RING ENERGY, INC. - Quarter Report: 2023 June (Form 10-Q)

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United States

Securities and Exchange Commission

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended June 30, 2023

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

For the transition period from ______ to ______

Commission file number 001-36057

Ring Energy, Inc.

(Exact name of registrant as specified in its charter)


Nevada			90-0406406
(State or other jurisdiction of incorporation or organization)			(I.R.S. Employer Identification No.)

1725 Hughes Landing Blvd., Suite 900 The Woodlands, TX			77380
(Address of principal executive offices)			(Zip Code)

(281) 397-3699
(Registrant’s telephone number, including area code)

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


Title of Each Class	Trading Symbol	Name of Each Exchange on Which Registered
Common Stock, par value $0.001	REI	NYSE American

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No o

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

Large accelerated filer

Accelerated filer

Non-accelerated filer

(Do not check if a smaller reporting company)

Smaller reporting company

Emerging growth company

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 is shell company (as defined in Rule 12b-2 of the Act). Yes o No x

As of August 3, 2023, the registrant had outstanding 195,356,773 shares of common stock ($0.001 par value).

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TABLE OF CONTENTS


PART I — FINANCIAL INFORMATION
	Item 1:	Financial Statements	6
	Item 2:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
	Item 3:	Quantitative and Qualitative Disclosures About Market Risk	42
	Item 4:	Controls and Procedures	43
PART II — OTHER INFORMATION
	Item 1:	Legal Proceedings	44
	Item 1A:	Risk Factors	44
	Item 2:	Unregistered Sales of Equity Securities and Use of Proceeds	44
	Item 3:	Defaults Upon Senior Securities	44
	Item 4:	Mine Safety Disclosures	44
	Item 5:	Other Information	44
	Item 6:	Exhibits	45
SIGNATURES			46

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Forward Looking Statements

This Quarterly Report on Form 10-Q (herein, “Quarterly 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 Quarterly Report regarding our strategy, future operations, financial position, estimated revenues and expenses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report, the words “may,” “will,” “could,” “would,” “should,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “plan,” “pursue,” “target,” “continue,” “potential,” “guidance,” “project” or other similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. All forward-looking statements speak only as of the date of this Quarterly Report. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Quarterly Report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We are making investors aware that such forward-looking statements, because they relate to future events, are by their very nature subject to many important factors that could cause actual results to differ materially from those contemplated. Such factors include:

•declines or volatility in the prices we receive for our oil and natural gas;

•our ability to raise additional capital to fund future capital expenditures;

•our ability to generate sufficient cash flow from operations, 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;

•risks and liabilities associated with acquired companies and properties;

•risks related to integration of acquired companies and properties;

•potential defects in title to our properties;

•cost and availability of drilling rigs, equipment, supplies, personnel and oilfield services;

•geological concentration of our reserves;

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•the potential for production decline rates and associated production costs for our wells to be greater than we forecast;

•the timing and extent of our success in acquiring, discovering, developing and producing oil and natural gas reserves;

•the possibility that acquisitions and divestitures may involve unexpected costs or delays, and that acquisitions may not achieve intended benefits;

•the possibility that potential divestitures may not occur or could be burdened with unforeseen costs;

•unanticipated reductions in the borrowing base under the credit agreement we are party to;

•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 firm transportation for oil and natural gas we produce and to sell the oil and natural gas at market prices;

•future environmental, social and governance ("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 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;

•future cyber risk compliance developments and its effect on the loss of confidentiality, integrity, or availability of information, data, or information (or control) systems that reflect the potential adverse impacts to organizational operations and assets, individuals, or other organizations;

•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;

•actions or inaction of third-party operators of our properties;

•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;

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•impacts of world health events, including the coronavirus (“COVID-19”), and any reactive or proactive measures taken by businesses, governments and by other organizations related thereto, and the direct and indirect effects of world health events on the market for and price of oil and natural gas;

•our insurance coverage may not adequately cover all losses that may be sustained in connection with our business activities;

•possible adverse results from litigation and the use of financial resources to defend ourselves; and

•the other factors discussed in Part I, Item 1A-- “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2022, as well as in our financial statements, related notes, and the other financial information appearing elsewhere in this Quarterly Report and our other reports filed from time to time with the Securities and Exchange Commission (the “SEC”).

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date that such statements are made. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

Unless the context otherwise requires, references in this Quarterly Report to “Ring,” “Ring Energy,” the “Company,” “we,” “us,” “our” or “ours” refer to Ring Energy, Inc.

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PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

The following (a) condensed balance sheet as of December 31, 2022 which has been derived from our audited financial statements, and (b) the unaudited condensed financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission ("SEC"). Accordingly, certain disclosures by accounting principles generally accepted in the United States ("GAAP") and normally included in Annual Reports on Form 10-K have been omitted. Although management believes that our disclosures are adequate to make the information presented not misleading, these unaudited interim financial statements should be read in conjunction with the Company's audited financial statements and related notes included in its most recent Annual Report on Form 10-K.

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RING ENERGY, INC.

CONDENSED BALANCE SHEETS

(Unaudited)


	June 30, 2023		December 31, 2022
ASSETS
Current Assets
Cash and cash equivalents	$	1,749,975	$	3,712,526
Accounts receivable	32,044,159		42,448,719
Joint interest billing receivables, net	2,617,815		983,802
Derivative assets	8,307,537		4,669,162
Inventory	7,327,295		9,250,717
Prepaid expenses and other assets	3,061,216		2,101,538
Total Current Assets	55,107,997		63,166,464
Properties and Equipment
Oil and natural gas properties, full cost method	1,524,510,887		1,463,838,595
Financing lease asset subject to depreciation	3,144,038		3,019,476
Fixed assets subject to depreciation	2,762,370		3,147,125
Total Properties and Equipment	1,530,417,295		1,470,005,196
Accumulated depreciation, depletion and amortization	(331,153,213)		(289,935,259)
Net Properties and Equipment	1,199,264,082		1,180,069,937
Operating lease asset	1,628,832		1,735,013
Derivative assets	10,555,937		6,129,410
Deferred financing costs	15,458,204		17,898,973
Total Assets	$	1,282,015,052	$	1,268,999,797

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	90,021,106	$	111,398,268
Income tax liability	98,481		—
Financing lease liability	761,110		709,653
Operating lease liability	394,404		398,362
Derivative liabilities	7,848,580		13,345,619
Notes payable	1,412,674		499,880
Deferred cash payment	—		14,807,276
Asset retirement obligations	408,958		635,843
Total Current Liabilities	100,945,313		141,794,901

Non-current Liabilities
Deferred income taxes	4,074,183		8,499,016
Revolving line of credit	397,000,000		415,000,000
Financing lease liability, less current portion	765,753		1,052,479
Operating lease liability, less current portion	1,263,936		1,473,897
Derivative liabilities	10,829,096		10,485,650
Asset retirement obligations	28,296,455		29,590,463
Total Liabilities	543,174,736		607,896,406
Commitments and contingencies
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; 195,350,672 shares and 175,530,212 shares issued and outstanding, respectively	195,350		175,530
Additional paid-in capital	791,450,835		775,241,114
Accumulated deficit	(52,805,869)		(114,313,253)
Total Stockholders’ Equity	738,840,316		661,103,391
Total Liabilities and Stockholders' Equity	$	1,282,015,052	$	1,268,999,797

The accompanying notes are an integral part of these unaudited condensed financial statements.

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RING ENERGY, INC.

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)


	For the Three Months Ended				For the Six Months Ended
	June 30, 2023		June 30, 2022		June 30, 2023		June 30, 2022

Oil, Natural Gas, and Natural Gas Liquids Revenues	$	79,348,573	$	84,961,875	$	167,431,485	$	153,142,907

Costs and Operating Expenses
Lease operating expenses	15,938,106		8,301,443		33,410,797		17,254,608
Gathering, transportation and processing costs	(1,632)		549,389		(2,455)		1,846,247
Ad valorem taxes	1,670,343		949,239		3,340,956		1,901,193
Oil and natural gas production taxes	4,012,139		4,157,457		8,420,279		7,375,819
Depreciation, depletion and amortization	20,792,932		10,749,204		42,064,603		20,530,491
Asset retirement obligation accretion	353,878		186,303		719,725		374,545
Operating lease expense	115,353		83,590		228,491		167,180
General and administrative expense	6,810,243		5,832,302		13,940,382		11,354,579

Total Costs and Operating Expenses	49,691,362		30,808,927		102,122,778		60,804,662

Income from Operations	29,657,211		54,152,948		65,308,707		92,338,245

Other Income (Expense)
Interest income	79,745		—		79,745		—
Interest (expense)	(10,550,807)		(3,279,299)		(20,941,086)		(6,677,660)
Gain (loss) on derivative contracts	3,264,660		(7,457,018)		12,739,565		(35,053,159)
Gain (loss) on disposal of assets	(132,109)		—		(132,109)		—
Other income	116,610		—		126,210		—
Net Other Income (Expense)	(7,221,901)		(10,736,317)		(8,127,675)		(41,730,819)

Income Before Benefit from (Provision for) Income Taxes	22,435,310		43,416,631		57,181,032		50,607,426

Benefit from (Provision for) Income Taxes	6,356,295		(1,472,209)		4,326,352		(1,550,961)
Net Income	$	28,791,605	$	41,944,422	$	61,507,384	$	49,056,465

Basic Earnings per Share	$	0.15	$	0.39	$	0.33	$	0.47
Diluted Earnings per Share	$	0.15	$	0.32	$	0.32	$	0.39

The accompanying notes are an integral part of these unaudited condensed financial statements.

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RING ENERGY, INC.

CONDENSED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Unaudited)


	Common Stock			Additional Paid-in Capital		Retained Earnings (Accumulated Deficit)		Total Stockholders' Equity
For the Six Months Ended June 30, 2023	Shares	Amount
Balance, December 31, 2022	175,530,212	$	175,530	$	775,241,114	$	(114,313,253)	$	661,103,391
Exercise of common warrants issued in offering	4,517,427	4,517		3,609,424		—		3,613,941


Restricted stock vested	659,479	659		(659)		—		—
Shares to cover tax withholdings for restricted stock vested	(79,634)	(79)		79		—		—
Payments to cover tax withholdings for restricted stock vested, net	—	—		(134,381)		—		(134,381)


Share-based compensation	—	—		1,943,696		—		1,943,696
Net income	—	—		—		32,715,779		32,715,779
Balance, March 31, 2023	180,627,484	$	180,627	$	780,659,273	$	(81,597,474)	$	699,242,426
Induced exercise of common warrants issued in offering	14,512,166	14,512		8,673,143		—		8,687,655


Restricted stock vested	288,709	289		(289)		—		—
Shares to cover tax withholdings for restricted stock vested	(77,687)	(78)		78		—		—
Payments to cover tax withholdings for restricted stock vested, net	—	—		(141,682)		—		(141,682)


Share-based compensation	—	—		2,260,312		—		2,260,312
Net income	—	—		—		28,791,605		28,791,605
Balance, June 30, 2023	195,350,672	$	195,350	$	791,450,835	$	(52,805,869)	$	738,840,316












For the Six Months Ended June 30, 2022
Balance, December 31, 2021	100,192,562	$	100,193	$	553,472,292	$	(252,948,278)	$	300,624,207
Share-based compensation	—	—		1,521,910		—		1,521,910
Net income	—	—		—		7,112,043		7,112,043
Balance, March 31, 2022	100,192,562	$	100,193	$	554,994,202	$	(245,836,235)	$	309,258,160
Exercise of common warrants issued in offering	6,453,907	6,454		5,156,672		—		5,163,126
Options exercised	100,000	100		(100)		—		—
Shares elected to be withheld for options exercised	(47,506)	(48)		48		—		—
Restricted stock vested	610,195	610		(610)		—		—
Shares to cover tax withholdings for restricted stock vested	(73,047)	(73)		73		—		—
Payments to cover tax withholdings for restricted stock vested	—	—		(257,694)		—		(257,694)
Share-based compensation	—	—		1,899,245		—		1,899,245
Net income	—	—		—		41,944,422		41,944,422
Balance, June 30, 2022	107,236,111	$	107,236	$	561,791,836	$	(203,891,813)	$	358,007,259

The accompanying notes are an integral part of these unaudited condensed financial statements.

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RING ENERGY, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)


	For the Six Months Ended
	June 30, 2023		June 30, 2022
Cash Flows From Operating Activities
Net income	$	61,507,384	$	49,056,465
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	42,064,603		20,530,490
Asset retirement obligation accretion	719,725		374,545
Amortization of deferred financing costs	2,440,769		388,548
Share-based compensation	4,204,008		3,421,155
Bad debt expense	22,209		—
Deferred income tax expense (benefit)	(4,575,710)		1,550,961
Excess tax expense (benefit) related to share-based compensation	150,877		—
(Gain) loss on derivative contracts	(12,739,565)		35,053,159
Cash received (paid) for derivative settlements, net	(478,930)		(33,732,766)
Changes in operating assets and liabilities:
Accounts receivable	8,748,338		(14,393,828)
Inventory	1,923,422		—
Prepaid expenses and other assets	(959,678)		(2,267,717)
Accounts payable	(15,061,289)		6,847,979
Settlement of asset retirement obligation	(919,886)		(1,666,576)
Net Cash Provided by Operating Activities	87,046,277		65,162,415
Cash Flows From Investing Activities
Payments for the Stronghold Acquisition	(18,511,170)		—
Payments to purchase oil and natural gas properties	(878,743)		(743,851)
Payments to develop oil and natural gas properties	(72,551,222)		(49,654,172)
Payments to acquire or improve fixed assets subject to depreciation	(25,894)		(91,760)
Sale of fixed assets subject to depreciation	332,230		134,600
Proceeds from divestiture of equipment for oil and natural gas properties	54,558		25,066
Receipt from sale of Delaware properties	7,992,917		—
Net Cash (Used in) Investing Activities	(83,587,324)		(50,330,117)
Cash Flows From Financing Activities
Proceeds from revolving line of credit	84,500,000		50,500,000
Payments on revolving line of credit	(102,500,000)		(70,500,000)
Proceeds from issuance of common stock from warrant exercises	12,301,596		5,163,126

Payments for taxes withheld on vested restricted shares, net	(276,063)		(257,694)
Proceeds from notes payable	1,565,071		928,626
Payments on notes payable	(652,277)		(620,741)

Reduction of financing lease liabilities	(359,831)		(230,642)
Net Cash Provided by (Used in) Financing Activities	(5,421,504)		(15,017,325)
Net Increase (Decrease) in Cash	(1,962,551)		(185,027)
Cash at Beginning of Period	3,712,526		2,408,316
Cash at End of Period	$	1,749,975	$	2,223,289

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RING ENERGY, INC.

STATEMENTS OF CASH FLOWS (CONTINUED)


	For the Six Months Ended

	June 30, 2023		June 30, 2022
Supplemental Cash Flow Information
Cash paid for interest	$	18,622,944	$	6,228,393

Noncash Investing and Financing Activities
Asset retirement obligation incurred during development	$	173,516	$	122,206


Asset retirement obligation sold	(2,262,478)		—
Operating lease assets obtained in exchange for new operating lease liability	1,148,400		—

Financing lease assets obtained in exchange for new financing lease liability	142,719		—

Capitalized expenditures attributable to drilling projects financed through current liabilities	(2,621,236)		11,181,178

Supplemental Schedule for Stronghold Acquisition
Investing Activities - Cash Paid






Payment of deferred cash payment	$	15,000,000	$	—
Payment of post-close settlement	$	3,511,170	$	—
Payments for the Stronghold Acquisition	$	18,511,170	$	—

The accompanying notes are an integral part of these unaudited condensed financial statements.

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RING ENERGY, INC.

NOTES TO CONDENSED FINANCIAL STATEMENTS

(UNAUDITED)

Index to the Notes to the Condensed Financial Statements


Note 1 — Basis of Presentation & Significant Accounting Policies			Note 8 — Revolving Line of Credit
Note 2 — Revenue Recognition			Note 9 — Asset Retirement Obligation
Note 3 — Leases			Note 10 — Stockholders' Equity
Note 4 — Earnings Per Share Information			Note 11 — Employee Stock Options and Restricted Stock Units
Note 5 — Acquisitions & Divestitures			Note 12 — Commitments & Contingencies
Note 6 — Derivative Financial Instruments			Note 13 — Subsequent Events
Note 7 — Fair Value Measurements

NOTE 1 — BASIS OF PRESENTATION & SIGNIFICANT ACCOUNTING POLICIES

Condensed Financial Statements – The accompanying condensed financial statements prepared by Ring Energy, Inc., a Nevada corporation (the “Company,” "Ring Energy" or “Ring”), have not been audited by an independent registered public accounting firm. In the opinion of the Company’s management, the accompanying unaudited financial statements contain all adjustments necessary for fair presentation of the results of operations for the periods presented, which adjustments were of a normal recurring nature, except as disclosed herein. The condensed results of operations for the three and six months ended June 30, 2023, are not necessarily indicative of the results to be expected for the full year ending December 31, 2023, for various reasons, including the impact of fluctuations in prices received for oil and natural gas, natural production declines, the uncertainty of exploration and development drilling results, fluctuations in the fair value of derivative instruments, and other factors.

These unaudited condensed financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) applicable to interim financial information, and, accordingly, do not include all of the information and notes required by GAAP for complete financial statements. Therefore, these financial statements should be read in conjunction with the financial statements and notes included in the Company’s annual report on Form 10-K for the year ended December 31, 2022.

Organization and Nature of Operations – Ring Energy is a growth oriented independent exploration and production company based in The Woodlands, Texas engaged in oil and natural gas development, production, acquisition, and exploration activities currently focused in Texas. Our primary drilling operations target the oil and liquids rich producing formations in the Northwest Shelf and the Central Basin Platform, both of which are part of the Permian Basin.

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 cash flow from operations, 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 its cash flows from such price declines; however, if oil or natural gas prices rapidly deteriorate due to unanticipated economic conditions, this could have a material adverse effect on the Company’s cash flows.

The Company expects ongoing oil price volatility over the short 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 on hand and cash flows from operations.

Use of Estimates – The preparation of financial statements in conformity with 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 unaudited condensed 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

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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 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 the revolving line of credit approximate their fair value because the underlying instruments are at interest rates which approximate current market rates. The carrying amounts of accounts 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.

Fair Value of Non-financial Assets and Liabilities – The Company also applies fair value accounting guidance to initially, or as events dictate, measure non-financial assets and liabilities such as those obtained through business acquisitions, property and equipment and asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two as considered appropriate based on the circumstances. Under the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and natural gas production or other applicable sales estimates, operational costs and a risk-adjusted discount rate. The Company may use the present value of estimated future cash inflows and/or outflows or third-party offers or prices of comparable assets with consideration of current market conditions to value its non-financial assets and liabilities when circumstances dictate determining fair value is necessary. Given the significance of the unobservable nature of a number of the inputs, these are considered Level 3 on the fair value hierarchy.

Derivative Instruments and Hedging Activities – The Company periodically enters into derivative contracts to manage its exposure to commodity price risk. These derivative contracts, which are generally placed with major financial institutions, may take the form of forward contracts, futures contracts, swaps or options. The oil and gas reference prices upon which the commodity derivative contracts are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company for its oil and 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 Condensed 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. See "NOTE 6 — DERIVATIVE FINANCIAL INSTRUMENTS" for additional information.

Concentration of Credit Risk and Receivables – Financial instruments that potentially subject the Company to a concentration of credit risk consist principally of cash and receivables.

Cash and cash equivalents - The Company had cash in excess of federally insured limits of $1,499,975 and $3,462,526 as of June 30, 2023 and December 31, 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. The Company has not had any significant credit losses in the past and believes its accounts receivable are fully collectable. During the six months ended June 30, 2023, sales to three customers represented 68%, 13% and 11%, respectively, of total oil, natural gas, and natural gas liquids sales. As of June 30, 2023, receivables outstanding from these three customers represented 71%, 13% and 11%, respectively, of accounts receivable.

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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 June 30, 2023 or December 31, 2022.

Joint interest billing receivables, net - The Company also has joint interest billing receivables. Joint interest billing receivables are collateralized by the pro rata revenue attributable to the joint interest holders and further by the interest itself. Accounts receivable from joint interest owners or purchasers 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 three and six months ended June 30, 2023 and June 30, 2022.


	For the Three Months Ended				For the Six Months Ended
	June 30, 2023		June 30, 2022		June 30, 2023		June 30, 2022
Bad debt expense	$	19,315	$	—	$	22,209	$	—

The following table reflects the Company's joint interest billing receivables and allowance for credit losses as of June 30, 2023 and December 31, 2022.


	June 30, 2023		December 31, 2022
Joint interest billing receivables	$	2,776,650	$	1,226,049
Allowance for credit losses	(158,835)		(242,247)
Joint interest billing receivables, net	$	2,617,815	$	983,802

The relief of $83,412 in the allowance for credit losses during the six months ended June 30, 2023 was primarily due a clearing of $105,620 in allowances that were associated with the Delaware Basin asset sale, offset by new allowances booked (see NOTE 5 — ACQUISITIONS & DIVESTITURES for more detail).

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 June 30, 2023 and December 31, 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 market value. Inventory balances are excluded from the Company's calculation of depletion.

Oil and Natural Gas Properties – The Company uses the full cost method of accounting for oil and natural gas properties. Under this method, all costs (direct and indirect) associated with acquisition, exploration, and development of oil and natural gas properties are capitalized. Costs capitalized include acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties and costs of drilling and equipping productive and non-productive wells. Drilling costs include directly related overhead costs. Capitalized costs are categorized either as being subject to amortization or not subject to amortization. All of the Company’s capitalized costs, excluding inventory, are subject to amortization.

The Company records a liability in the period in which an asset retirement obligation (“ARO”) is incurred, in an amount equal to the discounted estimated fair value of the obligation that is capitalized. Thereafter this liability is accreted up to the final retirement cost. An ARO is a future expenditure related to the disposal or other retirement of certain assets. The Company’s ARO relates to future plugging and abandonment expenses of its oil and natural gas properties and related facilities disposal. Dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs.

All capitalized costs of oil and natural gas properties, including the estimated future costs to develop proved reserves and estimated future costs to plug and abandon wells and costs of site restoration, less the estimated salvage value of equipment associated with the oil and natural gas properties, are amortized on the unit-of-production method using estimates of proved reserves as determined by independent petroleum engineers. If the results of an assessment indicate that the properties are

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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 three and six months ended June 30, 2023 and 2022.


	For the Three Months Ended				For the Six Months Ended
	June 30, 2023		June 30, 2022		June 30, 2023		June 30, 2022
Depletion	$	20,511,809	$	10,629,787	$	41,492,351	$	20,254,404
Depletion rate, per barrel-of-oil-equivalent (Boe)	$	13.05	$	12.51	$	12.89	$	12.28

In addition, capitalized costs less accumulated depreciation, depletion and amortization and related deferred income taxes are not allowed to exceed an amount (the full cost ceiling) equal to the sum of:

1)the present value of estimated future net revenues discounted at ten percent computed in compliance with SEC guidelines;

2)plus the cost of properties not being amortized;

3)plus the lower of cost or estimated fair value of unproven properties included in the costs being amortized;

4)less income tax effects related to differences between the book and tax basis of the properties.

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


Leasehold improvements						3‑5 years
Office equipment and software						3‑7 years
Equipment						5‑10 years
Automobiles						4 years

The following table provides information on the Company's depreciation expense for the three and six months ended June 30, 2023 and 2022.


	For the Three Months Ended				For the Six Months Ended
	June 30, 2023		June 30, 2022		June 30, 2023		June 30, 2022
Depreciation	$	91,628	$	8,567	$	196,729	$	48,622

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. The annual percentage rate (APR) for this note is 7.08%. As of June 30, 2023, the notes payable balance included in current liabilities on the Condensed Balance Sheet is $1,412,674. The following table shows interest paid related to these notes payable for the three and six months ended June 30, 2023 and 2022. This interest is included within "Interest (expense)" in the Condensed Statements of Operations.


	Three Months Ended				Six Months Ended
	June 30, 2023		June 30, 2022		June 30, 2023		June 30, 2022
Interest paid for notes payable	$	9,234	$	4,682	$	12,925	$	9,284

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Revenue Recognition – In January 2018, the Company adopted Accounting Standards Update (“ASU”) 2014-09 Revenues from Contracts with Customers (Topic 606) (“ASU 2014-09”). The timing of recognizing revenue from the sale of produced crude oil and natural gas was not changed as a result of adopting ASU 2014-09. The Company predominantly derives its revenue from the sale of produced crude oil and natural gas. The contractual performance obligation is satisfied when the product is delivered to the purchaser. Revenue is recorded in the month the product is delivered to the purchaser. The Company receives payment from one to three months after delivery. The transaction price includes variable consideration as product pricing is based on published market prices and reduced for contract specified differentials. The new guidance regarding ASU 2014-09 does not require that the transaction price be fixed or stated in the contract. Estimating the variable consideration does not require significant judgment and Ring engages third party sources to validate the estimates. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration the Company expects to receive in exchange for those products. See "NOTE 2 — REVENUE RECOGNITION" for additional information.

Income Taxes – Provisions for income taxes are based on taxes payable or refundable for the current year and deferred taxes. Deferred taxes are provided on differences between the tax basis of assets and liabilities and their reported amounts in the financial statements, and tax carryforwards. Deferred tax assets and liabilities are included in the financial statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the provision for income taxes.

Since December 31, 2020, the Company has determined that a full valuation allowance is necessary due to the Company's assessment that it is more likely than not that it will 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 will not be offset by existing deferred tax liabilities as a result of the 80% limitation on the utilization net operating losses incurred after 2017. Since 2021, commodity prices had increased and the Company continues to project positive pre-tax book income. As of June 30, 2023, the Company is 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 judgement on the realizability of the related federal deferred tax assets in future years, the Company released $7.7 million of valuation allowance as a discrete benefit in the first six months ended June 30, 2023. Accordingly, the Company recorded the following federal and state income tax benefits (provisions) for the three and six months ended June 30, 2023 and 2022.


	For the Three Months Ended				For the Six Months Ended
	June 30, 2023		June 30, 2022		June 30, 2023		June 30, 2022
Deferred federal income tax benefit (provision)	$	6,640,741	$	(1,014,048)	$	5,111,491	$	(1,014,048)
Current state income tax benefit (provision)	(41,191)		12,813		(98,481)		—
Deferred state income tax benefit (provision)	(243,255)		(470,974)		(686,658)		(536,913)
Benefit from (Provision for) Income Taxes	$	6,356,295	$	(1,472,209)	$	4,326,352	$	(1,550,961)

The Company has immaterial operations in New Mexico which is in a net deferred tax asset position for which a full valuation allowance is still recorded.

For the three and six months ended June 30, 2023, the Company’s overall effective tax rates (calculated as Benefit from (Provision for) Income Taxes divided by Income Before Benefit from (Provision for) Income Taxes) were 28.33% and 7.57%, respectively. These rates were primarily impacted by the release of valuation allowance on its federal net deferred tax asset. A tax benefit of $7.7 million was recorded as a discrete item in the three months ended June 30, 2023.

Accounting for Uncertainty in Income Taxes – In accordance with GAAP, the Company has analyzed its filing positions in all jurisdictions where it is required to file income tax returns for the open tax years. The Company has identified its federal income tax return and its franchise tax return in Texas in which it operates as “major” tax jurisdictions. The Company’s federal income tax returns for the years ended December 31, 2018 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 2017 and after. The Company currently believes that all significant filing positions are highly certain and that all of its significant income tax filing positions and deductions would be sustained upon audit. Therefore, the Company has no significant reserves for uncertain tax positions and no adjustments to such reserves were required by GAAP. No

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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 Condensed Statements of Operations.

Three-Stream Reporting - Beginning July 1, 2022, the Company began reporting volumes and revenues on a three-stream basis, separately reporting crude oil, natural gas, and natural gas liquids ("NGLs") 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 AND 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.

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 applicable period. Diluted earnings (loss) per share are calculated to give effect to potentially issuable dilutive common shares.

Share-Based Employee Compensation – The Company has outstanding stock option grants and restricted stock unit awards to directors, officers and employees, which are described more fully in "NOTE 11 — EMPLOYEE STOCK OPTIONS AND RESTRICTED STOCK UNITS". The Company recognizes the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award and recognizes the related compensation expense over the period during which an employee is required to provide service in exchange for the award, which is generally the vesting period.

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.

The following table summarizes the Company's share-based compensation, included with General and administrative expense within our Condensed Statements of Operations, incurred for the three and six months ended June 30, 2023 and 2022.


	Three Months Ended				Six Months Ended
	June 30, 2023		June 30, 2022		Jun. 30, 2023		Jun. 30, 2022
Share-based compensation	$	2,260,312	$	1,899,245	$	4,204,008	$	3,421,155

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 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 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,

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the Company's interest rates were transitioned from the LIBOR to the SOFR (Standard Overnight Financing Rate) reference rate. At this time, the Company does not plan to enter into additional contracts using LIBOR as a reference rate.

In October 2021, the FASB issued ASU 2021-08, "Business Combinations (Topic 805) – Accounting for Contract Assets and Contract Liabilities from Contracts with Customers” ("ASU 2021-08"). This update requires the acquirer in a business combination to record contract asset and liabilities following Topic 606 – “Revenue from Contracts with Customers” at acquisition as if it had originated the contract, rather than at fair value. This update is effective for public business entities beginning after December 15, 2022, with early adoption permitted. The Company continues to evaluate the provisions of this update, but it does not believe the adoption will have a material impact on its financial position, results of operations or liquidity.

NOTE 2 — REVENUE RECOGNITION

The Company predominantly derives its revenue from the sale of produced crude oil, natural gas, NGLs. The contractual performance obligation is satisfied when the product is delivered to the purchaser. Revenue is recorded in the month the product is delivered to the purchaser. The Company receives payment from one to three months after delivery. The 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 customer represents a separate performance obligation, therefore, future volumes to be delivered are wholly unsatisfied and disclosure of transaction price allocated to remaining performance obligation is not required. The transaction price includes variable consideration, as product pricing is based on published market prices and adjusted for contract specified differentials such as quality, energy content and transportation. The guidance does not require that the transaction price be fixed or stated in the contract. Estimating the variable consideration does not require significant judgment and the Company engages third party sources to validate the estimates. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration the Company expects to receive in exchange for those products.

Oil sales

Under the Company’s oil sales contracts, the Company sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue at the net price received when control transfers to the purchaser at the point of delivery and it is probable the Company will collect the consideration it is entitled to receive.

Natural gas and NGL sales

Under the Company’s natural gas sales processing contracts for its Central Basin Platform properties and a portion of its Northwest Shelf assets, the Company delivers unprocessed natural gas to a midstream processing entity at the wellhead. The midstream processing entity obtains control of the natural gas and NGLs at the wellhead. The midstream processing entity gathers and processes the natural gas and NGLs and remits proceeds to the Company for the resulting sale of natural gas and NGLs. Under these processing agreements, the Company recognizes revenue when control transfers to the purchaser at the point of delivery and it is probable the Company will collect the consideration it is entitled to receive. As such, the Company accounts for any fees and deductions as a reduction of the transaction price.

Until April 30, 2022, under the Company's natural gas sales processing contracts for the bulk of its Northwest Shelf assets, the Company delivered unprocessed natural gas to a midstream processing entity at the wellhead. However, the Company maintained ownership of the gas through processing and received proceeds from the marketing of the resulting products. Under this processing agreement, the Company recognized the fees associated with the processing as an expense rather than netting these costs against Oil, Natural Gas, and Natural Gas Liquids Revenues in the Condensed Statements of Operations. Beginning May 1, 2022, these contracts were combined into one contract, and it was modified so that the Company no longer maintained ownership of the gas through processing. Accordingly, the Company from that point on accounts for any such fees and deductions as a reduction of the transaction price.

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Disaggregation of Revenue. The following table presents revenues disaggregated by product:


	For the Three Months Ended				For the Six Months Ended
	June 30, 2023		June 30, 2022		June 30, 2023		June 30, 2022
Oil, Natural Gas, and Natural Gas Liquids Revenues
Oil	$	78,042,072	$	79,688,536	$	161,628,399	$	143,119,163
Natural gas	(1,100,776)		5,273,339		(36,213)		10,023,744
Natural gas liquids (1)	2,407,277		—		5,839,299		—
Total oil, natural gas, and natural gas liquids revenues	$	79,348,573	$	84,961,875	$	167,431,485	$	153,142,907

(1) Beginning on July 1, 2022, the Company began reporting volumes and revenues on a three-stream basis, separately reporting crude oil, natural gas, and NGL sales. For periods prior to July 1, 2022, sales revenues for NGLs were presented with natural gas.

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. The additional office space that was added is under construction and until completed, the rental obligation for this space has not commenced. In other words, the Company does not have control of the additional office space in accordance with ASC 842-40-55-5. The future payments associated with these operating leases as to the current obligations are reflected below.

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. not capitalize). The office equipment and compressors are not subject to ASU 2016-02 based on the agreement and nature of use. These leases are for terms that are less than 12 months and the Company does not intend to continue to lease this equipment for more than 12 months. The lease costs associated with these leases is reflected in the short-term lease costs within Lease operating expenses, shown below.

The Company has financing leases for vehicles. These leases have a term of 36 months at the end of which the Company owns the vehicles. These vehicles are generally sold at the end of their term and the proceeds applied to a new vehicle.

Future lease payments associated with these operating and financing leases as of June 30, 2023 are as follows:


	2023		2024		2025		2026		2027		Other Future Years
Operating lease payments (1)	$	220,193	$	482,328	$	494,692	$	398,096	$	216,000	—
Financing lease payments (2)	416,687		771,643		432,695		11,136		—		—

(1)The weighted average discount rate as of June 30, 2023 for operating leases was 4.50%. Based on this rate, the future lease payments above include imputed interest of $152,969. The weighted average remaining term of operating leases was 3.81 years.

(2)The weighted average discount rate as of June 30, 2023 for financing leases was 6.05%. Based on this rate, the future lease payments above include imputed interest of $105,298. The weighted average remaining term of financing leases was 2.02 years.

The following table represents a reconciliation between the undiscounted future cash flows in the table above and the operating and financing lease liabilities disclosed in the Condensed Balance Sheets:

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	As of
	June 30, 2023		December 31, 2022
Operating lease liability, current portion	$	394,404	$	398,362
Operating lease liability, non-current portion	1,263,936		1,473,897
Operating lease liability, total	$	1,658,340	$	1,872,259
Total undiscounted future cash flows (sum of future operating lease payments)	1,811,309		2,065,580
Imputed interest	152,969		193,321
Undiscounted future cash flows less imputed interest	$	1,658,340	$	1,872,259

Financing lease liability, current portion	$	761,110	$	709,653
Financing lease liability, non-current portion	765,753		1,052,479
Financing lease liability, total	$	1,526,863	$	1,762,132
Total undiscounted future cash flows (sum of future financing lease payments)	1,632,161		1,900,595
Imputed interest	105,298		138,463
Undiscounted future cash flows less imputed interest	$	1,526,863	$	1,762,132

The following table provides supplemental information regarding lease costs in our Condensed Statements of Operations:


	For the Three Months Ended				For the Six Months Ended
	June 30, 2023		June 30, 2022		June 30, 2023		June 30, 2022
Operating lease costs	$	115,353	$	83,590	$	228,491	$	167,180
Short-term lease costs (1)	1,815,836		581,799		3,029,635		1,297,602
Financing lease costs:
Amortization of financing lease assets (2)	189,495		110,850		375,523		227,465
Interest on financing lease liabilities (3)	24,268		7,280		49,699		13,793

(1)Amount included in Lease operating expenses

(2)Amount included in Depreciation, depletion and amortization

(3)Amount included in Interest (expense)

NOTE 4 — EARNINGS PER SHARE INFORMATION

The following table presents the calculation of the Company's basic and diluted earnings per share for the three and six months ended June 30, 2023 and 2022.


	For the Three Months Ended				For the Six Months Ended
	June 30, 2023		June 30, 2022		June 30, 2023		June 30, 2022
Net Income	$	28,791,605	$	41,944,422	$	61,507,384	$	49,056,465
Basic Weighted-Average Shares Outstanding	193,077,859		106,390,776		185,545,775		103,291,669
Effect of dilutive securities:
Stock options	—		114,985		—		115,069
Restricted stock units	1,096,128		2,614,251		1,192,039		2,274,467
Performance stock units	276,566		393,023		241,140		243,475
Common warrants	1,415,980		21,084,554		6,045,012		20,327,025
Diluted Weighted-Average Shares Outstanding	195,866,533		130,597,589		193,023,966		126,251,705
Basic Earnings per Share	$	0.15	$	0.39	$	0.33	$	0.47
Diluted Earnings per Share	$	0.15	$	0.32	$	0.32	$	0.39

The following table presents the securities which were excluded from the Company's computation of diluted earnings per share for the three and six months ended June 30, 2023 and 2022, as their effect would have been anti-dilutive.

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	For the Three Months Ended		For the Six Months Ended
	June 30, 2023	June 30, 2022	June 30, 2023	June 30, 2022
Antidilutive securities:
Stock options to purchase common stock	265,500	70,500	265,500	70,500
Unvested restricted stock units	1,803,513	6,681	71,985	6,269
Unvested performance stock units	1,592,268	—	1,296,912	767,537

NOTE 5 — ACQUISITIONS & DIVESTITURES

Delaware Basin Sale

On May 11, 2023, the Company completed the divestiture of its Delaware Basin assets to an unaffiliated party for preliminary cash consideration of approximately $8.0 million, subject to customary final purchase price adjustments. As part of the divestiture, the Company was relieved of an asset retirement obligation balance of approximately $2.3 million.

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.

NOTE 6 — DERIVATIVE FINANCIAL INSTRUMENTS

The Company is exposed to fluctuations in crude oil and natural gas prices on its production. It utilizes derivative strategies that consist of either a single derivative instrument or a combination of instruments to manage the variability in cash flows associated with the forecasted sale of our future domestic oil and natural gas production. While the use of derivative instruments may limit or partially reduce the downside risk of adverse commodity price movements, their use also may limit future income from favorable commodity price movements.

From time to time, the Company enters into derivative contracts to protect the Company’s cash flow from price fluctuation and maintain its capital programs. The Company has historically used costless collars, deferred premium puts, or swaps for this purpose. Oil derivative contracts are based on WTI (West Texas Intermediate) 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. On swap contracts, there is no spread and payments will be made or received based on the difference between WTI and the swap contract price. The deferred premium put contract has the premium established upon entering the contract, and due upon settlement of the contract.

The use of derivative transactions involves the risk that the counterparties, which generally are financial institutions, will be unable to meet the financial terms of such transactions. All of our derivative contracts are with lenders under our credit facility. Non-performance risk is incorporated in the discount rate by adding the quoted bank (counterparty) credit default swap (CDS) rates to the risk free rate. Although the counterparties hold the right to offset (i.e. netting) the settlement amounts with the Company, in accordance with ASC 815-10-50-4B, the Company classifies the fair value of all its derivative positions on a gross basis in its corresponding Condensed Balance Sheets.

The Company’s derivative financial instruments are recorded at fair value and included as either assets or liabilities in the accompanying Condensed Balance Sheets. The Company has not designated its derivative instruments as hedges for accounting purposes, and, as a result, any gains or losses resulting from changes in fair value of outstanding derivative financial instruments and from the settlement of derivative financial instruments are recognized in earnings and included as a component of "Other Income (Expense)" under the heading "Gain (loss) on derivative contracts" in the accompanying Condensed Statements of Operations.

The following presents the impact of the Company’s contracts on its Condensed Balance Sheets for the periods indicated.


	As of
	June 30, 2023		December 31, 2022
Commodity derivative instruments, marked to market:

Derivative assets, current	$	14,604,030	$	16,193,327
Discounted deferred premiums	(6,296,493)		(11,524,165)
Derivatives assets, current, net of premiums	$	8,307,537	$	4,669,162

Derivative assets, noncurrent	$	10,555,937	$	7,606,258
Discounted deferred premiums	—		(1,476,848)
Derivative assets, noncurrent, net of premiums	$	10,555,937	$	6,129,410

Derivative liabilities, current	$	7,848,580	$	13,345,619

Derivative liabilities, noncurrent	$	10,829,096	$	10,485,650

The components of “Gain (loss) on derivative contracts” from the Condensed Statements of Operations are as follows for the respective periods:


	For the Three Months Ended				For the Six Months Ended
	June 30, 2023		June 30, 2022		June 30, 2023		June 30, 2022
Oil derivatives:
Realized gain (loss) on oil derivatives	$	(833,841)	$	(19,617,265)	$	(1,497,603)	$	(33,732,766)
Unrealized gain (loss) on oil derivatives	4,545,136		12,160,247		12,652,157		(1,320,393)
Gain (loss) on oil derivatives	$	3,711,295	$	(7,457,018)	$	11,154,554	$	(35,053,159)

Natural gas derivatives:
Realized gain (loss) on natural gas derivatives	1,013,436		—		1,018,673		—
Unrealized gain (loss) on natural gas derivatives	(1,460,071)		—		566,338		—
Gain (loss) on natural gas derivatives	$	(446,635)	$	—	$	1,585,011	$	—

Gain (loss) on derivative contracts	$	3,264,660	$	(7,457,018)	$	12,739,565	$	(35,053,159)

The components of “Cash paid for derivative settlements, net” within the Condensed Statements of Cash Flows are as follows for the respective periods:


	For the Three Months Ended				For the Six Months Ended
	June 30, 2023		June 30, 2022		June 30, 2023		June 30, 2022
Cash flows from operating activities
Cash received (paid) for oil derivatives	$	(833,841)	$	(19,617,265)	$	(1,497,603)	$	(33,732,766)
Cash received (paid) from natural gas derivatives	1,013,436		—		1,018,673		—
Cash received (paid) for derivative settlements, net	$	179,595	$	(19,617,265)	$	(478,930)	$	(33,732,766)

The following tables reflect the details of current derivative contracts as of June 30, 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)
	Q3 2023		Q4 2023		Q1 2024		Q2 2024		Q3 2024		Q4 2024		Q1 2025		Q2 2025		Q3 2025		Q4 2025

Swaps:
Hedged volume (Bbl)	181,700		138,000		170,625		156,975		282,900		368,000		—		—		—		—
Weighted average swap price	$	74.19	$	74.52	$	67.40	$	66.40	$	65.49	$	68.43	$	—	$	—	$	—	$	—

Deferred premium puts:
Hedged volume (Bbl)	230,000		165,600		45,500		45,500		—		—		—		—		—		—
Weighted average strike price	$	80.47	$	83.78	$	84.70	$	82.80	$	—	$	—	$	—	$	—	$	—	$	—
Weighted average deferred premium price	$	10.60	$	14.61	$	17.15	$	17.49	$	—	$	—	$	—	$	—	$	—	$	—

Two-way collars:
Hedged volume (Bbl)	211,163		274,285		339,603		325,847		230,000		128,800		474,750		464,100		—		—
Weighted average put price	$	55.56	$	56.73	$	64.20	$	64.30	$	64.00	$	60.00	$	57.06	$	60.00	$	—	$	—
Weighted average call price	$	69.25	$	70.77	$	79.73	$	79.09	$	76.50	$	73.24	$	75.82	$	69.85	$	—	$	—

Three-way collars:
Hedged volume (Bbl)	16,242		15,598		—		—		—		—		—		—		—		—
Weighted average first put price	$	45.00	$	45.00	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Weighted average second put price	$	55.00	$	55.00	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Weighted average call price	$	80.05	$	80.05	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—


	Gas Hedges (Henry Hub)
	Q3 2023		Q4 2023		Q1 2024		Q2 2024		Q3 2024		Q4 2024		Q1 2025		Q2 2025		Q3 2025		Q4 2025

NYMEX Swaps:
Hedged volume (MMBtu)	144,781		203,706		152,113		138,053		121,587		644,946		616,199		591,725		—		—
Weighted average swap price	$	3.36	$	3.35	$	3.62	$	3.61	$	3.59	$	4.45	$	3.78	$	3.43	$	—	$	—

Two-way collars:
Hedged volume (MMBtu)	404,421		579,998		591,500		568,750		552,000		—		—		—		—		—
Weighted average put price	$	3.17	$	3.15	$	4.00	$	4.00	$	4.00	$	—	$	—	$	—	$	—	$	—
Call hedged volume (MMBtu)	404,421		579,998		591,500		568,750		552,000		—		—		—		—		—
Weighted average call price	$	4.55	$	4.50	$	6.29	$	6.29	$	6.29	$	—	$	—	$	—	$	—	$	—


	Oil Hedges (basis differential)
	Q3 2023		Q4 2023		Q1 2024		Q2 2024		Q3 2024		Q4 2024		Q1 2025		Q2 2025		Q3 2025		Q4 2025

Argus basis swaps:
Hedged volume (MMBtu)	305,000		460,000		364,000		364,000		368,000		368,000		270,000		273,000		276,000		276,000
Weighted average spread price (1)	$	1.10	$	1.10	$	1.15	$	1.15	$	1.15	$	1.15	$	1.00	$	1.00	$	1.00	$	1.00


	Gas Hedges (basis differential)
	Q3 2023		Q4 2023		Q1 2024		Q2 2024		Q3 2024		Q4 2024		Q1 2025		Q2 2025		Q3 2025		Q4 2025

Waha basis swaps:
Hedged volume (MMBtu)	332,855		324,021		—		—		—		—		—		—		—		—
Weighted average spread price (1)	$	0.55	$	0.55	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—

El Paso Permian Basin basis swaps:
Hedged volume (MMBtu)	329,529		459,683		—		—		—		—		—		—		—		—
Weighted average spread price (1)	$	0.63	$	0.63	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—

(1) The oil basis swap hedges are calculated as the fixed price (weighted average spread price above) less the difference between WTI Midland and WTI Cushing, in the issue of Argus Americas Crude. The gas basis swap hedges are calculated as the Henry Hub natural gas price less the fixed amount specified as the weighted average spread price above.

NOTE 7 — FAIR VALUE MEASUREMENTS

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The authoritative guidance requires disclosure of the framework for measuring fair value and requires that fair value measurements be classified and disclosed in one of the following categories:


Level 1:			Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2:			Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that we value using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3:			Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity).

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy. We continue to evaluate our inputs to ensure the fair value level classification is appropriate. When transfers between levels occur, it is our policy to assume that the transfer occurred at the date of the event or change in circumstances that caused the transfer.

The fair values of the Company’s derivatives are not actively quoted in the open market. The Company uses a market approach to estimate the fair values of its derivative instruments on a recurring basis, utilizing commodity futures pricing for the underlying commodities provided by a reputable third party, a Level 2 fair value measurement.

The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments if events or changes in certain circumstances indicate that adjustments may be necessary.

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The following table summarizes the valuation of our assets and liabilities that are measured at fair value on a recurring basis (further detail in "NOTE 6 — 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 June 30, 2023

Commodity Derivatives - Assets	$	—	$	18,863,474	$	—	$	18,863,474
Commodity Derivatives - Liabilities	$	—	$	(18,677,676)	$	—	$	(18,677,676)

Total	$	—	$	185,798	$	—	$	185,798

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 8 — REVOLVING LINE OF CREDIT

On July 1, 2014, the Company entered into a Credit Agreement with SunTrust Bank (now Truist), as lender, issuing bank and administrative agent for several banks and other financial institutions and lenders (the “Administrative Agent”), (which was amended several times) that provided for a maximum borrowing base of $1 billion with security consisting of substantially all of the assets of the Company. In April 2019, the Company amended and restated the Credit Agreement with the Administrative Agent (as amended and restated, the “Credit Facility”).

On August 31, 2022, the Company modified its Credit Facility through a Second Amended and Restated Credit Agreement, extending the maturity date of the facility to August 2026. In conjunction with the Stronghold Acquisition, with the newly acquired assets put up for collateral, the Company established a borrowing base of $600 million. The borrowing base is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time. The borrowing base is redetermined semi-annually each May and November. The borrowing base is subject to reduction in certain circumstances such as the sale or disposition of certain oil and gas properties of the Company or its subsidiaries and cancellation of certain hedging positions.

The syndicate was modified to add five lenders, replacing five exiting lenders. Rather than Eurodollar loans, the reference rate on the Second Amended and Restated Credit Agreement is the Standard Overnight Financing Rate (“SOFR”). Beginning on the June 30, 2023 financial statements and compliance certification delivery date, the Second Amended and Restated Credit Agreement will allow for the Company to declare dividends for its equity owners, subject to certain limitations. These limitations include (i) no default or event of default has occurred or will occur upon such payments, (ii) the pro forma Leverage Ratio, as defined in the Second Amended and Restated Credit Agreement, does not exceed 2.00 to 1.00, (iii) the amount of such payments does not exceed Available Free Cash Flow, (iv) the Borrowing Base Utilization Percentage is not greater than 80%, and (v) a Responsible Officer certifies that the other four conditions are satisfied.

The interest rate on each SOFR Loan will be the adjusted term SOFR for the applicable interest period plus a margin between 3.0% and 4.0% (depending on the then-current level of borrowing base usage). The annual interest rate on each

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base rate Loan is (a) the greatest of (i) the Administrative Agent’s prime lending rate, (ii) the Federal Funds Rate (as defined in the Second Amended and Restated Credit Agreement) plus 0.5% per annum, (iii) the adjusted term SOFR determined on a daily basis for an interest period of one month, plus 1.00% per annum and (iv) 0.00% per annum, plus (b) a margin between 2.0% and 3.0% per annum (depending on the then-current level of borrowing base usage).

The Second Amended and Restated Credit Agreement contains certain covenants, which, among other things, require the maintenance of (i) a total Leverage Ratio (outstanding debt to adjusted earnings before interest, taxes, depreciation and amortization, exploration expenses, and all other non-cash charges acceptable to the Administrative Agent) of not more than 3.0 to 1.0 and (ii) a minimum ratio of Current Assets to Current Liabilities (as such terms are defined in the Second Amended and Restated Credit Agreement) of 1.0 to 1.0.

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. 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 shall be 0% from such hedge testing date to the next succeeding hedge testing date. 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 shall be 25% from such hedge testing date to the next succeeding hedge testing date.

The Second Amended and Restated Credit Agreement also contains other customary affirmative and negative covenants and events of default. As of June 30, 2023, $397 million was outstanding on the Credit Facility. The Company is in compliance with all covenants contained in the Second Amended and Restated Credit Agreement as of June 30, 2023.

Under the Second Amended and Restated Credit Agreement, the applicable percentage for the unused commitment fee is 0.5% per annum for all levels of borrowing base utilization. As of June 30, 2023, the Company's unused line of credit was $202.2 million, representative of a borrowing base of $600 million less the outstanding balance of $397 million, and standby letters of credit of $760,438 in total ($260,000 with state and federal agencies and $500,438 with an insurance company for New Mexico surety bonds).

NOTE 9 — ASSET RETIREMENT OBLIGATION

The Company records the obligation to plug and abandon oil and gas wells at the dates properties are either acquired or the wells are drilled. The asset retirement obligation is adjusted each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the costs or timing estimates. The asset retirement obligation is incurred using an annual credit-adjusted risk-free discount rate at the applicable dates. Changes in the asset retirement obligation during the six months ended June 30, 2023 were as follows:


Balance, December 31, 2022	$	30,226,306
Liabilities acquired	—
Liabilities incurred	173,516
Liabilities sold	(2,262,478)
Liabilities settled	(151,656)
Revision of estimate	—
Accretion expense	719,725
Balance, June 30, 2023	$	28,705,413

The following table presents the Company's current and non-current asset retirement obligation balances as of the periods specified.

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	June 30, 2023		December 31, 2022
Asset retirement obligations, current	408,958		635,843
Asset retirement obligations, non-current	28,296,455		29,590,463
Asset retirement obligations	$	28,705,413	$	30,226,306

NOTE 10 — STOCKHOLDERS' EQUITY

As of December 31, 2022, the Company had 19,107,793 exercisable common warrants, with a contractual exercise price of $0.80 per warrant, expiring five years from initial issuance in October 2020. During the six months ended June 30, 2023, a total of 19,029,593 common warrants were exercised. The following table reflects the common warrants exercised, including the proceeds received for such exercises. As of June 30, 2023 there remained 78,200 exercisable common warrants.


	Common Warrants	Exercise Price		Proceeds Received
Exercisable, December 31, 2021	29,361,700	$	0.80
Exercised	—	—		$	—
Exercisable, March 31, 2022	29,361,700	$	0.80
Exercised	(6,453,907)	0.80		$	5,163,126
Exercisable, June 30, 2022	22,907,793	$	0.80

Exercisable, December 31, 2022	19,107,793	$	0.80
Exercised	(4,517,427)	0.80		$	3,613,941
Exercisable, March 31, 2023	14,590,366	$	0.80
Exercised (1)	(14,512,166)	0.62		$	8,997,543
Exercisable, June 30, 2023	78,200	$	0.80

(1) On April 11 and 12, 2023, the Company and certain holders of the common warrants (the “Participating Holders”) entered into a form of Warrant Amendment and Exercise Agreement (the “Exercise Agreement”) pursuant to which the Company agreed to reduce the exercise price of an aggregate of 14,512,166 common warrants held by such Participating Holders from $0.80 to $0.62 per share (the “Reduced Exercise Price”) in consideration for the exercise of the common warrants held by such Participating Holders in full at the Reduced Exercise Price in cash. The Company received aggregate gross proceeds of $8,997,543 from the exercise of the common warrants by the Participating Holders pursuant to the Exercise Agreement, which was recognized as an equity issuance cost in accordance with ASC 815-40-35-17(a). In our Statements of Stockholders' Equity, the net impact to Stockholders' Equity is $8,687,655, which is net of $309,888 in advisory fees.

NOTE 11 — EMPLOYEE STOCK OPTIONS AND RESTRICTED STOCK UNITS

Compensation expense charged against income for share-based awards during the three and six months ended June 30, 2023 and 2022 was as follows. These amounts are included in General and administrative expense in the Condensed Statements of Operations.


	Three Months Ended				Six Months Ended
	June 30, 2023		June 30, 2022		Jun. 30, 2023		Jun. 30, 2022
Share-based compensation	$	2,260,312	$	1,899,245	$	4,204,008	$	3,421,155

In 2011, the Board approved and adopted a long-term incentive plan (the “2011 Plan”), which was subsequently approved and amended by the shareholders. There were 341,755 shares eligible for grant, either as stock options or as restricted stock, as of June 30, 2023.

In 2021, the Board approved and adopted the Ring Energy, Inc. 2021 Omnibus Incentive Plan (the “2021 Plan”), which was subsequently approved and amended by the shareholders at the 2021 Annual Meeting. At the 2023 Annual Meeting,

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the shareholders approved a Plan Amendment to increase the number of shares available under the 2021 Plan by 6.0 million. Accordingly, there were 8,219,397 shares eligible for grant, either as stock options or as restricted stock, as of June 30, 2023 under the 2021 Plan.

Stock Options

A summary of the status of the stock options as of June 30, 2023 and 2022 and changes during the six months then ended are as follows:


	Options	Weighted- Average Exercise Price		Weighted-Average Remaining Contractual Term	Aggregate Intrinsic Value
Outstanding, December 31, 2021	365,500	$	3.61
Granted	—	—
Forfeited or rescinded	—	—
Exercised	—	—
Outstanding, March 31, 2022	365,500	$	3.61	2.21 years	$	536,900

Granted	—	$	—
Forfeited or rescinded	—	$	—
Exercised	(100,000)	$	2.00
Outstanding, June 30, 2022	265,500	$	4.21	2.14 years	$	128,700
Exercisable, June 30, 2022	265,500	$	4.21	2.14 years

Outstanding, December 31, 2022	265,500	$	4.21
Granted	—	—
Forfeited or rescinded	—	—
Exercised	—	—
Outstanding, March 31, 2023	265,500	$	4.21	1.39 years	$	—

Granted	—	$	—
Forfeited or rescinded	—	$	—
Exercised	—	$	—
Outstanding, June 30, 2023	265,500	$	4.21	1.14 years	$	—
Exercisable, June 30, 2023	265,500	$	4.21	1.14 years

The intrinsic values were calculated using the closing price on June 30, 2023 of $1.71 and the closing price on June 30, 2022 of $2.66. As of June 30, 2023, the Company had $0 of unrecognized compensation cost related to stock options.

Restricted Stock Units

A summary of the restricted stock unit activity as of June 30, 2023 and 2022, respectively, and changes during the six months then ended are as follows:

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	Restricted Stock Units	Weighted- Average Grant Date Fair Value
Outstanding, December 31, 2021	2,572,596	$	1.75
Granted	1,247,061	2.79
Forfeited or rescinded	—	—
Vested	—	—
Outstanding, March 31, 2022	3,819,657	$	2.09
Granted	19,642	$	4.27
Forfeited or rescinded	(17,204)	$	2.79
Vested	(610,195)	$	2.80
Outstanding, June 30, 2022	3,211,900	$	1.97

Outstanding, December 31, 2022	2,623,790	$	2.29
Granted	2,270,842	2.22
Forfeited or rescinded	(11,712)	2.22
Vested	(659,479)	2.80
Outstanding, March 31, 2023	4,223,441	$	2.17
Granted	—	$	—
Forfeited or rescinded	(49,465)	$	2.22
Vested	(288,709)	$	2.85
Outstanding, June 30, 2023	3,885,267	$	2.12

As of June 30, 2023, the Company had $5,060,731 of unrecognized compensation cost related to restricted stock unit grants that will be recognized over a weighted average period of 2.05 years. Grant activity for the six months ended June 30, 2023 was primarily restricted stock units for the annual long-term incentive plan awards for employees.

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Performance Stock Units

A summary of the status of the performance stock unit ("PSU") grants as of June 30, 2023 and 2022, respectively, along with changes during the six months then ended are as follows:


	Performance Stock Units	Weighted- Average Grant Date Fair Value
Outstanding, December 31, 2021	860,216	$	3.87
Granted	860,216	3.65
Forfeited or rescinded	—	—
Vested	—	—
Outstanding, March 31, 2022	1,720,432	$	3.76
Granted	—	$	—
Forfeited or rescinded	—	$	—
Vested	—	$	—
Outstanding, June 30, 2022	1,720,432	$	3.76

Outstanding, December 31, 2022	1,720,432	$	3.76
Granted	1,162,162	2.71
Forfeited or rescinded	—	—
Vested	—	—
Outstanding, March 31, 2023	2,882,594	$	3.34
Granted	—	$	—
Forfeited or rescinded	—	$	—
Vested	—	$	—
Outstanding, June 30, 2023	2,882,594	$	3.34

As of June 30, 2023, the Company had $6,364,168 of unrecognized compensation cost related to the PSU awards that will be recognized over a weighted average period of 1.76 years.

NOTE 12 — COMMITMENTS & CONTINGENCIES

Standby Letters of Credit – A commercial bank issued standby letters of credit on behalf of the Company totaling $260,000 to state and federal agencies and $500,438 to an insurance company to secure the surety bonds described below. The standby letters of credit are valid until cancelled or matured and are collateralized by the revolving credit facility with the bank. The terms of the letters of credit to the state and federal agencies are extended for a term of one year at a time. The Company intends to renew the standby letters of credit to the state and federal agencies for as long as the Company does business in the States of Texas and New Mexico. The letters of credit to the insurance company will be renewed if the insurance requires them to retain the surety bonds. No amounts have been drawn under the standby letters of credit.

Surety Bonds – An insurance company issued surety bonds on behalf of the Company totaling $500,438 to various State of New Mexico agencies in order for the Company to do business in the State of New Mexico. The surety bonds are valid until canceled or matured. The terms of the surety bonds are extended for a term of one year at a time. The Company intends to renew the surety bonds on $400,000 as long as the Company does business in the State of New Mexico. The remaining $100,438 is related to inactive wells and will remain in place until the Company returns those wells to activity or plugs them. One of those wells has been plugged, and the bond released in the amount of $50,150, leaving the amount related to inactive wells as $50,288. On December 23, 2022, the Company increased its blanket plugging surety bond by $200,000. As of June 30, 2023, the Company had surety bonds in total of $650,288.

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NOTE 13 — SUBSEQUENT EVENTS

Founders Acquisition

On July 10, 2023, the Company, as buyer, and Founders Oil & Gas IV, LLC (the “Founders”), as seller, entered into an Asset Purchase Agreement (the “Purchase Agreement”). Pursuant to the Purchase Agreement, the Company will acquire (the “Founders Acquisition”) interests in oil and gas leases and related property of Founders located in Ector County, Texas, for a purchase price (the “Purchase Price”) of $75 million in cash. The Purchase Price is subject to customary purchase price adjustments with an effective date of April 1, 2023. In connection with the Purchase Agreement, the Company deposited $7.5 million in cash into a third-party escrow account as a deposit pursuant to the Purchase Agreement, which will be credited against the Purchase Price upon closing of the Founders Acquisition.

In accordance with ASC Topic 855, Subsequent Events, the Company has evaluated all events subsequent to the balance sheet date of June 30, 2023, through the date of this report. The Company has reported on all material subsequent events.

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Item 2: 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 Quarterly Report. The following discussion includes forward-looking statements that reflect our plans, estimates and beliefs and our actual results could differ materially from those discussed in these forward-looking statements as a result of many factors, including those discussed under “Risk Factors,” "Forward Looking Statements" and elsewhere in this Quarterly Report.

Overview

Ring Energy, Inc. (the "Company," "Ring," "we," "us," "our" and similar terms) is a growth oriented independent exploration and production company based in The Woodlands, Texas engaged in oil and natural gas development, production, acquisition, and exploration activities currently focused in the Permian Basin of Texas. Our primary drilling operations target the oil and liquids rich producing formations in the Northwest Shelf and the Central Basin Platform, both of which are part of the Permian Basin.

Business Description and Plan of Operation

The Company is focused on balancing the need to reduce long-term debt and further developing our oil and gas properties to maintain or grow our annual production. We intend to achieve both through proper allocation of cash flow generated by our operations and potentially through the sale of non-core assets. We intend to continue evaluating potential transactions to acquire strategic producing assets with attractive acreage positions that can provide competitive returns for our shareholders.

•Growing production and reserves by developing our oil-rich resource base through conventional and horizontal drilling. In an effort to maximize its value and resources potential, Ring intends to drill and develop its acreage base in both the Northwest Shelf and Central Basin Platform assets, allowing Ring to execute on its plan of operating within its generated cash flow.

•Reduction of long-term debt and deleveraging of asset. Ring intends to reduce its long-term debt primarily through the use of excess cash flow and potentially through the sale of non-core assets. The Company believes that with its attractive field level margins, it is well 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 June 30, 2023, the Company made net paydowns of $25 million on its revolving line of credit, which reduced the outstanding long-term debt balance to $397 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 exceptional upside potential. Ring has a history of acquiring leasehold positions that it believes to have additional resource potential that meet its targeted returns on invested capital and comparable to its existing inventory of drilling locations. We pursue an acquisition strategy designed to increase reserves at attractive finding costs and complement existing core properties. Management intends to continue to pursue strategic acquisitions and structure the potential transactions financially, so they improve 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. Ring believes that leveraging the relationships of its management and board of directors will be a competitive advantage in identifying potential acquisition targets.

2023 Developments and Highlights

Drilling, Completion, and Recompletion

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In the first quarter of 2023, in the Northwest Shelf, the Company drilled and completed two 1-mile horizontal wells (each with a working interest of 100%), and two 1.5-mile horizontal wells (one with a working interest of approximately 99.8% and the other with a working interest of approximately 75.4%). Next, in its Crane County acreage within the Central Basin Platform, the Company drilled and completed three vertical wells (each with a working interest of 100%) and performed six vertical well re-completions (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 re-completions (each with a working interest of 100%).

The table below sets forth our drilling and completion activities for 2023 for the six months ended June 30, 2023.


Quarter	Area	Wells Drilled	Wells Completed	Re-completions

1Q 2023	Northwest Shelf	4	4	—
	Central Basin Platform (Vertical)	3	3	6

	Total	7	7	6

2Q 2023	Northwest Shelf	4	4	—
	Central Basin Platform (Vertical)	2	2	3

	Total	6	6	3

Market Conditions and Commodity Prices

Our financial results depend on many factors, particularly the price of crude oil and natural gas and our ability to market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand both domestically and world wide, which are impacted by many factors. As a result, we cannot accurately predict future commodity prices, and therefore, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our drilling program, production volumes or revenues.

Average oil and natural gas prices received through 2022 and 2023 to date continue to demonstrate commodity price volatility and we believe oil and natural gas prices will continue to be volatile for the foreseeable future. The ability to find and develop sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success.

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Results of Operations

Oil, Natural Gas, and Natural Gas Liquids Revenues for the Three Months Ended June 30, 2023 and 2022


	For the Three Months Ended
	June 30, 2023		June 30, 2022		Change		% Change
Net sales:
Oil	$	78,042,072	$	79,688,536	$	(1,646,464)	(2)	%
Natural gas	(1,100,776)		5,273,339		(6,374,115)		(121)	%
Natural gas liquids	2,407,277		—		2,407,277		100	%
Total sales	$	79,348,573	$	84,961,875	$	(5,613,302)	(7)	%

Net production:
Oil (Bbls)	1,079,379		729,484		349,895		48	%
Natural gas (Mcf)	1,557,545		723,196		834,349		115	%
Natural gas liquids (Bbls)	232,698		—		232,698		100	%
Total production (Boe)(1)	1,571,668		850,017		721,651		85	%

Average sales price:
Oil (per Bbl)	$	72.30	$	109.24	$	(36.94)	(34)	%
Natural gas (per Mcf)	(0.71)		7.29		(8.00)		(110)	%
Natural gas liquids (Bbl)	10.35		—		10.35		100	%
Total per Boe	$	50.49	$	99.95	$	(49.46)	(49)	%

(1) Boe is calculated using six Mcf of natural gas as the equivalent of one barrel of oil.

Oil sales. Oil sales decreased approximately $1.6 million from $79.7 million to $78.0 million due to a decrease in the average realized price per barrel from $109.24 to $72.30, offset by an increase in sales volume from 729,484 barrels of oil to 1,079,379 barrels of oil. The decreased average realized price per barrel was primarily a result of lower market conditions. Of the increase in volume of 349,895 barrels of oil, 285,981 barrels of oil were attributable to the Stronghold Acquisition with the remainder attributable to our 2023 development program offset by the Delaware divestiture.

Natural gas sales. Natural gas sales decreased approximately $6.4 million from $5.3 million to $(1.1) million. Our natural gas sales volume increased from 723,196 Mcf to 1,557,545 Mcf. The average realized price per Mcf decreased from $7.29 to $(0.71). Of the increase in volume of 834,349 Mcf, 873,689 Mcf was attributable to the Stronghold Acquisition with the remainder attributable to our 2023 development program offset by the Delaware divestiture. The price decrease was driven by a significant reduction in realized revenue pricing due to lower market conditions, lower gas differential from intermittent Permian gas takeaway pipeline constraints and the Company's change in reporting presentation from two-stream (oil and natural gas) to three-stream (oil, natural gas, and NGLs) beginning on July 1, 2022. The realized revenue pricing includes the impact of fees that are netted from revenue. For the three months ended June 30, 2023, gross revenues were $1.01 per Mcf and fees were $(1.71) per Mcf, compared to gross revenues of $9.13 per Mcf (which was inclusive of NGLs prior to three-stream conversion) and fees of $(1.84) per Mcf for the three months ended June 30, 2022. This resulted in a net realized price of $(0.71) for the three months ended June 30, 2023 compared to $7.29 per Mcf for the three months ended June 30, 2022.

Natural gas liquids sales. NGL sales increased approximately $2.4 million from $0 to $2.4 million. NGL sales volumes for the three months ended June 30, 2023 were 232,698 barrels of NGLs compared to no sales of NGLs for the comparable period in 2022 due to the Company's change in reporting presentation for its natural gas products, which are presented on a three-stream basis beginning on July 1, 2022. Of the increase in volume of 232,698 barrels, 139,894 barrels is attributable to the Stronghold Acquisition with the remainder attributable to our 2023 development program offset by the Delaware divestiture. The average realized price per barrel of NGLs was $10.35 for the three months ended June 30, 2023.

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Oil, Natural Gas, and Natural Gas Liquids Revenues for the Six Months Ended June 30, 2023 and 2022


	For the Six Months Ended
	June 30, 2023		June 30, 2022		Change		% Change
Net sales:
Oil	$	161,628,399	$	143,119,163	$	18,509,236	13	%
Natural gas	(36,213)		10,023,744		(10,059,957)		(100)	%
Natural gas liquids	5,839,299		—		5,839,299		100	%
Total sales	$	167,431,485	$	153,142,907	$	14,288,578	9	%

Net production:
Oil (Bbls)	2,218,792		1,405,699		813,093		58	%
Natural gas (Mcf)	3,158,952		1,455,479		1,703,473		117	%
Natural gas liquids (Bbls)	472,690		—		472,690		100	%
Total production (Boe)(1)	3,217,974		1,648,279		1,569,695		95	%

Average sales price:
Oil (per Bbl)	$	72.85	$	101.81	$	(28.96)	(28)	%
Natural gas (per Mcf)	(0.01)		6.89		(6.90)		(100)	%
Natural gas liquids (Bbl)	12.35		—		12.35		100	%
Total per Boe	$	52.03	$	92.91	$	(40.88)	(44)	%

(1) Boe is calculated using six Mcf of natural gas as the equivalent of one barrel of oil.

Oil sales. Oil sales increased approximately $18.5 million from $143.1 million to $161.6 million due to an increase in sales volume from 1,405,699 barrels of oil to 2,218,792 barrels of oil, offset by a decrease in the average realized price per barrel from $101.81 to $72.85. Of the increase in volume of 813,093 barrels, 595,359 barrels of oil was attributable to the Stronghold Acquisition with the remainder attributable to our 2023 development program offset by the Delaware divestiture.The decreased average realized price per barrel was primarily the result of lower market conditions.

Natural gas sales. Natural gas sales decreased approximately $10.1 million from $10.0 million to $(36,213). The natural gas sales volume increased from 1,455,479 Mcf to 3,158,952 Mcf. The average realized price per Mcf decreased from $6.89 to $(0.01). Of the increase in volume of 1,703,473 Mcf, 1,836,827 Mcf was attributable to the Stronghold Acquisition with the remainder attributable to our 2023 development program offset by the Delaware divestiture. The price decrease was driven by lower market conditions coupled with lower gas differential due to intermittent Permian gas takeaway pipeline constraints and the Company's change in reporting presentation from two-stream (oil and natural gas) to three-stream (oil, natural gas, and NGLs) beginning on July 1, 2022. The realized revenue pricing includes the impact of fees that are netted from revenue. For the six months ended June 30, 2023, gross revenues were $1.52 per Mcf and fees were $(1.53) per Mcf, compared to gross revenues of $8.00 per Mcf (which was inclusive of NGLs prior to three-stream conversion) and fees of $(1.11) per Mcf for the six months ended June 30, 2022. This resulted in a net realized price of $(0.01) for the six months ended June 30, 2023 compared to $6.89 per Mcf for the six months ended June 30, 2022.

Natural gas liquids sales. NGL sales increased approximately $5.8 million from $0 to $5.8 million. NGL sales volumes for the six months ended June 30, 2023 were 472,690 barrels of NGLs compared to no sales of NGLs for the comparable period in 2022 due to the Company's change in reporting presentation for its natural gas products, which are presented on a three-stream basis beginning July 1, 2022. Of the increase in volume of 472,690 barrels, 293,848 barrels is attributable to the Stronghold Acquisition with the remainder attributable to our 2023 development program offset by the Delaware divestiture. The average realized price per barrel of NGLs was $12.35 for the six months ended June 30, 2023.

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Production Costs for the Three Months Ended June 30, 2023 and 2022


	For the Three Months Ended
	June 30, 2023			June 30, 2022			Change			% Change

Lease operating expenses ("LOE")	$	15,938,106		$	8,301,443		$	7,636,663		92	%
Average LOE per Boe	$	10.14		$	9.77		$	0.37		4	%

Gathering, transportation and processing costs ("GTP")	$	(1,632)		$	549,389		$	(551,021)		(100)	%
Average GTP per Boe	$	—		$	0.65		$	(0.65)		(100)	%

Ad valorem taxes	$	1,670,343		$	949,239		$	721,104		76	%
Average Ad valorem taxes per Boe	$	1.06		$	1.12		$	(0.06)		(5)	%

Oil and natural gas production taxes	$	4,012,139		$	4,157,457		$	(145,318)		(3)	%
Average Production taxes per Boe	$	2.55		$	4.89		$	(2.34)		(48)	%
Production taxes as a percentage of total sales	5.06		%	4.89		%	0.17		%	3	%

Lease operating expenses. Our total lease operating expenses (“LOE”) increased from $8.3 million to $15.9 million and increased on a per Boe basis from $9.77 to $10.14. These per Boe amounts are calculated by dividing our total lease operating expenses by our total volume sold, in Boe. Total LOE increased primarily due to an 85% increase in production of 721,651 Boe as a result of the Stronghold Acquisition as well as our 2023 development program.

Gathering, transportation and processing costs. Our total gathering, transportation and processing costs (“GTP”) decreased from $549,389 to a negative $1,632 and decreased on a per Boe basis from $0.65 to $—. GTP costs decreased from being re-classified as a reduction to oil and natural gas sales revenues, due to a natural gas processing entity taking control of transportation at the wellhead beginning on May 1, 2022. The negative $1,632 recognized during the second quarter of 2023 was a result of payout adjustments made during the current period.

Ad valorem taxes. Our total ad valorem taxes increased from $0.9 million to $1.7 million and decreased on a per Boe basis from $1.12 to $1.06. Of the approximate $0.7 million increase in ad valorem taxes, approximately $0.6 million is from the addition of properties associated with the Stronghold Acquisition.

Oil and natural gas production taxes. Oil and natural gas production taxes as a percentage of oil and natural gas sales were 4.89% for the three months ended June 30, 2022 and increased to 5.06% for the three months ended June 30, 2023. Overall, the percentage was consistent period over period.

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Production Costs for the Six Months Ended June 30, 2023 and 2022


	For the Six Months Ended
	June 30, 2023			June 30, 2022			Change			% Change

Lease operating expenses ("LOE")	$	33,410,797		$	17,254,608		$	16,156,189		94	%
Average LOE per Boe	$	10.38		$	10.47		$	(0.09)		(1)	%

Gathering, transportation and processing costs ("GTP")	$	(2,455)		$	1,846,247		$	(1,848,702)		(100)	%
Average GTP per Boe	$	—		$	1.12		$	(1.12)		(100)	%

Ad valorem taxes	$	3,340,956		$	1,901,193		$	1,439,763		76	%
Average Ad valorem taxes per Boe	$	1.04		$	1.15		$	(0.11)		(10)	%

Oil and natural gas production taxes	$	8,420,279		$	7,375,819		$	1,044,460		14	%
Average Production taxes per Boe	$	2.62		$	4.47		$	(1.85)		(41)	%
Production taxes as a percentage of total sales	5.03		%	4.82		%	0.21		%	4	%

Lease operating expenses. Our total LOE increased from $17.3 million to $33.4 million and decreased on a per Boe basis from $10.47 to $10.38. Total LOE increased primarily due to a 95% increase in production of 1,569,695 Boe as a result of the Stronghold Acquisition as well as our 2023 development program.

Gathering, transportation and processing costs. Our total GTP decreased from $1,846,247 to a negative $2,455 and decreased on a per Boe basis from $1.12 to $—. GTP costs decreased from being re-classified as a reduction to oil and natural gas sales revenues, due to a natural gas processing entity taking control of transportation at the wellhead beginning on May 1, 2022. The negative $2,455 recognized during the second quarter of 2023 was a result of payout adjustments.

Ad valorem taxes. Our total ad valorem taxes increased from $1.9 million to $3.3 million and decreased on a per Boe basis from $1.15 to $1.04. Of the $1.4 million increase in ad valorem taxes, approximately $1.3 million is from the addition of properties associated with the Stronghold Acquisition.

Oil and natural gas production taxes. Oil and natural gas production taxes as a percentage of oil and natural gas sales were 4.82% for the six months ended June 30, 2022 and increased to 5.03% for the six months ended June 30, 2023. Overall, the percentage was consistent period over period.

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Other Costs and Operating Expenses for the Three Months Ended June 30, 2023 and 2022


	For the Three Months Ended
	June 30, 2023		June 30, 2022		Change		% Change

Depreciation, depletion and amortization (DD&A):
Depletion	$	20,511,809	$	10,629,787	$	9,882,022	93	%
Depreciation	91,628		8,567		83,061		970	%
Amortization of financing lease assets	189,495		110,850		78,645		71	%
Total depreciation, depletion and amortization	$	20,792,932	$	10,749,204	$	10,043,728	93	%

Depletion per Boe	$	13.05	$	12.51	$	0.54	4	%
Depreciation, depletion and amortization per Boe	$	13.23	$	12.65	$	0.58	5	%

Asset retirement obligation ("ARO") accretion	$	353,878	$	186,303	$	167,575	90	%

Operating lease expense	$	115,353	$	83,590	$	31,763	38	%

General and administrative expense ("G&A"):
General and administrative expense (excluding Share-based compensation)	$	4,549,931	$	3,933,057	$	616,874	16	%
Share-based compensation	2,260,312		1,899,245		361,067		19	%
Total general and administrative expense	$	6,810,243	$	5,832,302	$	977,941	17	%

G&A per Boe	$	4.33	$	6.86	$	(2.53)	(37)	%
G&A excluding Share-based compensation, per Boe	$	2.89	$	4.63	$	(1.74)	(38)	%

Depreciation, depletion and amortization. Our depreciation, depletion and amortization increased from $10.7 million to $20.8 million due to an increase in our total estimated costs of property, including properties acquired in the Stronghold Acquisition, as well as a increase of 721,651 in Boe produced. Additional trucks were purchased and leased for field operations, resulting in higher depreciation and finance lease amortization costs. Our average depreciation, depletion and amortization per Boe increased from $12.65 per Boe to $13.23 per Boe. These per Boe amounts are calculated by dividing our total depreciation, depletion and amortization expense by our total Boe volumes sold. The increase in DD&A per Boe was from an increase in the total estimated costs of property that was higher than the increase in the Boe amortization base.

Asset retirement obligation accretion. Our asset retirement obligation (“ARO”) accretion increased from $186,303 to $353,878 primarily as a result of the additional ARO accretion associated with the properties added from the Stronghold Acquisition. Additionally, between the beginning of the third quarter of 2022 and the end of the second quarter of 2023, 34 new wells were added from drilling and completion activities and one well from participation in non-operating activities, offset by 25 wells plugged and abandoned during that time period.

Operating lease expense. Our operating lease expense increased from $83,590 to $115,353 due to the additional office space leased in Midland beginning on October 1, 2022.

General and administrative expense. General and administrative expense increased from $5.8 million to $6.8 million, with $0.4 million of the $1.0 million cost increase due to an increase in share-based compensation costs. The remaining $0.6 million increase in G&A costs were primarily attributable to a $0.6 million increase in salaries and wages, a $0.2 million increase in bonuses, a $0.2 million increase in transaction costs, and a $0.2 million increase in legal fees, offset by a $0.6 million reduction in G&A costs from the Employee Retention Tax Credit, received in the current quarter.

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Other Costs and Operating Expenses for the Six Months Ended June 30, 2023 and 2022


	For the Six Months Ended
	June 30, 2023		June 30, 2022		Change		% Change

Depreciation, depletion and amortization (DD&A):
Depletion	$	41,492,351	$	20,254,404	$	21,237,947	105	%
Depreciation	196,729		48,622		148,107		305	%
Amortization of financing lease assets	375,523		227,465		148,058		65	%
Total depreciation, depletion and amortization	$	42,064,603	$	20,530,491	$	21,534,112	105	%

Depletion per Boe	$	12.89	$	12.29	$	0.60	5	%
Depreciation, depletion and amortization per Boe	$	13.07	$	12.46	$	0.61	5	%

Asset retirement obligation ("ARO") accretion	$	719,725	$	374,545	$	345,180	92	%

Operating lease expense	$	228,491	$	167,180	$	61,311	37	%

General and administrative expense ("G&A"):
General and administrative expense (excluding Share-based compensation)	$	9,736,374	$	7,933,424	$	1,802,950	23	%
Share-based compensation	4,204,008		3,421,155		782,853		23	%
Total general and administrative expense	$	13,940,382	$	11,354,579	$	2,585,803	23	%

G&A per Boe	$	4.33	$	6.89	$	(2.56)	(37)	%
G&A excluding Share-based compensation, per Boe	$	3.03	$	4.81	$	(1.78)	(37)	%

Depreciation, depletion and amortization. Our depreciation, depletion and amortization increased from $20.5 million to $42.1 million due to an increase in our total estimated costs of property, including properties acquired in the Stronghold Acquisition, as well as an increase of 1,569,695 in Boe produced. Additional trucks were purchased and leased for field operations, resulting in higher depreciation and finance lease amortization costs. Our average depreciation, depletion and amortization per Boe increased from $12.46 per Boe to $13.07 per Boe.

Asset retirement obligation accretion. Our ARO accretion increased from $374,545 to $719,725 primarily as a result of the additional ARO accretion associated with the properties added from the Stronghold Acquisition (total of 913 wells added). Additionally, during the prior 12 months, 10 new wells were added from drilling and completion and non-operated activities, net of wells plugged and abandoned or sold.

Operating lease expense. Our operating lease expense increased from $167,180 to $228,491 due to the additional office space leased in Midland beginning October 1, 2022.

General and administrative expense. General and administrative expense increased from $11.4 million to $13.9 million, with $0.8 million of the $2.6 million cost increase due to an increase in share-based compensation costs. The remaining $1.8 million increase in G&A costs were primarily attributable to a $1.2 million increase in salaries and wages, a $0.6 million increase in bonuses, a $0.3 million increase in legal fees, a $0.3 million increase in software costs, and a $0.2 million increase in transaction costs, offset by a $0.6 million reduction in G&A costs from the Employee Retention Tax Credit as well as a $0.2 million reduction in employee health insurance costs.

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Other Income (Expense) for the Three Months Ended June 30, 2023 and 2022


	For the Three Months Ended
	June 30, 2023		June 30, 2022		Change		% Change

Interest income	$	79,745	$	—	$	79,745	100	%

Interest expense:
Interest on revolving line of credit	$	9,056,845	$	2,987,366	$	6,069,479	203	%
Fees associated with revolving line of credit	$	240,075	$	90,697	149,378		165	%
Amortization of deferred financing costs	$	1,220,385	$	189,274	1,031,111		545	%
Interest on financing lease liabilities	$	24,268	$	7,280	16,988		233	%
Interest paid for notes payable	$	9,234	$	4,682	4,552		97	%

Total interest expense	$	10,550,807	$	3,279,299	$	7,271,508	222	%

Gain (loss) on derivative contracts:
Realized gain (loss):
Crude oil	$	(833,841)	$	(19,617,265)	$	18,783,424	(96)	%
Natural gas	1,013,436		—		1,013,436		100	%
Total realized gain (loss)	$	179,595	$	(19,617,265)	$	19,796,860	(101)	%
Unrealized gain (loss):
Crude oil	$	4,545,136	$	12,160,247	$	(7,615,111)	(63)	%
Natural gas	(1,460,071)		—		(1,460,071)		100	%
Total unrealized gain (loss)	$	3,085,065	$	12,160,247	$	(9,075,182)	(75)	%
Total gain (loss) on derivative contracts:	$	3,264,660	$	(7,457,018)	$	10,721,678	(144)	%

Gain (loss) on disposal of assets	$	(132,109)	$	—	$	(132,109)	100	%
Other income	$	116,610	$	—	$	116,610	100	%

Interest income. Interest income recognized included $50,703 from depositing excess cash balances in bank sweep accounts beginning in May 2023 and $29,042 from interest earned on the Employee Retention Tax Credit.

Interest expense. Interest expense increased from $3.3 million to $10.6 million primarily due to higher amounts outstanding on our credit facility, with a weighted average daily debt of approximately $273.7 million during the second quarter of 2022 compared to approximately $414.9 million during the second quarter of 2023, particularly due to the additional debt incurred in connection with the Stronghold Acquisition. Additionally, the increase in interest expense was due to higher interest rates, with a weighted average interest rate of 8.7% in the second quarter of 2023 compared to 4.4% in the second quarter of 2022.

Gain (loss) on derivative contracts. We recorded a gain on derivative contracts of $3.3 million for the three months ended June 30, 2023 compared to a loss on derivative contracts of $7.5 million for the three months ended June 30, 2022. For the derivative contract settlements, we recorded a realized gain of $0.2 million for the three months ended June 30, 2023 and a realized loss of $19.6 million for the three months ended June 30, 2022. The reduction of $19.8 million in the realized loss was a result of our more favorable derivative contract portfolio during the three months ended June 30, 2023. In the same quarter of the prior year, we were party to swaps with prices as low as $44.22, compared to oil settlement prices as high as $114.34. For the marked-to-market contracts, we recorded an unrealized gain of $3.1 million for the three months ended June 30, 2023 and an unrealized gain of $12.2 million for the three months ended June 30, 2022. This significant unrealized gain recognized in the three months ended June 30, 2022 was due to 12 favorable derivative contracts entered into during the last two days of that quarter.

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Gain (loss) on disposal of assets. We recognized a loss of $132,109 on disposal from selling multiple company owned vehicles.

Other income. During the quarter, we recognized other income of $116,036 from terminating our Woodlands office operating lease. The remaining other income was from terminating a finance lease for a truck.

Other Income (Expense) for the Six Months Ended June 30, 2023 and 2022


	For the Six Months Ended
	June 30, 2023		June 30, 2022		Change		% Change

Interest income	$	79,745	$	—	$	79,745	100	%

Interest expense:
Interest on revolving line of credit	$	17,766,719	$	6,116,987	$	11,649,732	190	%
Fees associated with revolving line of credit	$	478,250	$	149,048	329,202		221	%
Amortization of deferred financing costs	$	2,440,769	$	388,548	2,052,221		528	%
Interest on financing lease liabilities	$	49,699	$	13,793	35,906		260	%
Interest paid for notes payable	$	12,925	$	9,284	3,641		39	%
Deferred cash payment accretion	$	192,724	$	—	192,724		100	%
Total interest expense	$	20,941,086	$	6,677,660	$	14,263,426	214	%

Gain (loss) on derivative contracts:
Realized gain (loss):
Crude oil	$	(1,497,603)	$	(33,732,766)	$	32,235,163	(96)	%
Natural gas	1,018,673		—		1,018,673		100	%
Total realized gain (loss)	$	(478,930)	$	(33,732,766)	$	33,253,836	(99)	%
Unrealized gain (loss):
Crude oil	$	12,652,157	$	(1,320,393)	$	13,972,550	(1058)	%
Natural gas	566,338		—		566,338		100	%
Total unrealized gain (loss)	$	13,218,495	$	(1,320,393)	$	14,538,888	(1101)	%
Total gain (loss) on derivative contracts:	$	12,739,565	$	(35,053,159)	$	47,792,724	(136)	%

Gain (loss) on disposal of assets	$	(132,109)	$	—	$	(132,109)	100	%
Other income	$	126,210	$	—	$	126,210	100	%

Interest expense. Interest expense increased from $6.7 million to $20.9 million primarily due to the result of higher amounts outstanding on our credit facility, with a weighted average daily debt of approximately $283.8 million during the six months ended June 30, 2022 compared to approximately $419.6 million during the six months ended June 30, 2023, particularly due to additional debt incurred in connection with the Stronghold Acquisition. Additionally, the increase in interest expense was due to higher interest rates, with a weighted average interest rate of 8.5% during the six months ended June 30, 2023 compared to 4.3% during the six months ended June 30, 2022.

Gain (loss) on derivative contracts. We recorded a gain on derivative contracts of $12.7 million for the six months ended June 30, 2023 and a loss on derivative contracts of $35.1 million for the six months ended June 30, 2022. For the derivative contract settlements, we recorded a realized loss of $0.5 million for the six months ended June 30, 2023 and a realized loss

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of $33.7 million for the six months ended June 30, 2022. The reduction of $33.3 million in the realized loss was a result of our better diversified and more favorable derivative contract portfolio during the current year. In the prior year, our portfolio included swap prices significantly lower than oil settlement prices. For the marked-to-market contracts, we recorded an unrealized gain of $13.2 million for the six months ended June 30, 2023 and an unrealized loss of $1.3 million for the six months ended June 30, 2022. This change in unrealized derivatives was due to a more favorable diversification of derivative contracts held.

Gain (loss) on disposal of assets. We recognized a loss of $132,109 on disposal from selling multiple company owned vehicles.

Other income. This income primarily resulted from our termination of the Woodlands office operating lease as of May 31, 2023.

Benefit from (Provision for) Income Taxes for the Three Months Ended June 30, 2023 and 2022


	For the Three Months Ended
	June 30, 2023		June 30, 2022		Change		% Change

Benefit from (Provision for) Income Taxes:
Deferred federal income tax benefit (provision)	$	6,640,741	$	(1,014,048)	$	7,654,789	(755)	%
Current state income tax benefit (provision)	$	(41,191)	$	12,813	(54,004)		(421)	%
Deferred state income tax benefit (provision)	$	(243,255)	$	(470,974)	227,719		(48)	%
Benefit from (Provision for) Income Taxes	$	6,356,295	$	(1,472,209)	$	7,828,504	(532)	%

Benefit from (Provision for) income taxes. The benefit from (provision for) income taxes changed from a provision of $1.5 million for the three months ended June 30, 2022 to a benefit of $6.4 million for the three months ended June 30, 2023. Income taxes for discrete items are calculated and recorded in the period that a specific transaction occurred. For the three months ended June 30, 2023, the overall effective rate was different than the federal statutory rate due primarily to state income taxes and valuation allowances. The current year federal tax benefit was the result of the release in valuation allowance. As a result of increased commodity prices and other positive evidence, we released the federal valuation allowances in the first six months of 2023, of which $7.7 million was recorded as a discrete item.

Benefit from (Provision for) Income Taxes for the Six Months Ended June 30, 2023 and 2022


	For the Six Months Ended
	June 30, 2023		June 30, 2022		Change		% Change

Benefit from (Provision for) Income Taxes:
Deferred federal income tax benefit (provision)	$	5,111,491	$	(1,014,048)	$	6,125,539	(604)	%
Current state income tax benefit (provision)	$	(98,481)	$	—	(98,481)		100	%
Deferred state income tax benefit (provision)	$	(686,658)	$	(536,913)	(149,745)		28	%
Benefit from (Provision for) Income Taxes	$	4,326,352	$	(1,550,961)	$	5,877,313	(379)	%

Benefit from (Provision for) income taxes. The benefit from (provision for) income taxes changed from a provision of $1.6 million for the six months ended June 30, 2022 to a benefit of $4.3 million for the six months ended June 30, 2023. The current year federal tax provision was the result of the release in valuation allowance. Due to increased commodity prices and other positive evidence, we released the federal valuation allowances in the first six months of 2023, of which $7.7 million was recorded as a discrete item.

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Liquidity and Capital Resources

As of June 30, 2023, we had cash on hand of $1.7 million, compared to $3.7 million as of December 31, 2022. We had net cash provided by operating activities for the six months ended June 30, 2023 of $87.0 million, compared to net cash provided by operating activities of $65.2 million for the same period in 2022 primarily due to higher year to date revenues, which resulted in more cash received from purchasers. We had net cash used in investing activities of $83.6 million for the six months ended June 30, 2023, compared to net cash used in investing activities of $50.3 million for the same period in 2022, driven by an increase in capital expenditures to develop oil and natural gas properties, as well as deferred payments made for the Stronghold Acquisition. Net cash used in financing activities was $5.4 million for the six months ended June 30, 2023 during which time $18 million was the net pay down of principal on our Credit Facility.

We will continue to focus on maximizing cash flow in 2023 through a combination of cost monitoring and prudent capital allocation, which includes prioritizing our capital to projects we believe will provide high rates of return in the current commodity price environment. We will continue our pursuit of acquisitions and business combinations, seeking opportunities that we believe will provide high margin properties with attractive returns at current commodity prices.

During the remainder of 2023, we will remain focused on maximizing cash flow, reducing our debt level, and maximizing our liquidity.

Availability of Capital Resources under Credit Facility

As of June 30, 2023, $397 million was outstanding on our Credit Facility and we were in compliance with all of the covenants under the Credit Facility. The Credit Facility matures in August 2026. The borrowing base under our Credit Facility is $600 million. The borrowing base is redetermined semi-annually on each May 1 and November 1. See "NOTE 8 — REVOLVING LINE OF CREDIT" in the Notes to the condensed financial statements for more information on our Credit Facility.

Derivative Financial Instruments

The following table reflects the contracts outstanding as of June 30, 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)
	Q3 2023		Q4 2023		Q1 2024		Q2 2024		Q3 2024		Q4 2024		Q1 2025		Q2 2025		Q3 2025		Q4 2025

Swaps:
Hedged volume (Bbl)	181,700		138,000		170,625		156,975		282,900		368,000		—		—		—		—
Weighted average swap price	$	74.19	$	74.52	$	67.40	$	66.40	$	65.49	$	68.43	$	—	$	—	$	—	$	—

Deferred premium puts:
Hedged volume (Bbl)	230,000		165,600		45,500		45,500		—		—		—		—		—		—
Weighted average strike price	$	80.47	$	83.78	$	84.70	$	82.80	$	—	$	—	$	—	$	—	$	—	$	—
Weighted average deferred premium price	$	10.60	$	14.61	$	17.15	$	17.49	$	—	$	—	$	—	$	—	$	—	$	—

Two-way collars:
Hedged volume (Bbl)	211,163		274,285		339,603		325,847		230,000		128,800		474,750		464,100		—		—
Weighted average put price	$	55.56	$	56.73	$	64.20	$	64.30	$	64.00	$	60.00	$	57.06	$	60.00	$	—	$	—
Weighted average call price	$	69.25	$	70.77	$	79.73	$	79.09	$	76.50	$	73.24	$	75.82	$	69.85	$	—	$	—

Three-way collars:
Hedged volume (Bbl)	16,242		15,598		—		—		—		—		—		—		—		—
Weighted average first put price	$	45.00	$	45.00	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Weighted average second put price	$	55.00	$	55.00	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Weighted average call price	$	80.05	$	80.05	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—

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	Gas Hedges (Henry Hub)
	Q3 2023		Q4 2023		Q1 2024		Q2 2024		Q3 2024		Q4 2024		Q1 2025		Q2 2025		Q3 2025		Q4 2025

NYMEX Swaps:
Hedged volume (MMBtu)	144,781		203,706		152,113		138,053		121,587		644,946		616,199		591,725		—		—
Weighted average swap price	$	3.36	$	3.35	$	3.62	$	3.61	$	3.59	$	4.45	$	3.78	$	3.43	$	—	$	—

Two-way collars:
Hedged volume (MMBtu)	404,421		579,998		591,500		568,750		552,000		—		—		—		—		—
Weighted average put price	$	3.17	$	3.15	$	4.00	$	4.00	$	4.00	$	—	$	—	$	—	$	—	$	—
Call hedged volume (MMBtu)	404,421		579,998		591,500		568,750		552,000		—		—		—		—		—
Weighted average call price	$	4.55	$	4.50	$	6.29	$	6.29	$	6.29	$	—	$	—	$	—	$	—	$	—


	Oil Hedges (basis differential)
	Q3 2023		Q4 2023		Q1 2024		Q2 2024		Q3 2024		Q4 2024		Q1 2025		Q2 2025		Q3 2025		Q4 2025

Argus basis swaps:
Hedged volume (MMBtu)	305,000		460,000		364,000		364,000		368,000		368,000		270,000		273,000		276,000		276,000
Weighted average spread price (1)	$	1.10	$	1.10	$	1.15	$	1.15	$	1.15	$	1.15	$	1.00	$	1.00	$	1.00	$	1.00


	Gas Hedges (basis differential)
	Q3 2023		Q4 2023		Q1 2024		Q2 2024		Q3 2024		Q4 2024		Q1 2025		Q2 2025		Q3 2025		Q4 2025

Waha basis swaps:
Hedged volume (MMBtu)	332,855		324,021		—		—		—		—		—		—		—		—
Weighted average spread price (1)	$	0.55	$	0.55	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—

El Paso Permian Basin basis swaps:
Hedged volume (MMBtu)	329,529		459,683		—		—		—		—		—		—		—		—
Weighted average spread price (1)	$	0.63	$	0.63	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—

Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the accompanying Condensed Balance Sheets. 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 accompanying Condensed Statements of Operations.

Effects of Inflation and Pricing

The oil and natural gas industry is cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry puts significant pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do associated costs. Material changes in prices impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans and the value of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and

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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 June 30, 2023, we had no off-balance sheet financing arrangements.

Capital Resources for Future Acquisition and Development Opportunities

We continuously evaluate potential acquisitions and development opportunities. To the extent possible, we intend to acquire producing properties with lower-risk undeveloped drilling opportunities rather than properties with higher-risk exploratory opportunities. We do not intend to limit our evaluation to any one state, but we presently have no intention to acquire offshore properties or properties located outside of the United States.

The pursuit of and the acquisition of accretive oil and gas properties may require substantially greater capital than we currently have available and obtaining additional capital may require that we obtain either short-term or long-term debt or sell our equity or both. Further, it may be necessary for us to retain outside consultants and others in our endeavors to locate desirable oil and gas properties.

The process of acquiring one or more additional oil and gas properties would impact our financial position, reduce our cash position and possibly increase our debt. The types of costs that we may incur include the costs to retain consultants and investment bankers specializing in the purchase of oil and gas properties, obtaining petroleum engineering reports relative to the oil and gas properties that we are investigating, legal fees associated with any such acquisitions including title reports, SEC reporting expenses, and negotiating definitive agreements. Additionally, accounting fees may be incurred relative to obtaining and evaluating historical and proforma information regarding such oil and gas properties. Even though we may incur such costs, there is no assurance that we will ultimately be able to consummate other acquisitions of oil and gas producing properties.

Item 3: 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. A significant decline in the prices of oil or natural gas would likely have a material adverse effect on our financial condition and results of operations. In order to reduce commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas, we enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production.

Customer Credit Risk

Our principal exposure to credit risk is through receivables from the sale of our oil and natural gas production (approximately $23.2 million as of June 30, 2023). We are subject to credit risk due to the concentration of our oil and natural gas receivables with our most significant customers, or purchasers. We do not require our purchasers to post collateral, and the inability of our significant purchasers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. Refer to the following table for detail on the top three purchasers of our oil, natural gas, and NGL revenues for the six months ended June 30, 2023. We believe that the loss of any of these purchasers would not materially impact our business because we could readily find other purchasers for our oil and natural gas.

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For the Six Months Ended

As of

June 30, 2023

Percentage of Oil, Natural Gas, and Natural Gas Liquids Revenues

Percentage of accounts receivables from the sale of our oil and natural gas production

Customer:

Phillips 66 Company ("Phillips")

68%

71%

Enterprise Crude Oil LLC ("Enterprise")

13%

NGL Crude Partners ("NGL Crude")

11%

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. 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 June 30, 2023, we had $397.0 million outstanding on our Credit Facility with a weighted average interest rate for the six months ended June 30, 2023 of 8.5%. A 1% change in the interest rate on our Credit Facility would result in an estimated $4.0 million change in our annual interest expense. See "NOTE 8 — REVOLVING LINE OF CREDIT" in the Notes to the condensed financial statements for more information on the Company’s interest rates on our Credit Facility.

Currently, we do not use interest rate derivative instruments to manage exposure to interest rate changes.

Currency Exchange Rate Risk

Foreign sales accounted for none of the Company's sales; the Company accepts payment for its commodity sales only in U.S. dollars. Ring is therefore not exposed to foreign currency exchange rate risk on these sales.

Please also see Item 1A “Risk Factors” for a discussion of other risks and uncertainties we face in our business.

Item 4: Controls and Procedures

Evaluation of disclosure controls and procedures.

Our management, with the participation of Paul D. McKinney, our principal executive officer, and Travis T. Thomas, our principal financial officer, evaluated the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Exchange Act. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well 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 fact that there are resource constraints, and that management is required to apply its judgment in evaluating the benefits of possible controls and procedures relative to their costs.

Based on management’s evaluation, Messrs. McKinney and Thomas concluded that our disclosure controls and procedures as of the end of the period covered by this report were effective in ensuring that information required to be disclosed by us in reports that we file or submit under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (ii) is accumulated and communicated to the Company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

We will continue to monitor and evaluate the effectiveness of our disclosure controls and procedures and our internal controls over financial reporting on an ongoing basis and are committed to taking further action and implementing additional enhancements or improvements, as necessary and as funds allow.

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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 three months ended June 30, 2023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1: Legal Proceedings

The Company is a defendant in a lawsuit in Harris County District Court, Houston, Texas, styled EPUS Permian Assets, LLC, v. Ring Energy, Inc., that was filed in July 2021. The plaintiff, EPUS Permian Assets, LLC, claims breach of contract, money had and received by fraudulent inducement, unjust enrichment and constructive trust. The plaintiff is requesting its forfeited deposit of $5,500,000 in connection with a proposed property sale by the Company plus related damages, and attorneys’ fees and costs. The action relates to a proposed property sale by the Company to the plaintiff, which was extended by the Company on several occasions with the plaintiff ultimately failing to perform on the agreement and the Company keeping the deposit. The Company believes that the claims by the plaintiff are entirely without merit and is conducting a vigorous defense and counterclaim. The Company has filed an answer and a counterclaim denying the allegations and asserting affirmative defenses that would bar or substantially limit the plaintiff’s claims, asserting breach of contract and requesting a declaratory judgment and attorneys’ fees and costs. The parties have begun taking depositions and are conducting discovery.

Item 1A: Risk Factors

We are subject to certain risks and hazards due to the nature of the business activities we conduct. For a discussion of these risks, see “Item 1A. Risk Factors” in our 2022 Form 10-K. We may experience additional risks and uncertainties not currently known to us. Further, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect us. Any such risks may materially and adversely affect our business, financial condition, cash flows, and results of operations.

Item 2: Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3: Defaults Upon Senior Securities

None.

Item 4: Mine Safety Disclosures

None.

Item 5: Other Information

During the quarter ended June 30, 2023, none of our directors or officers (as defined in Rule 16a-1(f) of the Exchange Act) adopted, terminated or modified a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K).

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Item 6: Exhibits

Incorporated by Reference

Exhibit
Number

Exhibit Description

Form

File No.

Exhibit

Filing Date

Filed
Here-with

Furnished
Herewith

31.1

Rule 13a-14(a) Certification by Chief Executive Officer

31.2

Rule 13a-14(a) Certification by Chief Financial Officer

32.1

Section 1350 Certification of Chief Executive Officer

32.2

Section 1350 Certification Chief Financial Officer

101.SCH

Inline XBRL Taxonomy Extension Schema Document

101.CAL

Inline XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF

Inline XBRL Taxonomy Extension Definition Linkbase Document

101.LAB

Inline XBRL Taxonomy Extension Label Linkbase Document

101.PRE

Inline XBRL Taxonomy Extension Presentation Linkbase Document

104

Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

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SIGNATURES

Pursuant to the requirements 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.

Date: August 3, 2023	By:	/s/ Paul D. McKinney
		Paul D. McKinney
		Chief Executive Officer
		(Principal Executive Officer)

Date: August 3, 2023	By:	/s/ Travis T. Thomas
		Travis T. Thomas
		Chief Financial Officer
		(Principal Financial and Accounting Officer)