed assets acquired— 4,527,103 — 
Cash received for post-close adjustments, net— (5,535,839)— 
Payment of deferred cash payment15,000,000 — — 
Payment of post-close settlement3,511,170 — — 
Payments for the Stronghold Acquisition$18,511,170 $177,823,787 $— 
Investing Activities - Noncash
Assumption of suspense liability$— $1,651,596 $— 
Assumption of derivative liabilities— 24,784,406 — 
Assumption of asset retirement obligation— 14,538,550 — 
Deferred cash payment at fair value— 14,807,276 — 
Financing Activities - Noncash
Common stock issued for acquisition— 69,141,555 — 
Convertible preferred stock issued for acquisition— 137,858,446 — 
The accompanying notes are an integral part of these financial statements.

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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 Nevada corporation. Ring Energy, Inc. is referred to herein as the “Company.” The Company owns interests ingrowth oriented independent oil and natural gas properties locatedexploration and production company based in The Woodlands, Texas and is engaged primarily in the acquisition, exploration and development of oil and gas properties and the production and sale of oil and natural gas.

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
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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 theour revolving line of credit approximatesapproximate their fair value because the underlying instruments are at interest rates which approximate current market rates. The carrying amounts of receivablesaccounts 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 managements’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 Accounts ReceivableReceivables – Financial instruments that potentially subject the Company to a concentration of credit risk consist principally of cash and accounts receivable.receivables.
Cash and cash equivalents - The Company has cash in excess of federally insured limits of $70,836,381$46,384 and $14,756,581 at$3,462,526 as of December 31, 20162023 and 2017,2022, 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. Accordingly, no allowanceRefer to the "Major Purchasers" section below for doubtful accounts has been provided atdetail on purchaser activity for the years ended December 31, 20172023, 2022, and 2016.2021.
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.
Joint interest billing receivables, net - The Company also has a joint interest billing receivable. Joint interest billing receivables are collateralized by the pro rata revenue attributable to the joint interest holders and further by the interest itself.

Receivables from joint interest owners outstanding longer than the contractual payment terms are considered past due. The following table indicates the Company's provisions for bad debt expense associated with its joint interest billing receivables during the years ended December 31, 2023, 2022, and 2021.

For the Years Ended December 31,
202320222021
Bad debt expense$134,007$242,247$0
The following table reflects the Company's joint interest billing receivables and allowance for credit losses as of December 31, 2023 and 2022.
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20232022
Joint interest billing receivables$2,480,843 $1,226,049 
Allowance for credit losses(58,569)(242,247)
Joint interest billing receivables, net$2,422,274 $983,802 
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.
Cash and Cash Equivalents – The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

At December 31, 2023 and 2022, the Company had no such investments.

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.

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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, 2017, 20162023, 2022, and 2015.

  For the Years Ended December 31, 
  2017  2016  2015 
          
Depletion $20,197,690  $11,179,858  $14,889,487 
Depletion rate, per barrel-of-oil-equivalent (BOE) $13.92  $12.73  $20.03 

2021.

For the Years Ended December 31,
202320222021
Depletion$87,442,546 $55,029,956 $36,735,070 
Depletion rate, per barrel-of-oil-equivalent (Boe)$13.22 $12.19 $11.82 
In addition, capitalized costs less accumulated depreciation, depletion and amortization and related deferred income taxes shallare 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.

For the years ended December 31, 2016 and 2015, the Company took write downs

No impairments on oil and natural gas properties as a result of the ceiling test in the amount of $56,513,016 and $9,312,203, respectively. No impairment waswere recorded for the yearyears ended December 31, 2017.

2023, 2022 or 2021.

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Land, Buildings, Equipment, andSoftware, Leasehold Improvements, Automobiles, Buildings and Structures – Land, buildings, equipment, andsoftware, leasehold improvements, automobiles, buildings and structures are valuedcarried at historical cost, adjusted for impairment loss lessand accumulated depreciation.depreciation (except for land). Historical costs include all direct costs associated with the acquisition of land, buildings, equipment, andsoftware, 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 equipmentstructures is calculated using the straight-line method based upon the following estimated useful lives:

Leasehold improvements3-103‑5 years
Office equipment and software3-73‑7 years
MachineryEquipment5‑10 years
Automobiles4 years
Buildings and equipmentstructures5-107 years

Depreciation

The following table provides information on the Company's depreciation expense was $320,090, $303,456 and $286,304 for the years ended December 31, 2017, 20162023, 2022, and 2015,2021.
For the Years Ended December 31,
202320222021
Depreciation expense$364,024$205,600$124,961
During the year endedDecember 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:
20232022
Trade accounts payable$37,626,348 $40,480,684 
Revenues payable44,348,938 43,807,208 
Accrued expenses22,088,838 27,110,376 
Accounts payable$104,064,124 $111,398,268 
Trade accounts payable– The following table summarizes the Company's current trade accounts payable at December 31, 2023 and 2022:
20232022
Accounts payable related to vendors$36,944,263 $36,586,007 
Other682,085 3,894,677 
Trade accounts payable$37,626,348 $40,480,684 
Revenues payable– The following table summarizes the Company's current revenues and royalties payable at December 31, 2023 and 2022:
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20232022
Revenue held in suspense$31,592,825 $30,180,940 
Revenues and royalties payable12,756,113 13,626,268 
Revenues payable$44,348,938 $43,807,208 
Accrued expenses – The following table summarizes the Company's current accrued expenses at December 31, 2023 and 2022:
20232022
Accrued capital expenditures$7,518,603 $9,624,985 
Accrued lease operating expenses6,798,548 6,450,356 
Accrued interest3,684,378 3,222,864 
Accrued general and administrative expense4,047,095 4,076,699 
Other40,214 3,735,472 
Accrued expenses$22,088,838 $27,110,376 
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,
202320222021
Interest paid for notes payable$49,734 $25,579 $17,824 
Revenue recognitionRecognition – 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. AtThe 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 endtransaction 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 each month,royalties due to third parties in an amount that reflects the consideration the Company estimates the amount of production deliveredexpects to purchasers and the price received. Variances between the Company’s estimated revenue and actual payment are recordedreceive in the month the payment is received; however, differences have been insignificant.

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 basesbasis of assets and liabilities and their reportedcarrying amounts in the financial statements, and tax carry forwards.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.

On


Since December 22, 2017,31, 2020, the PresidentCompany 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
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by existing deferred tax liabilities as a result of the United States signed into law80% limitation on the Tax Cutsutilization of net operating losses incurred after 2017. Since 2021, commodity prices increased and Jobs Act of 2017 (the “Tax Act”). The SEC subsequently issued a Staff Accounting Bulletin No. 118, “Income tax Accounting Implications of the Tax Cuts and Jobs Act” (“SAB 118”), which provides guidance on accounting for the tax effects of the Tax Act. Under SAB 118, companies are able to record a reasonable estimate of the impacts of the Tax Act if one is able to be determined and report it as a provisional amount during the measurement period. The measurement period is not to extend beyond one year from the enactment date. Impacts of the Tax Act that a company is not able to make a reasonable estimate for should not be recorded until a reasonable estimate can be made during the measurement period. The Company continued to use our historical effective tax rate of 35% in calculating the expense through December 31, 2017. However, at December 31, 2017, the Company assessedcontinues to project positive pre-tax book income. As of June 30, 2023, the value of our Deferred Tax Assets applying the tax rate of 21% that will be effective for future incomes against which those assets will be applied.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 recordedreleased $24.2 million of valuation allowance as a provisional tax expense of $6,603,240benefit during the year ended December 31, 2017.

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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,
202320222021
Deferred federal income tax benefit (provision)$901,522 $(6,437,680)$— 
Current state income tax provision(72,213)— — 
Deferred state income tax provision(954,551)(1,971,044)(90,342)
Provision for Income Taxes$(125,242)$(8,408,724)$(90,342)

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,
202320222021
Effective tax rate0.1 %5.7 %2.6 %

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 generally accepted accounting principles,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 in such jurisdictions.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 jurisdictions.jurisdiction. The Company’s federal income tax returns for the years ended December 31, 2014 through 20172019 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 2013 through 2017.2018 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 generally accepted accounting principles.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 statementsStatements of operations.

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 CustomersPurchasers – During the year ended December 31, 2017,2023, sales to two customersthree purchasers represented 76%66%, 12%, and 18%10%, respectively, orof total oil, natural gas, and natural gas revenues. Atliquids sales. As of December 31, 2017,2023, sales outstanding from these three purchasers represented 65%, 11%, and 8%, respectively, of accounts receivable. During the year ended December 31, 2022, sales to twothree purchasers represented 68%, 13%, and 5%, respectively, of our customers made up 88%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, 2016,2021, sales to two customersthree purchasers represented 50%76%, 7%, and 42%6%, respectively, of total oil and natural gas revenues. Atsales. As of December 31, 2016,2021, sales outstanding from these two customers made up 59%three purchasers represented 75%, 8%, and 32%4%, respectively, of accounts receivable. During the year ended December 31, 2015, sales to three customers represented 48%, 23% and 20%, respectively of total sales. At December 31, 2015, these three customers made up 30%, 53% and 0%, respectively, of accounts receivable. The loss of any of our customers would not have a material adverse effect on the Company as there is an available market for its crude oil and natural gas production from other purchasers.

Stock-Based

Share-Based Employee and Non-Employee Compensation – The Company has outstanding stock optionsoption grants and restricted stock unit awards to directors, employeesofficers and contract employees, which are described more fully below in Note 10."Note 12 — EMPLOYEE STOCK OPTIONS, RESTRICTED STOCK AWARD PLAN, AND 401(K)". The Company accounts for its stock options grants in accordance with generally accepted accounting principles. Generally accepted accounting principles require the recognition ofrecognizes the cost of employee services received in exchange for an award of equity instruments in the financial statements and is measured based on the grant dategrant-date fair value of the award. Generally accepted accounting principles also requires stock optionaward and recognizes the related compensation expense to be recognized over the period during which an employee is required to provide service in exchange for the award, (thewhich is generally the vesting period).

Stock-based employeeperiod.

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, 2017, 20162023, 2022, and 2015 was $3,685,079, $2,267,0532021.
For the Years Ended December 31,
202320222021
Share-based compensation$8,833,425$7,162,231$2,418,323
Derivative Instruments and $2,566,716, respectively.

ReclassificationsHedging Activities –Certain reclassifications 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 amounts previously reportedforward 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 been madea 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 accompanying financial statementsindirect 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 maintain consistency between periods presented.arrive at Net cash provided by operating activities. The reclassifications had no impacttotal Gain (loss) on derivative contracts less the Cash received (paid) for derivative settlements, net income (loss)represents the unrealized (mark to market) gain or stockholders’ equity.

loss on derivative contracts.

Recently Adopted Accounting Pronouncements – In March 2016,August 2018, the Financial Accounting Standards Board (FASB)FASB issued Accounting Standards Update (ASU) 2016-09,Compensation – Stock CompensationASU 2018-13, Fair Value Measurement (Topic 718.)The guidance seeks820): Changes to simplify the accountingDisclosure Requirements for share-based compensation. The new standard requires all excess tax benefitsFair Value Measurement (“ASU 2018-13”). ASU
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2018-13 eliminates, adds and reductions from differences between the deductionmodifies certain disclosure requirements for tax purposesfair value measurement. ASU 2018-13 became effective for annual and the compensation cost recorded for financial reporting purposes be recognized as income tax expense or benefit in the Statement of Operations and not recognized as additional paid-in capital. The new standard also requires all excess tax benefits and deficiencies to be classified as operating activity included with income tax cash flows. Ring adopted this ASU as ofinterim periods beginning January 1, 2017.2020. ASU 2018-13 requires that the additional disclosure requirements be adopted using a retrospective approach. The Company usedadoption of this guidance did not have a material impact on the modified retrospective method to account for unrecognized excess tax benefits from prior periods, resulting in an adjustment to our beginning balances of Deferred Income Taxes and Retained Loss of $1,596,463. The Company will use the prospective method to account for current period and future excess tax benefit. For the year ended December 31, 2017, this resulted in a decrease of $49,896 to our income tax provision. The Company has also elected to continue to estimate the amount of expected forfeitures when calculating share-based compensation, instead of accounting for forfeitures as they occur.

Recent Accounting Pronouncements –Company’s financial statements.

In AugustJune 2016, the FASB issued Accounting Standards Update (ASU) 2016-15, StatementASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Cash Flows (Topic 230)Credit Losses on Financial Instruments, followed by other related ASUs that provided targeted improvements (collectively “ASU 2016-13”). ASU 2016-15 seeks2016-13 provides financial statement users with more decision-useful information about the expected credit losses on financial instruments and other commitments to reduce the existing diversity in practice in how certain cash receiptsextend credit held by a reporting entity at each reporting date. The guidance is to be applied using a modified retrospective method and cash payments are presented and classified in the statement of cash flows. This update isbecame effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted.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 guidance willASU did not have a material impact on the Company’s statement of cash flows.

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financial statements.

In February 2016,August 2020, the FASB issued ASU No. 2016-02, Leases2020-06, “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 841)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 lessees,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.
In December 2023, the FASB issued ASU 2023-09 "Income Taxes (Topic 740): Improvements to Income Tax Disclosures." The amendments from this update provide for more transparency about income tax information through improvements to income tax disclosures primarily related to the rate reconciliation and income taxes paid information. Specifically, public business entities are required to disclose a tabular reconciliation, using both percentages and reporting currency amounts, showing detail from eight specific categories: (a) state and local income tax net of federal (national) income tax effect, (b) foreign tax effects, (c) effect of changes in tax laws or rates enacted in the current period, (d) effect of cross-border tax laws, (e) tax credits, (f) changes in valuation allowances, (g) nontaxable or nondeductible items, and (h) changes in unrecognized tax benefits. In addition, public business entities are required to separately disclose any reconciling item, disaggregated by nature and/or jurisdiction, in which the effect of the reconciling item is equal to or greater than five percent of the amount computed by multiplying the income (or loss) from continuing operations before income taxes by the applicable statutory income tax rate. Also, for the state and local category, a public business entity is required to provide a qualitative description of the states and local jurisdictions that make up the majority (greater than 50 percent) of the category. Further, the amount of income taxes paid (net of refunds received) are required to be disaggregated by (i) federal (national), state, and foreign taxes, and (ii) by individual jurisdictions in which income taxes paid (net of refunds received) is equal to or greater than five percent of total income taxes paid (net of refunds received). Finally, the amendments from this update require that for all leases not considered to be short term, a company recognize both a lease liabilityentities disclose (i) income (or loss) from continuing operations before income tax expense (or benefit) disaggregated between domestic and right-of-use assetforeign and (ii) income tax expense (or benefit) from continuing operations disaggregated by federal, state, and foreign. The Company is currently assessing the impact of adopting this new guidance on its balance sheet, representingfinancial disclosures. For public business entities, the obligation to make payments and the right to use or control the use of a specified asset for the lease term. The amendments in this update are effective for annual periods beginning after December 15, 2018. Upon adoption2024.
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 will begin reflecting long-term future lease payments as bothengages third party sources to validate the estimates. Revenue is recognized net of royalties due to third parties in an asset and a liability on its balance sheet. The adoption of this guidance will not have a material impact on the Company’s financial statements.

In May 2014, the FASB and the International Accounting Standards Board (IASB) issued a joint revenue recognition standard, ASU 2014-09. The new standard removes inconsistencies in existing standards, changes the way companies recognize revenue from contracts with customers, and increases disclosure requirements. The codification was amended through additional ASUs and, as amended, requires companies to recognize revenue to depict the transfer of goods or services to customers in amountsamount that reflectreflects the consideration to which the companyCompany expects to be entitledreceive in exchange for those goods or services.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 guidanceCompany recognizes revenue at the net price received when control transfers to the purchaser at the point of delivery and it is effectiveprobable 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 annualits Central Basin Platform properties and interim periods beginning after December 15, 2017.a portion of its Northwest Shelf assets, the Company delivers unprocessed natural gas to a midstream processing entity at the wellhead. The standardmidstream 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 requiredprobable the Company will collect the consideration it is entitled to be adopted using eitherreceive. As such, the full retrospective approach,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 all prior periods presented adjusted, or 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 retrospective approach,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 cumulative adjustmentnatural 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,
202320222021
Oil, Natural Gas, and Natural Gas Liquids Revenues
Oil$349,044,863 $321,062,672 $181,533,093 
Natural gas (1)
334,175 18,693,631 14,772,873 
Natural gas liquids (1)
11,676,963 7,493,234 — 
Total oil, natural gas, and natural gas liquids revenues$361,056,001 $347,249,537 $196,305,966 
(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 retained earningsJuly 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 opening balance sheet. The Company will adopt the new standard utilizing the modified retrospective approach. Upon preliminary evaluation,agreement and nature of use. These leases are for terms that are less than 12 months and the Company does not expectintend to continue to lease this equipment for more than 12 months. The lease costs associated with these leases is reflected in the adoption of this ASU toshort-term lease costs within Lease operating expenses, shown below.
The Company has financing leases for vehicles. These leases have a material impactterm 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:
20242025202620272028Thereafter
Operating lease payments (1)
$675,210 $727,460 $636,649 $460,497 $250,606 $149,628 
Financing lease payments (2)
1,052,449 713,501 240,503 — — — 
(1)The weighted average annual discount rate as of December 31, 2023 for operating leases was 4.50%. Based on its financial statements.

In January 2017,this rate, the FASB issued ASU 2017-01,Business Combinations (Topic 805): Clarifyingfuture lease payments above include imputed interest of $277,833. The weighted average remaining term of operating leases was 4.32 years.

(2)The weighted average annual discount rate as of December 31, 2023 for financing leases was 6.69%. Based on this rate, the Definitionfuture lease payments above include imputed interest of $143,869. The weighted average remaining term of financing leases was 2.00 years.
The following table represents a Business.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,
20232022
Operating lease liability, current portion568,176 398,362 
Operating lease liability, non-current portion2,054,041 1,473,897 
Operating lease liability, total2,622,217 1,872,259 
Total undiscounted future cash flows (sum of future operating lease payments)2,900,050 2,065,580 
Imputed interest277,833 193,321 
Undiscounted future cash flows less imputed interest2,622,217 1,872,259 
Financing lease liability, current portion956,254 709,653 
Financing lease liability, non-current portion906,330 1,052,479 
Financing lease liability, total1,862,584 1,762,132 
Total undiscounted future cash flows (sum of future financing lease payments)2,006,453 1,900,595 
Imputed interest143,869 138,463 
Undiscounted future cash flows less imputed interest1,862,584 1,762,132 
The guidance assistsfollowing table provides supplemental information regarding lease costs in determining whether a transaction should be accounted for as an acquisition or disposalthe Statements of assets or of a business. This ASU provides a screen that when substantially allOperations:
2023
Operating lease costs$541,801 
Short-term lease costs (1)
$5,096,723 
Financing lease costs:
Amortization of financing lease assets (2)
$803,721 
Interest on financing lease liabilities (3)
$101,269 
(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 fair valueCompany'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 gross assets acquired, or disposed of, are concentrated in a single identifiable asset, or a group of similar identifiable assets,incremental shares is applied.
For the years ended December 31,202320222021
Net Income$104,864,641 $138,635,025 $3,322,892 
Basic Weighted-Average Shares Outstanding190,589,143 121,264,175 99,387,028 
Effect of dilutive securities:
Stock options— 83,384 75,897 
Restricted stock units1,292,582 2,040,181 1,613,810 
Performance stock units438,818 248,206 — 
Common warrants3,044,307 18,118,722 20,116,440 
Diluted Weighted-Average Shares Outstanding195,364,850 141,754,668 121,193,175 
Basic Earnings per Share$0.55 $1.14 $0.03 
Diluted Earnings per Share$0.54 $0.98 $0.03 
The following table presents the set will not be considered a business. If the screen is not met, a set must include an input and a substantive process that together significantly contribute to the ability to create an output to be considered a business. This ASU is effective for annual and interim periods beginning in 2018 and is required to be adopted using a prospective approach, with early adoption permitted for transactions not previously reported in issued financial statements. The Company does not plan on early adoption of the standard. The adoption of this guidance will not have a material impact on the Company’s financial statements.

NOTE 2 – EARNINGS (LOSS) PER SHARE INFORMATION

For the years ended December 31, 2017  2016  2015 
Net Income (Loss) $1,753,869  $(37,637,687) $(9,052,771)
Basic Weighted-Average Shares Outstanding  51,383,008   38,710,626   28,176,924 
Effect of dilutive securities:            
Stock options  1,413,932   -   - 
Restricted stock  9,772   -   - 
Diluted Weighted-Average Shares Outstanding  52,806,712   38,710,626   28,176,924 
Basic Earnings (Loss) per Share $0.03  $(0.97) $(0.32)
Diluted Earnings (Loss) per Share $0.03  $(0.97) $(0.32)

Stock options to purchase 603,500, 3,358,250 and 2,881,150 shares of common stocksecurities which were excluded from the Company's computation of diluted earnings (loss) per share duringfor the years ended December 31, 2017, 20162023, 2022 and 2015, respectively,2021, as their effect would have been anti-dilutive.

As disclosed

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202320222021
Antidilutive securities:
Stock options to purchase common stock264,96670,500113,659
Unvested restricted stock units56,15313,51220,610
Unvested performance stock units1,445,804814,25594,270 

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 Note 15 below, subsequent to December 31, 2017,Andrews County, Texas. Upon closing, the Company issued 6,164,000received 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 underwritten public offering.

NOTE 3 – ACQUISITIONS

In June 2015,asset acquisition in accordance with ASC Topic 805 - Business Combinations. The fair value of the consideration paid by Ring completedand allocation of that amount to the acquisitionunderlying 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 assetsproperties. The inputs and assumptions related to the oil and gas properties were categorized as level 3 in the Ford West Field and Ford Geraldine Unit in Reeves and Culberson Counties, Texas. fair value hierarchy.

The acquired properties consistfollowing table represents the final allocation of 19,983 gross (19,679 net) acres and include a 98% average working interest and a 79% average net revenue interest. Consideration given by the Company consistedtotal cost of cash payments totaling $75,000,000 and the assumption of accounts receivable of approximately $286,563 and accounts payable of approximately $742,332. The Company incurred approximately $129,896 in acquisition related costs, which were recognized in general and administrative expense during the year ended December 31, 2015.

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The acquisition was recognized as a business combination whereby Ring recordedStronghold Acquisition to the assets acquired and the liabilities assumed at their fair values as of the Stronghold Acquisition date:

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Consideration:
Shares of Common Stock issued21,339,986 
Common Stock price as of August 31, 2022$3.24 
Common Stock Consideration$69,141,555 
Shares of Preferred Stock issued153,176 
Aggregate Liquidation Preference$153,176,000 
Conversion Price$3.60 
As-Converted Shares of Common Stock42,548,892 
Common Stock Price as of August 31, 2022$3.24 
Preferred Stock Consideration$137,858,446 
Cash consideration:
Closing amount paid to Stronghold121,392,455 
Escrow deposit paid46,500,000 
Cash paid for inventory and fixed assets4,527,103 
Cash paid for realized losses on August oil derivatives1,777,925 
  Cash received for post-close adjustments, net(5,535,839)
Total cash consideration168,661,644 
Fair value of deferred payment liability14,807,276 
Post-close settlement to be paid to Stronghold3,511,170 
Fair value of consideration paid to seller393,980,091 
Direct transaction costs9,162,143 
Total consideration$403,142,234 
Fair value of assets acquired:
Oil and natural gas properties439,589,683 
Inventory and fixed assets4,527,103 
Amount attributable to assets acquired$444,116,786 
Fair value of liabilities assumed:
Suspense liability1,651,596 
Derivative liabilities, marked to market24,784,406 
Asset retirement obligations14,538,550 
Amount attributable to liabilities assumed$40,974,552 
Net assets acquired$403,142,234 
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 1, 2015, which is the date11, 2023, the Company obtained controlcompleted 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 propertiesdivestiture, 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 wasFounders 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 date for financial reporting purposes.in accordance with ASC 805. The estimated fair value of the acquired properties approximated the consideration paid whichby Ring and allocation of that amount to the Company concluded approximatedunderlying 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 that wouldof the assets and liabilities acquired required judgment and certain assumptions to be paid by a typical market participant. 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 summarizesrepresents the fair valuesfinal allocation of the total cost of the Founders Acquisition to the assets acquired and the liabilities assumed:

Assets acquired    
Proved oil and natural gas properties $78,361,634 
Accounts receivable  400,629 
Liabilities assumed    
Accounts payable  (1,562,147)
Asset retirement obligations  (3,361,634)
Total Identifiable Net Assets $73,838,482 

The following unaudited pro forma information is presented to reflect the operationsassumed as of the Founders Acquisition date:

Consideration:
Cash consideration
Escrow deposit released at closing$7,500,000 
Closing amount paid to Founders42,502,799 
Interest from escrow deposit1,747 
Fair value of deferred payment liability14,657,383 
Post-close adjustments(4,139,244)
Total cash consideration$60,522,685 
Direct transaction costs1,361,843 
Total consideration$61,884,528
Fair value of assets acquired:
Oil and natural gas properties$64,886,472 
Amount attributable to assets acquired$64,886,472 
Fair value of liabilities assumed:
Suspense liability$677,116 
Asset retirement obligations2,090,777 
Ad valorem tax liability234,051 
Amount attributable to liabilities assumed$3,001,944 
Net assets acquired$61,884,528

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 as ifcompleted the Ford West Fielddivestiture 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.
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Table of Contents
Gaines County Texas Sale
On December 29, 2023, the Company completed the sale of specified oil and Ford Geraldine Unit acquisitiongas 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 been completed on Januaryan effective date of December 1, 2015.

For the year ended December 31, 2015 
    
Oil and Gas Revenues $37,253,437 
Net Income (Loss) $(9,097,288)
     
Basic Earnings (Loss) per Share $(0.32)
Diluted Earnings (Loss) per Share $(0.32)

2023. As part of the sale, the buyer assumed an asset retirement obligation balance of approximately $0.5 million.

NOTE 4 –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 Relating to Oil and Natural Gas Producing Activities

As of December 31, 2017  2016 
Proved oil and natural gas properties $433,591,134  $250,133,965 
Inventory for property development  -   1,582,427 
Fixed assets subject to depreciation  1,884,818   1,549,311 
Total capitalized costs  435,475,952   253,265,703 
Accumulated depletion, depreciation and amortization  (61,864,932)  (41,347,152)
         
Net Capitalized Costs $373,611,020  $211,918,551 

Net

As of December 31,20232022
Oil and natural gas properties, full cost method
Proved properties1,663,548,249 1,463,838,595 
Unproved properties— — 
Total oil and natural gas properties, full cost method1,663,548,249 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 
Costs Incurred in Oil and Gas Producing Activities

For the years Ended December 31, 2017  2016 
Acquisition of proved properties $28,682,298  $10,193,927 
Development costs  125,977,758   26,862,680 
         
Total Net Costs Incurred $154,660,056  $37,056,607 

F-12

For the years Ended December 31,202320222021
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 properties152,559,314 129,332,155 51,302,131 
Total costs incurred$235,460,214 $308,719,645 $52,670,568 

NOTE 5 –7 — DERIVATIVE FINANCIAL INSTRUMENTS

The Company is exposed to fluctuations in crude oil and natural gas prices on its production. We canutilizeIt 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.

On September 25, 2017,

From time to time, the Company enteredenters into new derivative contracts in the form of costless collars of WTI Crude Oil prices in order to protect the Company’s cash flow from price fluctuation and maintain its capital programs. “Costless collars”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 tradesuse of derivative transactions involves the risk that the counterparties, which generally are for 1,000 barrelsfinancial institutions, will be unable to meet the financial terms of oil per day.  Forsuch transactions. All of our derivative contracts are with lenders under our Credit Facility. Non-performance risk is incorporated in the period of October 1, 2017 through December 31, 2017,discount rate by adding the put price is $49.00 andquoted bank (counterparty) credit default swap (CDS) rates to the call price is $55.35.  Forrisk free rate. Although the period of January 1, 2018 through December 31, 2018,counterparties hold the put price is $49.00 andright to offset (i.e. netting) the call price is $54.60.

On October 27, 2017,settlement amounts with the Company, entered in additional costless collarsaccordance with ASC 815-10-50-4B, the Company classifies the fair value of WTI Crude Oil. This trade is for the period January 1, 2018 through December 31, 2018 for 1,000 barrelsall its derivative positions on a gross basis in its Balance Sheets.

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Table of oil per day with a put price of $51.00 and a call price of $54.80.

DerivativeContents

The Company’s derivative financial instruments are recorded at fair value and included as either assets or liabilities in the accompanying balance sheets. AnyBalance 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"Other Income (Expense)" under the heading "Gain (loss) on derivative contracts" in the accompanying statementsStatements of operations.

Operations.

The usefollowing presents the impact of the Company’s contracts on its Balance Sheets for the periods indicated.
As of December 31,
20232022
Commodity derivative instruments, marked to market:
Derivative assets, current7,768,697 16,193,327 
Discounted deferred premiums(1,553,323)(11,524,165)
Derivatives assets, current, net of premiums$6,215,374 $4,669,162 
Derivative assets, noncurrent11,634,714 7,606,258 
Discounted deferred premiums— (1,476,848)
Derivative assets, noncurrent, net of premiums$11,634,714 $6,129,410 
Derivative liabilities, current$7,520,336 $13,345,619 
Derivative liabilities, noncurrent$11,510,368 $10,485,650 
The components of “Gain (loss) on derivative transactions involvescontracts” from the risk thatStatements of Operations are as follows for the counterparties, which generallyrespective periods:
For the years ended December 31,
202320222021
Oil derivatives:
Realized loss on oil derivatives$(11,364,484)$(61,875,870)$(53,511,332)
Unrealized gain (loss) on oil derivatives9,462,374 40,546,123 (24,143,120)
Loss on oil derivatives$(1,902,110)$(21,329,747)$(77,654,452)
Natural gas derivatives:
Realized gain (loss) on natural gas derivatives2,279,564 (650,084)743,178 
Unrealized gain (loss) on natural gas derivatives2,389,708 447,172 (941,867)
Gain (loss) on natural gas derivatives$4,669,272 $(202,912)$(198,689)
Gain (loss) on derivative contracts$2,767,162 $(21,532,659)$(77,853,141)
The components of “Cash (paid) received for derivative settlements, net” within the Statements of Cash Flows are financial institutions, will be unable to meetas follows for the financial termsrespective periods:
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Table of such transactions. AtContents
For the years ended December 31,
202320222021
Cash flows from operating activities
Cash paid for oil derivatives$(11,364,484)$(61,875,870)$(53,511,332)
Cash (paid) received on natural gas derivatives2,279,564 (650,084)743,178 
Cash paid for derivative settlements, net$(9,084,920)$(62,525,954)$(52,768,154)

The following tables reflect the details of current derivative contracts as of December 31, 2017, 100%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 2024Q2 2024Q3 2024Q4 2024Q1 2025Q2 2025Q3 2025Q4 2025
Swaps:
Hedged volume (Bbl)170,625 156,975 282,900 368,000 — — 184,000 — 
Weighted average swap price$67.40 $66.40 $65.49 $68.43 $— $— $73.35 $— 
Deferred premium puts:
Hedged volume (Bbl)45,500 45,500 — — — — — — 
Weighted average strike price$84.70 $82.80 $— $— $— $— $— $— 
Weighted average deferred premium price$17.15 $17.49 $— $— $— $— $— $— 
Two-way collars:
Hedged volume (Bbl)371,453 334,947 230,000 128,800 474,750 464,100 225,400 404,800 
Weighted average put price$64.27 $64.32 $64.00 $60.00 $57.06 $60.00 $65.00 $60.00 
Weighted average call price$79.92 $79.16 $76.50 $73.24 $75.82 $69.85 $78.91 $75.68 
Gas Hedges (Henry Hub)
Q1 2024Q2 2024Q3 2024Q4 2024Q1 2025Q2 2025Q3 2025Q4 2025
NYMEX Swaps:
Hedged volume (MMBtu)101,615 138,053 121,587 644,946 616,199 591,725 285,200 — 
Weighted average swap price$3.62 $3.61 $3.59 $4.45 $3.78 $3.43 $3.73 $— 
Two-way collars:
Hedged volume (MMBtu)417,000 605,150 584,200 27,600 27,000 27,300 308,200 598,000 
Weighted average put price$3.94 $3.94 $3.94 $3.00 $3.00 $3.00 $3.00 $3.00 
Weighted average call price$6.15 $6.16 $6.17 $4.15 $4.15 $4.15 $4.75 $4.15 
Oil Hedges (basis differential)
Q1 2024Q2 2024Q3 2024Q4 2024Q1 2025Q2 2025Q3 2025Q4 2025
Argus basis swaps:
Hedged volume (Bbl)240,000 364,000 368,000 368,000 270,000 273,000 276,000 276,000 
Weighted average spread price (1)
$1.15 $1.15 $1.15 $1.15 $1.00 $1.00 $1.00 $1.00 

(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 our volumes subject to derivative instruments are with lenders under our credit facility.

Argus Americas Crude.


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NOTE 6 –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.

F-13

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.

  Fair Value Measurement Classification    
  Quoted prices in
Actives Markets
for Identical Assets
or (Liabilities)
(Level 1)		  Significant Other
Observable Inputs
(Level 2)		  Significant
Unobservable
Inputs (Level 3)		  Total 
As of December 31, 2017                
                 
Oil and gas derivative contracts $-  $(3,968,286) $-  $(3,968,286)
                 
Total $-  $(3,968,286) $-  $(3,968,286)

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
Commodity Derivatives - Assets
$— $10,798,572 $— $10,798,572 
Commodity Derivatives - Liabilities— (23,831,269)— (23,831,269)
Total$— $(13,032,697)$— $(13,032,697)
As of December 31, 2023
Commodity Derivatives - Assets$— $17,850,088 $— $17,850,088 
Commodity Derivatives - Liabilities— (19,030,704)— (19,030,704)
Total$— $(1,180,616)$— $(1,180,616)
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 7 –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 (“Administrative(the “Administrative Agent”), which(which was amended on May 18, 2016, June 26, 2015several 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 July 24, 2014restated the Credit Agreement with the Administrative Agent (as amended and restated, the “Credit Facility”).  The
On August 31, 2022, the Company modified its Credit Facility providesthrough 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 senior secured revolving credit facility with a maximum borrowing amountbase of $500$600 million. The Credit Facility matures on June 26, 2020, and is secured by substantially all of the Company’s assets.

In May 2016, the borrowing base (the “Borrowing Base”) was reduced from the initial $100 million to $60 million. The Borrowing Base is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time. The Borrowing Base will beborrowing base is redetermined semi-annually on each May 1 and November 1, beginning November 1, 2015.November. The Borrowing Base will also be reducedborrowing 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.

The

Rather than Eurodollar loans, the reference rate on the Second Credit Facility allowsAgreement is the SOFR. Also, the Second Credit Agreement permits the Company to declare dividends for Eurodollar Loansits 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 Base Rate Loans (each asamortization, 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 Facility)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 EurodollarSOFR Loan will be the adjusted LIBORterm SOFR for the applicable interest period plus a margin between 1.75%3.0% and 2.75%4.0% (depending on the then-current level of borrowing base usage). The annual interest rate on each Base Rate
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base rate Loan is (a) the greatest of (i) the Administrative Agent’s prime lending rate, (ii) the federal funds rateFederal Funds Rate (as defined in the Second Credit Agreement) plus 0.5% per annum, or(iii) the (iii) adjusted LIBORterm SOFR determined on a daily basis for an interest period of one-month,one month, plus 1.00% per annum and (iv) 0.00% per annum, plus (b) a margin between 2.75%2.0% and 3.75%3.0% per annum (depending on the then-current level of borrowing base usage).

The Second Credit FacilityAgreement contains certain covenants, which, among other things, require the maintenance of (i) a total leverage ratioLeverage Ratio of not more than 4.03.0 to 1.0 and (ii) a minimum current 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 FacilityAgreement 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, 2017,2023, $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 no amounts were outstanding onstandby 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 Credit Facility.

F-14
$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.

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Table of Contents
NOTE 8 –10 — ASSET RETIREMENT OBLIGATION

A reconciliation of the asset retirement obligation for the years ended December 31, 2015, 20162023, 2022 and 20172021 is as follows:

Balance, December 31, 2014 $3,896,489 
Liabilities acquired  3,361,634 
Liabilities incurred  171,635 
Liabilities settled  (446,192)
Accretion expense  418,384 
Balance, December 31, 2015 $7,401,950 
Liabilities incurred  308,509 
Liabilities settled  (240,606)
Accretion expense  487,182 
Balance, December 31, 2016 $7,957,035 
Liabilities incurred  1,297,289 
Liabilities settled  (766,595)
Accretion expense  567,968 
Balance, December 31, 2017 $9,055,697 

Balance, December 31, 2020$17,117,135 
Liabilities acquired662,705 
Liabilities incurred171,390 
Liabilities sold(2,934,126)
Liabilities settled(904,514)
Revision of estimate (1)
435,419 
Accretion expense744,045 
Balance, December 31, 2021$15,292,054 
Liabilities acquired14,538,550 
Liabilities incurred353,008 
Liabilities sold— 
Liabilities settled(940,738)
Revision of estimate (1)
— 
Accretion expense983,432 
Balance, December 31, 2022$30,226,306 
Liabilities acquired2,090,777 
Liabilities incurred439,528 
Liabilities sold(5,340,211)
Liabilities settled(647,828)
Revision of estimate (1)
53,826 
Accretion expense1,425,686 
Balance, December 31, 2023$28,248,084 
(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, 2023December 31, 2022
Asset retirement obligations, current$165,642 $635,843 
Asset retirement obligations, non-current28,082,442 29,590,463 
Asset retirement obligations$28,248,084 $30,226,306 
NOTE 9 – STOCKHOLDERS’11 — STOCKHOLDERS' EQUITY

The Company iswas authorized to issue 150,000,000225,000,000 shares of common shares,stock, with a par value of $0.001 per share, and 50,000,000 shares of Preferred Stock.

Common Stock Issued in Public Offering–In June 2015,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 closed an underwritten public offering of 4,500,000 shares of its common stock at $11.50 per share for gross proceeds of $51,750,000. In July 2015,to increase the Company closed on the over-allotment associated with this offering, resulting in the issuance of an additional 100,000authorized shares of common stock at $11.50 per share, for gross proceedsfrom 225,000,000 to 450,000,000.

Issuance of $1,150,000. Total net proceeds from the offering were $50,039,853, after deducting commissionsequity instruments in public and offering expenses payable by the Company of approximately $2,860,147.

private offerings – In April 2016,October 2020, the Company closed on an underwritten public offering of 11,500,000(i) 9,575,800 shares of its common stock, including 1,500,000 shares sold pursuant(ii) 13,428,500 Pre-Funded Warrants and (iii) 23,004,300 warrants to the fullpurchase common stock (the “Common Warrants”) at a combined purchase price of $0.70. This includes a

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partial exercise of the over-allotment. The Common Warrants have a term of five years ending in October 2025 and an over-allotment option, at $5.60exercise price of $0.80 per share for grossshare. Gross proceeds of $64,400,000. Total net proceeds fromtotaled $16,089,582.
Concurrently with the underwritten public offering, were $61,063,497, after deducting underwriting commissions and offering expenses payable by the Company of $3,336,503.

In December 2016, 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 of 7,195,387and the registered direct offering aggregated $20,846,282. Total net proceeds for the Common Warrants exercised in 2020 aggregated $19,379,832.
Common stock issued pursuant to warrant exercise - In December 2020, the Company issued 3,300,000 shares of its common stock including 670,387 shares sold pursuant to the partial 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 over-allotment option, at $11.50aggregate 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 $82,746,951. Total net proceeds$8,997,543 from the offering were $78,485,787, after deducting underwriting commissions and offering expenses payableexercise of the common warrants by the Company of $4,261,164.

In July 2017, the Company closed on an underwritten public offering of 4,977,658 shares of its common stock, including 477,658 shares soldParticipating Holders pursuant to the partial exerciseExercise Agreement, which was recognized as an equity issuance cost in accordance with ASC 815-40-35-17(a). In the Statements of an over-allotment option, at $12.50 perStockholders' 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 gross proceedsthe purchase price consideration allocated to the aforementioned stock issuances.
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Table of $62,220,725. Total net proceeds from the offering were $59,026,956, after deducting underwriting commissions and offering expenses payable by the Company of $3,193,769.

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Common Stock Issuedstock issued for option exercises– During the years ended December 31, 2015, 20162022 and 2017,2021, the Company issued 56,875, 26,33452,494 and 133,308100,000 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 thosethe exercises:

  Options
exercised		  

Exercise

price ($)

  

Shares

issued

  

Shares

retained

  

Cash paid at

exercise ($)

  

Stock price on

date of exercise

($)

  Aggregate value
of shares retained
($)		 
2015  10,000  $2.00   8,115   1,885  $-  $10.61  $20,000 
   5,000   4.50   5,000   -   22,500   10.00   - 
   20,000   2.00   20,000   -   40,000   10.14   - 
   10,000   4.50   6,127   3,873   -   11.62   45,000 
   5,000   5.50   2,633   2,367   -   11.62   27,500 
   15,000   4.50   15,000   -   67,500   11.06   - 
   600   8.00   600   -   4,800   8.07   - 
                             
2015 Totals  65,600       57,475   8,125  $134,800      $92,500 
2015 Weighted Averages     $3.46              $10.73     

  

Options

exercised

  

Exercise

price ($)

  

Shares

issued

  

Shares

retained

  

Cash paid at

exercise ($)

  

Stock price on

date of exercise

($)

  

Aggregate value

of shares retained

($)

 
2016  5,000  $4.50   5,000   -  $22,500  $4.72  $- 
   20,000   4.50   20,000   -   90,000   7.29   - 
   150   2.00   119   31   -   9.72   300 
   350   2.00   276   74   -   9.46   700 
   400   2.00   339   61   -   13.05   800 
                             
2016 Totals  25,900       25,734   166  $112,500      $1,800 
2016 Weighted Averages     $4.41              $6.93     

  

Options

exercised

  

Exercise

price ($)

  

Shares

issued

  

Shares

retained

  

Cash paid at

exercise ($)

  

Stock price on

date of exercise

($)

  

Aggregate value

of shares retained

($)

 
2017  4,100  $2.00   3,491   609  $-  $13.47  $8,200 
   60,000   2.00   50,156   9,844   -   12.19   120,000 
   200   8.00   116   84   -   13.75   1,600 
   1,500   10.89  ��1,188   312   -   13.75   16,335 
   600   5.25   229   371   -   13.75   3,150 
   20,000   5.50   11,953   8,047   -   13.67   110,000 
   2,000   8.00   830   1,170   -   13.67   16,000 
   2,000   5.25   1,232   768   -   13.67   10,500 
   15,000   2.00   12,875   2,125   -   14.12   30,000 
   60,000   2.00   51,238   8,762   -   13.70   120,000 
                             
2017 Totals  165,400       133,308   32,092  $-      $435,785 
2017 Weighted Averages     $2.63              $13.18     

F-16

Options
exercised		Exercise
price ($)		Shares
issued		Shares
retained		Cash paid at
exercise ($)		Stock price
on date of exercise
($)		Aggregate value
of shares retained
($)
2021100,000$2.00 100,000—$200,000 $3.14 $— 
2021 Totals100,000100,000—$200,000 — 
2021 Weighted Averages$2.00 $3.14 

Options
exercised		Exercise
price ($)		Shares
issued		Shares
retained		Cash paid at
exercise ($)		Stock price
on date of exercise
($)		Aggregate value
of shares retained
($)
2022100,000$2.00 52,49447,506$— $4.21 $200,000 
2022 Totals100,00052,49447,506$— 200,000 
2022 Weighted Averages$2.00 $4.21 
NOTE 10 –12 — EMPLOYEE STOCK OPTIONS, AND 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 Company’s Board of Directors approved and adopted a long termlong-term incentive plan (the “2011 Plan”), which was subsequently approved and amended by the shareholders. There were 1,040,200536,755 shares eligible for grant, either as stock options or as restricted stock, atas of December 31, 2017.

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 – Following is a table reflecting the issuances during 2015, 2016 and 2017 and their related exercise prices:

Grant date # of options  Exercise price 
April 1, 2015  3,750  $10.89 
December 9, 2015  291,000   8.25 
         
January 13, 2016(1)  241,000  $5.25 
May 3, 2016  15,000   6.42 
December 13, 2016  582,500   11.75 
         
April 20, 2017  7,500  $11.70 
         
   1,140,750     

(1) On December 9, 2015, Ring issued option awards to its named executive officers and directors. On January 13, 2016, upon the recommendation of the Compensation Committee, Ring rescinded the option awardsNo stock options were granted to its employees and directors (other than Messrs. McCabe and Rochford, who are the members of the Compensation Committee) as the result of a significant decline in the years ended December 31, 2023, 2022, or 2021. All outstanding stock price and re-issued the option awards as of that date to meet the goals and objectives of the Company’s equity based compensation program. The amounts shown as Option Awards include the additional fair value of the new options over the original grant.

All granted options vest at the rate of 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, 2017, 20162023, 2022, and 20152021 and changes during the years ended December 31, 2017, 20162023, 2022, and 20152021 is as follows:

  2017  2016  2015 
  Options  Weighted-
Average
Exercise Price		  Options  Weighted-
Average
Exercise Price		  Options  Weighted-
Average
Exercise Price		 
Outstanding at beginning of the year  3,362,350  $5.90   2,881,750  $5.07   2,684,500  $4.67 
Issued  7,500   11.70   838,500   9.79   294,750   8.28 
Forfeited or rescinded  (11,450)  10.12   (331,400)  8.62   (32,500)  4.47 
Exercised  (165,400)  2.63   (26,500)  4.41   (65,000)  3.46 
                         
Outstanding at end of year  3,193,000  $6.07   3,362,350  $5.90   2,881,750  $5.07 
                         
Exercisable at end of  year  2,091,900  $4.85   1,722,850  $4.01   1,214,000  $3.85 
                         
 Weighted average fair value of options granted during the year     $9.14      $9.72      $6.55 

F-17

202320222021
OptionsWeighted-
Average
Exercise Price		OptionsWeighted-
Average
Exercise Price		OptionsWeighted-
Average
Exercise Price
Outstanding at beginning of year265,500$4.21 365,500$3.61 465,500$3.26 
Granted—— —— —— 
Forfeited—— —— —— 
Expired(195,000)2.00 —— —— 
Exercised—— (100,000)2.00 (100,000)2.00 
Outstanding at end of year70,500$10.33 265,500$4.21 365,500$3.61 
Exercisable at end of year70,500$10.33 265,500$4.21 365,500$3.61 

The Company uses the Black-Scholes option pricing model to calculate the fair-value of each option grant. The expected volatility is based on the historical price volatility of the Company’s common stock. We elected to use the simplified method for estimating the expected term as allowed by generally accepted accounting principles for options granted during the years ended December 31, 2017, 2016 and 2015. Under the simplified method, the expected term is equal to the midpoint between the vesting period and the contractual term of the stock option. The risk-free interest rate represents the U.S. Treasury bill rate for the expected life of the related stock options. The dividend yield represents the Company’s anticipated cash dividend over the expected life of the stock options. The following are the Black-Scholes weighted-average assumptions used for options granted during the periods ended December 31, 2017, 2016 and 2015:

  Risk free interest rate  Expected life (years)  Dividend yield  Volatility 
             
April 1, 2015  1.32%  6.5   -   103%
December 9, 2015  1.64%  6.5   -   100%
                 
January 13, 2016  1.51%  6.5   -   100%
May 3, 2016  1.25%  6.5   -   99%
December 13, 2016  1.92%  6.5   -   96%
                 
April 20, 2017  1.78%  6.5   -   94%

For the years ended December 31, 2017, 20162023, 2022, and 2015,2021, the Company incurred stock basedshare-based compensation expense related to stock options of $3,618,309, $2,267,053$0, $0, and $2,566,716,$20,934, respectively. As of December 31, 2017, there was $3,741,9972023, the Company had $0 of unrecognized compensation cost related to stock options that will be recognized over a weighted average period of 2.5 years.options. The aggregate intrinsic value of options vested and expected to vest atas of December 31, 20172023 was $25,126,363.$0. The aggregate intrinsic value of options exercisable at December 31, 20172023 was $19,884,600.$0. The year-end intrinsic values are based on a December 31, 20172023 closing stock price of $13.90.

Options$1.46.

No stock options were exercised during 2023. Stock options exercised of 165,400100,000 shares in 2017, 26,500 in 2016 and 65,000 in 20152022 had an aggregate intrinsic value on the date of exercise of $1,744,047, $65,089 and $476,642, respectively.

$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 atas of December 31, 2017:

   Options Outstanding    
Exercise price  Number
Outstanding		  Weighted-
Average
Remaining
Contractual Life
(in years)		  Number
Exercisable		 
 2.00   555,000   4.17   555,000 
 4.50   1,340,000   5.24   1,080,000 
 5.50   5,000   5.45   - 
 7.50   29,000   5.73   23,000 
 10.00   90,000   6.21   72,000 
 14.54   20,000   6.99   12,000 
 8.00   282,500   7.17   168,700 
 8.25   50,000   8.19   20,000 
 5.25   223,000   8.28   45,000 
 6.42   15,000   8.59   3,000 
 11.75   576,000   9.20   115,200 
 11.70   7,500   9.30   - 
               
     3,193,000   6.27   2,093,900 

Any excess tax benefits from the exercise2023:

Options Outstanding
Exercise priceNumber
Outstanding		Weighted-
Average
Remaining
Contractual Life
(in years)		Number
Exercisable
5.50 5,0000.215,000
14.54 10,0001.7410,000
8.00 4,5001.924,500
6.42 15,0002.3415,000
11.75 36,0002.9536,000
$10.33 70,5002.3970,500
F-33
Table of stock options will not be recognized in paid-in capital until the Company is in a current tax paying position. Presently, the company has a net loss and therefore not yet subject to income taxes. Accordingly, no excess tax benefits have been recognized for the years ended December 31, 2017, 2016 or 2015.

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Restricted stock unit grants – Following is a table reflecting the restricted stock unit grants during 2017. No restricted stock was granted during 2015 or 2016.

2023, 2022 and 2021:
Grant date
# of shares of
restricted stock
 units
DecemberApril 30, 202133,950
June 17, 20211,162,152
July 6, 202111,824
July 12, 20214,007
September 1, 202110,417
September 8, 20213,306
February 9, 20221,247,061
April 13, 20227,143
May 10, 202210,349
June 16, 20222,150
July 14, 20228,547
August 29, 202230,581
September 1, 202237,797
September 19, 2017202249,645
February 16, 2023330,9002,270,842

All restricted

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 as of December 31, 2017 and changes during the years ended December 31, 20172023, 2022 and 2021 is as follows:

  2017 
  Restricted stock  Weighted-
Average Grant
Date Fair Value		 
Outstanding at beginning of the year  -  $- 
Granted  330,900   13.44 
Forfeited or rescinded  -   - 
Vested  -   - 
         
Outstanding at end of year  330,900  $13.44 

No restricted stock was granted prior to 2017.

No restricted stock vested during 2017.

202320222021
Restricted stock unitsWeighted-
Average Grant
Date Fair Value		Restricted stock unitsWeighted-
Average Grant
Date Fair Value		Restricted stock unitsWeighted-
Average Grant
Date Fair Value
Outstanding at beginning of year2,623,790$2.29 2,572,596$1.75 2,132,297$2.94 
Granted2,270,8422.22 1,393,2732.83 1,225,6562.77 
Forfeited or rescinded(66,174)2.22 (31,185)2.83 — — 
Vested(1,680,232)1.99 (1,310,894)1.79 (785,357)1.37 
Outstanding at end of year3,148,226$2.40 2,623,790$2.29 2,572,596$1.75 
For the yearyears ended December 31, 2017,2023, 2022 and 2021, the Company incurred stock basedshare-based compensation expense related to restricted stock unit grants of $66,770. No such expense was incurred during 2016 or 2015.$4,537,026, $4,148,639, and $2,225,895, respectively. As of December 31, 2017, there was $4,380,5262023, 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 2.01.72 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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860,216 PSUs were granted to the Company’s five executive officers (the “2021 PSU Awards”). The performance period for the 2021 PSU Awards began on January 1, 2021, and ended on December 31, 2023. Based on the achievement of the performance goals for the 2021 PSU Awards, a total of 1,170,024 PSUs vested on December 31, 2023. On February 9, 2022, the Company granted a total of 860,216 PSUs to the Company's five executive officers (the "2022 PSU Awards"). The performance period for the 2022 PSU Awards began on January 1, 2022, and will end on December 31, 2024. The PSUs are performance-based restricted stock units subject to the terms of the 2021 Plan and the PSU Agreement. On February 16, 2023, the Company granted a total of 1,162,162 PSUs to the Company's five executive officers (the "2023 PSU Awards"). The performance period for the 2023 PSU Awards began on January 1, 2023, and will end on December 31, 2025.
A summary of the status of the PSU awards and changes during the years ended December 31, 2023, 2022 and 2021 are as follows:
202320222021
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 year1,720,432$3.76 860,216$3.87 —$— 
Granted1,162,1622.71 860,2163.65 860,2163.87 
Incremental performance stock units vested309,808— —— —— 
Forfeited or rescinded—— —— —— 
Vested(1,170,024)3.66—— —— 
Outstanding at end of year2,022,378$3.11 1,720,432$3.76 860,216$3.87 
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:
202320222021
Employer safe harbor match$346,268 $284,094 $228,273 
NOTE 11 –13 — RELATED PARTY TRANSACTIONS

The Company is leasingleased office space in Tulsa, Oklahoma, from Arenaco, LLC (“Arenaco”), a company that iswas owned by
two of stockholders’stockholders of the Company, Mr. Rochford, former Chairman of the Board, of the Company, and Mr. McCabe, a Directorformer director of the
Company. During the yearsyear ended December 31, 2017, 2016 and 2015,2021, the Company paid $60,000, $60,000$10,000 to Arenaco. The month-to-month
Arenaco lease was terminated as of March 31, 2021.
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Table of Contents

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 $60,000, respectively,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 this company.

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 12 –14 — COMMITMENTS AND CONTINGENT LIABILITIES

CONTINGENCIES

Standby Letters of Credit– A commercial bank has 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 statesstate and federal agencies are extended for a term of Texas and Kansas totaling $280,000 to allow the Company to do business in those states.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 those states.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.

Operating leases

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 following table summarizes our future estimated office lease paymentssurety bonds are valid until canceled or matured. The terms of the surety bonds are extended for periods subsequent to December 31, 2017. The leases pertain to approximately 15,000 square feeta term of space for our corporate headquarters in Midland, Texas, approximately 3,700 square feet of office space for our accounting offices in Tulsa, Oklahoma and approximately 2,000 square feet of office space for our field office in Andrews, Texas.one year at a time. The Company incurred lease expensesdoes not intend to renew the surety bonds in the State of $543,770, $527,582 and $526,658 for the years ended December 31, 2017, 2016 and 2015, respectively. The following table reflects the future minimum lease payments under the operating leaseNew Mexico, as these operated assets have now been sold to a third party. As of December 31, 2017.

Year Lease Obligation 
    
2018 $531,550 
2019 $539,675 
2020  37,725 
     
  $1,108,950 

F-19
2023, the Company had remaining surety bonds in total of $25,000.

NOTE 13 –15 — INCOME TAXES

For the years ended December 31, 2017, 20162023, 2022, and 2015,2021, components of our provision for income taxes are as follows:

Provision for Income Taxes 2017  2016  2015 
Deferred taxes $10,416,171  $(19,987,585) $(5,003,713)
Provision for (Benefit from) Income Taxes $10,416,171  $(19,987,585) $(5,003,713)

Provision for Income Taxes:202320222021
Federal deferred tax$(901,522)$6,437,680 $— 
State current tax72,213 — — 
State deferred tax954,551 1,971,044 90,342 
Provision for Income Taxes$125,242 $8,408,724 $90,342 
The following is a reconciliation of income taxes computed using the U.S. federal statutory rate to the provision for income taxes:

Rate Reconciliation 2017  2016  2015 
Tax at federal statutory rate (34%) $4,194,556  $(19,592,592) $(4,779,205)
Non-deductible expenses  6,158   2,558   6,599 
Excess tax benefit from stock option exercises  (453,217)  15,055   (89,597)
Adjust prior estimates to tax return  (58,766)  167,526   - 
States taxes, net of Federal benefit  124,200   (580,132)  (141,510)
Effect of departure from State of Kansas  (350,059)  -   - 
Adjustment for change in future effective tax rate(1)  6,953,299   -   - 
Provision for (Benefit from) Income Taxes $10,416,171  $(19,987,585) $(5,003,713)

Rate Reconciliation:202320222021
Pre-tax book income (1)
$104,917,670 $147,043,749 $3,413,234 
Tax at federal statutory rate$22,032,711 $30,879,187 $716,779 
Excess tax benefit from stock option exercises and restricted stock vesting478,304 (312,268)(175,187)
Adjust prior estimates to tax return(474,617)214,740 2,938,948 
States taxes, net of federal benefit1,122,782 1,443,145 430,654 
Valuation allowance(24,182,975)(24,151,242)(3,827,194)
Non-deductible expenses and other1,149,037 335,162 6,342 
Provision for Income Taxes$125,242 $8,408,724 $90,342 
(1) Amount represents pre-tax book income, net of income taxes paid.
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The enactmentCompany's deferred tax position reflects the net tax effects of the Tax Cutstemporary differences between the carrying amounts of assets and Jobs Act providedliabilities for a decrease infinancial reporting purposes and the corporateamounts used for income tax rate to 21% from 35%, resulting in a net $6.95 million reduction to our net deferred tax asset as of December 31, 2017.

reporting. The net deferred taxes consisted of the following atas of December 31, 20172023 and 2016:

Deferred Taxes: 2017  2016 
Deferred tax liabilities        
Property and equipment $27,563,290  $10,092,289 
         
Deferred tax assets        
Stock-based compensation  6,667,643   3,814,909 
Operating loss and IDC carryforwards  32,127,847   26,329,288 
Deferred tax assets  38,795,490   30,144,197 
Net deferred income tax asset $(11,232,200) $(20,051,908)

2022:

12/31/2023
Total		12/31/2022
Total
Deferred Tax Assets
Net operating loss (NOL) carryforward82,011,212 70,564,004 
Equity compensation1,372,277 1,554,680 
Asset retirement obligation6,165,239 6,635,099 
Fair market value of derivatives224,209 2,827,202 
§163(j) business interest expense carryforward12,854,900 4,917,358 
Others1,638,297 1,173,441 
Gross Deferred Tax Assets104,266,134 87,671,784 
Less: valuation allowance— (24,182,975)
Net Deferred Tax Assets104,266,134 63,488,809 
Deferred Tax Liabilities
Property and equipment(111,872,367)(71,402,820)
Other(945,812)(585,005)
Net Deferred Liabilities(112,818,179)(71,987,825)
Net Deferred Tax Liabilities(8,552,045)(8,499,016)
As of December 31, 2017,2023, the Company had net operating loss carry forwardscarryforwards for federal income tax reporting purposes of approximately $106.9$109.3 million which, if unused, will begin to expire in 2027 and fully expire in 2037.

F-20
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.

NOTE 14 – QUARTERLY FINANCIAL DATE (UNAUDITED)

  2015 
  Three Months Ended 
  March 31  June 30  September 30  December 31 
Revenues $6,045,701  $8,976,790  $8,629,007  $7,362,394 
Operating Income (Loss)  (1,549,389)  1,019,686   (1,473,514)  (11,311,117)
Net Income (Loss)  (975,624)  534,167   (1,138,268)  (7,473,046)
Basic Net Income (Loss) Per Share $(0.04) $0.02  $(0.04) $(0.25)
Diluted Net Income (Loss) Per Share  (0.04)  0.02   (0.04)  (0.25)

  2016 
  Three Months Ended 
  March 31  June 30  September 30  December 31 
Revenues $6,092,388 ��$7,104,609  $7,822,543  $9,830,709 
Operating Income (Loss)  (23,833,480)  (25,516,087)  (9,121,201)  1,438,007 
Net Income (Loss)  (15,275,044)  (15,941,500)  (5,944,137)  (477,006)
Basic Net Income (Loss) Per Share $(0.50) $(0.41) $(0.14) $(0.01)
Diluted Net Income (Loss) Per Share  (0.50)  (0.41)  (0.14)  (0.01)

  2017 
  Three Months Ended 
  March 31  June 30  September 30  December 31 
Revenues $12,243,793  $14,503,309  $16,643,930  $23,308,668 
Operating Income  2,502,852   2,621,612   4,292,081   6,550,596 
Net Income (Loss)  1,279,281   1,910,763   3,073,760   (4,509,935)
Basic Net Income (Loss) Per Share $0.03  $0.04  $0.06  $(0.08)
Diluted Net Income (Loss) Per Share  0.03   0.04   0.06   (0.08)

NOTE 15 – SUBSEQUENT EVENTS

Subsequent toAs of December 31, 2017,2023, 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 drew $10 million dollarswas 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 Company’s Credit Facility.

Subsequent tochange 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, 2017,2023. This resulted in an ending federal net deferred tax liability of $5,536,158. Additionally, the Company closed on an underwritten public offeringreported a net state deferred tax liability at December 31, 2023 of 6,164,000 shares$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
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contract, money had and received by fraudulent inducement, unjust enrichment and constructive trust. The plaintiff is requesting its common stock, including 804,000 shares sold pursuant to the full exerciseforfeited deposit of an over-allotment option, at $14.00 per share for gross proceeds of $86,296,000. Total net proceeds from the offering were approximately $81.8 million, after deducting underwriting commissions and offering expenses payable$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 approximately $4.5 million.

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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.

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.
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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 put options,derivatives, and other financing expense. Income taxes are based on statutory tax rates, reflecting allowable deductions.

For the years ended December 31, 2017  2016  2015 
Oil and gas sales $66,699,700  $30,850,248  $31,013,392 
Production costs  (15,978,362)  (9,867,800)  (9,958,380)
Production taxes  (3,152,562)  (1,504,620)  (1,468,073)
Depreciation, depletion, amortization and accretion  (21,085,748)  (11,970,496)  (15,594,175)
Ceiling test impairment  -   (56,513,016)  (9,312,203)
General and administrative (exclusive of corporate overhead)  (995,265)  (1,082,360)  (1,242,524)
Results of Oil and Gas Producing Operations $25,487,763  $(50,088,044) $(6,561,963)

For the years ended December 31,202320222021
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 31,202320222021
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 properties152,559,314 129,332,155 51,302,131 
Total costs incurred$235,460,214 $308,719,645 $52,670,568 
Capitalized Costs
As of December 31,20232022
Oil and natural gas properties, full cost method
Proved properties1,663,548,249 1,463,838,595 
Unproved properties— — 
Total oil and natural gas properties, full cost method1,663,548,249 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 natural gas liquids)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 year88,704,743157,870,44923,105,658138,122,143
Purchase of minerals in place6,543,6403,372,9651,089,3828,195,183
Extensions, discoveries and improved recovery3,098,8454,113,4801,014,3434,798,768
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 year82,141,277146,396,32223,218,564129,759,229
Proved Developed at beginning of year57,012,137106,399,05015,332,80490,078,116
Proved Undeveloped at beginning of year31,692,60651,471,3997,772,85448,044,027
Proved Developed at end of year56,029,03999,896,02215,449,90788,128,284
Proved Undeveloped at end of year26,112,23846,500,3007,768,65741,630,945
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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 year65,838,60971,773,789—77,800,907
Purchase of minerals in place28,086,920108,456,10716,715,62662,878,564
Extensions, discoveries and improved recovery628,978522,17852,810768,818
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)6,708,5591,186,108
End of year88,704,743157,870,44923,105,658138,122,143
  
Proved Developed at beginning of year36,820,82439,748,880—43,445,637
Proved Undeveloped at beginning of year29,017,78532,024,909—34,355,270
Proved Developed at end of year57,012,137106,399,05015,332,80490,078,116
Proved Undeveloped at end of year31,692,60651,471,3997,772,85448,044,027

(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.

For the Year Ended December 31, 2017  2016 
  Oil(1)  Natural Gas(1)  Oil(1)  Natural Gas(1) 
Proved Developed and Undeveloped Reserves                
Beginning of year  24,999,100   16,454,849   22,312,450   12,539,600 
Purchases of minerals in place  21,855   -   -   - 
Improved recovery and extensions  8,752,269   5,123,652   3,714,442   2,366,395 
Sale of minerals in place  (26,593)  (251,071)  -   - 
Production  (1,311,727)  (761,517)  (728,051)  (900,089)
Revision of previous estimate  (3,491,162)  (2,528,424)  (299,741)  2,448,943 
                 
End of year  28,943,742   18,037,489   24,999,100   16,454,849 
                 
Proved Developed at end of year  15,321,600   12,647,200   7,309,800   9,437,000 

1Oil reserves are stated in barrels; gas reserves are stated in thousand cubic feet.

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Standardized Measure of Discounted Future Net Cash Flows

December 31, 2017  2016 
Future cash flows $1,452,588,325  $1,019,179,570 
Future production costs  (476,753,026)  (318,378,291)
Future development costs  (132,347,551)  (140,511,904)
Future income taxes  (131,646,889)  (150,765,686)
Future net cash flows  711,840,859   409,523,689 
10% annual discount for estimated timing of cash flows  (389,375,740)  (249,728,651)
         
Standardized Measure of Discounted Cash Flows $322,465,119  $159,795,038 

December 31,202320222021
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 flows3,098,378,852 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

  2017  2016 
Beginning of the year $159,795,038  $172,686,441 
Purchase of minerals in place  179,441   - 
Extensions, discoveries and improved recovery, less related costs  77,967,484   42,388,078 
Development costs incurred during the year  181,887,252   43,085,217 
Sales of oil and gas produced, net of production costs  (50,721,338)  (19,477,828)
Sales of minerals in place  (508,331)  - 
Accretion of discount  22,991,164   11,995,583 
Net changes in price and production costs  108,595,790   (59,100,870)
Net change in estimated future development costs  (60,604,384)  (13,064,453)
Revision of previous quantity estimates  (56,812,326)  1,619,437 
Revision of estimated timing of cash flows  (58,123,153)  (30,342,680)
Net change in income taxes  (2,181,518)  10,006,113 
         
End of the Year $322,465,119  $159,795,038 

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202320222021
Beginning of the year$2,272,113,518 $1,137,364,848 $555,871,253 
Purchase of minerals in place141,738,066 996,313,882 33,688,718 
Extensions, discoveries and improved recovery57,607,609 20,447,842 79,003,885 
Development costs incurred during the year70,697,664 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 discount277,365,650 133,209,763 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 costs37,865,811 (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 taxes253,696,749 (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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