rei-20240930

Table of Contents

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 September 30, 2024

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 November 6, 2024, the registrant had outstanding 198,196,034 shares of common stock ($0.001 par value).

Table of Contents

TABLE OF CONTENTS


PART I — FINANCIAL INFORMATION
	Item 1:	Condensed Financial Statements	5
		Notes to the Condensed Financial Statements	11
	Item 2:	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
	Item 3:	Quantitative and Qualitative Disclosures About Market Risk	47
	Item 4:	Controls and Procedures	48
PART II — OTHER INFORMATION
	Item 1:	Legal Proceedings	48
	Item 1A:	Risk Factors	48
	Item 2:	Unregistered Sales of Equity Securities and Use of Proceeds	49
	Item 3:	Defaults Upon Senior Securities	49
	Item 4:	Mine Safety Disclosures	49
	Item 5:	Other Information	49
	Item 6:	Exhibits	49
SIGNATURES			50

Table of Contents

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 net cash provided by operating activities, borrowings or other sources to enable us to fully develop and produce our oil and natural gas properties;

•general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business;

•risks associated with drilling of wells, including completion risks, cost overruns, mechanical failures and the drilling of non-economic wells or dry holes;

•uncertainties associated with estimates of proved oil and natural gas reserves;

•the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;

•the effects of inflation on our cost structure;

•substantial declines in the estimated values of our proved oil and natural gas reserves;

•our ability to replace our oil and natural gas reserves;

•the effects of rising interest rates on our cost of capital and the actions that central banks around the world undertake to control inflation, including the impacts such actions have on general economic conditions;

•unanticipated reductions in the borrowing base under our credit agreement;

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

•risks and liabilities associated with the acquisition and integration of companies and properties;

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

•geological concentration of our oil and natural gas reserves;

Table of Contents

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

•our dependence on the availability, use and disposal of water in our drilling, completion and production operations;

•significant competition for oil and natural gas acreage and acquisitions;

•environmental or other governmental regulations, including legislation related to hydraulic fracture stimulation and climate change measures;

•our ability to secure reliable transportation for oil and natural gas we produce and to sell the oil and natural gas at market prices;

•future 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 optimal goals;

•the occurrence of cybersecurity incidents, attacks or other breaches to our information technology systems or on

systems and infrastructure used by the oil and gas industry;

•our ability to find and retain highly skilled personnel and our ability to retain key members of our management team on commercially reasonable terms;

•adverse weather conditions;

•costs and liabilities associated with environmental, health, and safety laws;

•the effect of our oil and natural gas derivative activities;

•social unrest, political instability, or armed conflict in major oil and natural gas producing regions outside the United States, including evolving geopolitical and military hostilities in the Middle East, Russia, and Ukraine and acts of terrorism or sabotage;

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

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

•the other factors discussed in Part I, Item 1A-- “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2023, as well as in our condensed 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.

Table of Contents

PART I — FINANCIAL INFORMATION

Item 1. Condensed Financial Statements

The following (a) condensed balance sheet as of December 31, 2023 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 condensed 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.

Table of Contents

RING ENERGY, INC.

CONDENSED BALANCE SHEETS

(Unaudited)


	September 30, 2024		December 31, 2023
ASSETS
Current Assets
Cash and cash equivalents	$	—	$	296,384
Accounts receivable	36,394,451		38,965,002
Joint interest billing receivables, net	1,343,801		2,422,274
Derivative assets	8,375,984		6,215,374
Inventory	4,627,980		6,136,935
Prepaid expenses and other assets	2,076,896		1,874,850
Total Current Assets	52,819,112		55,910,819
Properties and Equipment
Oil and natural gas properties, full cost method	1,770,078,718		1,663,548,249
Financing lease asset subject to depreciation	4,192,099		3,896,316
Fixed assets subject to depreciation	3,389,907		3,228,793
Total Properties and Equipment	1,777,660,724		1,670,673,358
Accumulated depreciation, depletion and amortization	(450,913,685)		(377,252,572)
Net Properties and Equipment	1,326,747,039		1,293,420,786
Operating lease asset	2,057,096		2,499,592
Derivative assets	8,735,674		11,634,714
Deferred financing costs	9,406,089		13,030,481
Total Assets	$	1,399,765,010	$	1,376,496,392

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	90,143,131	$	104,064,124
Income tax liability	257,704		—
Financing lease liability	879,598		956,254
Operating lease liability	633,132		568,176
Derivative liabilities	3,929,188		7,520,336
Notes payable	912,819		533,734

Asset retirement obligations	836,421		165,642
Total Current Liabilities	97,591,993		113,808,266

Non-current Liabilities

Deferred income taxes	26,859,453		8,552,045
Revolving line of credit	392,000,000		425,000,000
Financing lease liability, less current portion	496,954		906,330
Operating lease liability, less current portion	1,574,117		2,054,041
Derivative liabilities	4,535,777		11,510,368
Asset retirement obligations	25,396,573		28,082,442
Total Liabilities	548,454,867		589,913,492
Commitments and contingencies (See Note 12)
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; 198,196,034 shares and 196,837,001 shares issued and outstanding, respectively	198,196		196,837
Additional paid-in capital	798,747,764		795,834,675
Retained earnings (Accumulated deficit)	52,364,183		(9,448,612)
Total Stockholders’ Equity	851,310,143		786,582,900
Total Liabilities and Stockholders' Equity	$	1,399,765,010	$	1,376,496,392

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

Table of Contents

RING ENERGY, INC.

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)


	For the Three Months Ended				For the Nine Months Ended
	September 30, 2024		September 30, 2023		September 30, 2024		September 30, 2023

Oil, Natural Gas, and Natural Gas Liquids Revenues	$	89,244,383	$	93,681,798	$	282,886,868	$	261,113,283

Costs and Operating Expenses
Lease operating expenses	20,315,282		18,015,348		57,984,733		51,426,145
Gathering, transportation and processing costs	102,420		(4,530)		376,103		(6,985)
Ad valorem taxes	2,164,562		1,779,163		5,647,469		5,120,119
Oil and natural gas production taxes	4,203,851		4,753,289		12,259,418		13,173,568
Depreciation, depletion and amortization	25,662,123		21,989,034		74,153,994		64,053,637
Asset retirement obligation accretion	354,195		354,175		1,057,213		1,073,900
Operating lease expense	175,091		138,220		525,272		366,711
General and administrative expense	6,421,567		7,083,574		21,604,323		21,023,956

Total Costs and Operating Expenses	59,399,091		54,108,273		173,608,525		156,231,051

Income from Operations	29,845,292		39,573,525		109,278,343		104,882,232

Other Income (Expense)
Interest income	143,704		80,426		367,181		160,171
Interest (expense)	(10,754,243)		(11,381,754)		(33,199,314)		(32,322,840)
Gain (loss) on derivative contracts	24,731,625		(39,222,755)		3,888,531		(26,483,190)
Gain (loss) on disposal of assets	—		—		89,693		(132,109)
Other income	—		—		25,686		126,210
Net Other Income (Expense)	14,121,086		(50,524,083)		(28,828,223)		(58,651,758)

Income (Loss) Before Benefit from (Provision for) Income Taxes	43,966,378		(10,950,558)		80,450,120		46,230,474

Benefit from (Provision for) Income Taxes	(10,087,954)		3,411,336		(18,637,325)		7,737,688
Net Income (Loss)	$	33,878,424	$	(7,539,222)	$	61,812,795	$	53,968,162

Basic Earnings (Loss) per Share	$	0.17	$	(0.04)	$	0.31	$	0.29
Diluted Earnings (Loss) per Share	$	0.17	$	(0.04)	$	0.31	$	0.28

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

Table of Contents

RING ENERGY, INC.

CONDENSED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Unaudited)


	Common Stock			Additional Paid-in Capital		Retained Earnings (Accumulated Deficit)		Total Stockholders' Equity
For the Nine Months Ended September 30, 2024	Shares	Amount
Balance, December 31, 2023	196,837,001	$	196,837	$	795,834,675	$	(9,448,612)	$	786,582,900



Restricted stock vested	1,342,112	1,342		(1,342)		—		—
Shares to cover tax withholdings for restricted stock vested	(244,911)	(245)		245		—		—
Payments to cover tax withholdings for restricted stock vested, net	—	—		(814,985)		—		(814,985)


Share-based compensation	—	—		1,723,832		—		1,723,832
Net income	—	—		—		5,515,377		5,515,377
Balance, March 31, 2024	197,934,202	$	197,934	$	796,742,425	$	(3,933,235)	$	793,007,124



Restricted stock vested	303,797	304		(304)		—		—
Shares to cover tax withholdings for restricted stock vested	(71,702)	(72)		72		—		—
Payments to cover tax withholdings for restricted stock vested, net	—	—		(86,991)		—		(86,991)


Share-based compensation	—	—		2,077,778		—		2,077,778
Net income	—	—		—		22,418,994		22,418,994
Balance, June 30, 2024	198,166,297	$	198,166	$	798,732,980	$	18,485,759	$	817,416,905



Restricted stock vested	39,442	39		(39)		—		—
Shares to cover tax withholdings for restricted stock vested	(9,705)	(9)		9		—		—
Payments to cover tax withholdings for restricted stock vested, net	—	—		(17,273)		—		(17,273)


Share-based compensation	—	—		32,087		—		32,087
Net income	—	—		—		33,878,424		33,878,424
Balance, September 30, 2024	198,196,034	$	198,196	$	798,747,764	$	52,364,183	$	851,310,143

For the Nine Months Ended September 30, 2023
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



Restricted stock vested	39,443	39		(39)		—		—
Shares to cover tax withholdings for restricted stock vested	(9,588)	(9)		9		—		—
Payments to cover tax withholdings for restricted stock vested, net	—	—		(18,302)		—		(18,302)


Share-based compensation	—	—		2,170,735		—		2,170,735
Net loss	—	—		—		(7,539,222)		(7,539,222)
Balance, September 30, 2023	195,380,527	$	195,380	$	793,603,238	$	(60,345,091)	$	733,453,527

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

Table of Contents

RING ENERGY, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)


	For the Nine Months Ended
	September 30, 2024		September 30, 2023
Cash Flows From Operating Activities
Net income	$	61,812,795	$	53,968,162
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	74,153,994		64,053,637
Asset retirement obligation accretion	1,057,213		1,073,900
Amortization of deferred financing costs	3,670,096		3,699,235
Share-based compensation	3,833,697		6,374,743
Bad debt expense	187,594		41,865
(Gain) loss on disposal of assets	(89,693)		—
Deferred income tax expense (benefit)	18,212,075		(8,160,712)
Excess tax expense (benefit) related to share-based compensation	95,333		158,763
(Gain) loss on derivative contracts	(3,888,531)		26,483,190
Cash received (paid) for derivative settlements, net	(5,938,777)		(5,829,728)
Changes in operating assets and liabilities:
Accounts receivable	3,245,030		(5,671,516)
Inventory	1,508,955		3,701,882
Prepaid expenses and other assets	(202,046)		68,525
Accounts payable	(9,538,827)		3,500,913
Settlement of asset retirement obligation	(974,877)		(1,025,607)
Net Cash Provided by Operating Activities	147,144,031		142,437,252
Cash Flows From Investing Activities
Payments for the Stronghold Acquisition	—		(18,511,170)
Payments for the Founders Acquisition	—		(49,902,757)
Payments to purchase oil and natural gas properties	(787,343)		(1,605,262)
Payments to develop oil and natural gas properties	(117,559,401)		(112,996,032)
Payments to acquire or improve fixed assets subject to depreciation	(185,524)		(209,798)
Proceeds from sale of fixed assets subject to depreciation	10,605		332,230
Proceeds from divestiture of equipment for oil and natural gas properties	—		54,558
Proceeds from sale of Delaware properties	—		7,608,692
Proceeds from sale of New Mexico properties	(144,398)		4,312,502
Proceeds from sale of CBP vertical wells	5,500,000		—
Net Cash Used in Investing Activities	(113,166,061)		(170,917,037)
Cash Flows From Financing Activities
Proceeds from revolving line of credit	108,000,000		179,000,000
Payments on revolving line of credit	(141,000,000)		(166,000,000)
Proceeds from issuance of common stock from warrant exercises	—		12,301,596

Payments for taxes withheld on vested restricted shares, net	(919,249)		(294,365)
Proceeds from notes payable	1,501,507		1,565,071
Payments on notes payable	(1,122,422)		(1,114,883)
Payment of deferred financing costs	(45,704)		—
Reduction of financing lease liabilities	(688,486)		(551,579)
Net Cash Used in Financing Activities	(34,274,354)		24,905,840
Net Increase (Decrease) in Cash	(296,384)		(3,573,945)
Cash at Beginning of Period	296,384		3,712,526
Cash at End of Period	$	—	$	138,581

Table of Contents

RING ENERGY, INC.

CONDENSED STATEMENTS OF CASH FLOWS (CONTINUED)

(Unaudited)


	For the Nine Months Ended
	September 30, 2024		September 30, 2023
Supplemental Cash Flow Information
Cash paid for interest	$	30,208,974	$	27,804,707
Cash paid for income taxes	72,213		—

Noncash Investing and Financing Activities
Asset retirement obligation incurred during development	$	505,721	$	261,786
Asset retirement obligation acquired	—		2,090,777
Asset retirement obligation revision of estimate	133,794		53,824
Asset retirement obligation sold	(3,219,651)		(4,717,507)
Operating lease assets obtained in exchange for new operating lease liability	—		1,713,677

Financing lease assets obtained in exchange for new financing lease liability	341,218		305,052

Change in capitalized expenditures attributable to drilling projects financed through current liabilities	(4,034,975)		(1,394,081)

Supplemental Schedule for Founders Acquisition
Investing Activities - Cash Paid
Escrow deposit released at closing	$	—	$	7,500,000
Closing amount paid to Founders	—		42,502,799
Interest from escrow deposit	—		1,747
Direct transaction costs	—		1,361,843
Post-close adjustments	—		(1,463,632)
Payments for the Founders Acquisition	$	—	$	49,902,757
Investing Activities - Noncash
Assumption of suspense liability	$	—	$	677,116
Assumption of asset retirement obligation	—		2,090,777
Assumption of ad valorem tax liability	—		234,051
Deferred cash payment at fair value	—		14,657,383

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.

Table of Contents

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 and Divestitures			Note 12 — Commitments and Contingencies
Note 6 — Derivative Financial Instruments			Note 13 — Subsequent Events
Note 7 — Fair Value Measurements

NOTE 1 — BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

Condensed Financial Statements – The accompanying condensed financial statements prepared by Ring Energy, Inc., a Nevada corporation (the “Company,” "Ring Energy," “Ring,” "we," "us," or "our"), have not been audited by an independent registered public accounting firm. In the opinion of the Company’s management, the accompanying unaudited condensed 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 nine months ended September 30, 2024 are not necessarily indicative of the results to be expected for the full year ending December 31, 2024, 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 condensed 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, 2023.

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 the Permian Basin of Texas. Our drilling operations target the oil and liquids rich producing formations in the Northwest Shelf and the Central Basin Platform in the Permian Basin of Texas.

Liquidity and Capital Considerations – The Company strives to maintain an adequate liquidity level to address volatility and risk. Sources of liquidity include the Company’s net cash provided by operating activities, cash on hand, available borrowing capacity under its revolving credit facility, and proceeds from sales of non-strategic assets.

While changes in oil and natural gas prices affect the Company’s liquidity, the Company has put in place hedges in seeking to protect a substantial portion of its cash flows from price declines; however, if oil or natural gas prices rapidly deteriorate due to unanticipated economic conditions, this could still have a material adverse effect on the Company’s cash flows.

The Company expects ongoing oil price volatility over an indeterminate term. Extended depressed oil prices have historically had and could have a material adverse impact on the Company’s oil revenue, which is mitigated to some extent by the Company’s hedge contracts.

The Company believes that it has the ability to continue to fund its operations and service its debt by using cash flows from operations.

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

Table of Contents

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 our revolving line of credit approximate their fair value because the underlying instruments are at interest rates which approximate current market rates. The carrying amounts of accounts receivable and accounts payable and other current assets and liabilities approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities.

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

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" below for additional information.

The Company uses the indirect method of reporting operating cash flows within the Condensed Statements of Cash Flows. Accordingly, the non-cash, unrealized gains and losses from derivative contracts are reflected as an adjustment to arrive at Net cash provided by operating activities. The total Gain (loss) on derivative contracts less the Cash received (paid) for derivative settlements, net represents the unrealized (mark to market) gain or loss on derivative contracts.

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 $0 and $46,384 as of September 30, 2024 and December 31, 2023, respectively. The Company places its cash with a high credit quality financial institution. The Company has not experienced any losses in such accounts and believes it is not exposed to significant credit risk in this area.

Accounts receivable - Substantially all of the Company’s accounts receivable is from purchasers of oil and natural gas. Oil and natural gas sales are generally unsecured. Accounts receivable from purchasers outstanding longer than the contractual

Table of Contents

payment terms are considered past due. The Company has not had any significant credit losses in the past and believes its accounts receivable are fully collectable. During the nine months ended September 30, 2024, sales to three purchasers represented 61%, 14% and 13%, respectively, of total oil, natural gas, and natural gas liquids sales. As of September 30, 2024, receivables outstanding from these three purchasers represented 69%, 11% and 13%, respectively, of accounts receivable.

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 September 30, 2024 or December 31, 2023.

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. Receivables from joint interest owners outstanding longer than the contractual payment terms are considered past due. The following table indicates the Company's provisions for bad debt expense associated with its joint interest billing receivables during the three and nine months ended September 30, 2024 and September 30, 2023.


	For the Three Months Ended				For the Nine Months Ended
	September 30, 2024		September 30, 2023		September 30, 2024		September 30, 2023
Bad debt expense	$	8,817	$	19,656	$	187,594	$	41,865

The following table reflects the Company's joint interest billing receivables and allowance for credit losses as of September 30, 2024 and December 31, 2023.


	September 30, 2024		December 31, 2023
Joint interest billing receivables	$	1,552,281	$	2,480,843
Allowance for credit losses	(208,480)		(58,569)
Joint interest billing receivables, net	$	1,343,801	$	2,422,274

The increase of $149,911 in the allowance for credit losses during the nine months ended September 30, 2024 was primarily due to property sales and owner settlements.

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 September 30, 2024 and December 31, 2023, the Company had no such investments.

Inventory - The full balance of the Company's inventory consists of materials and supplies for its operations, with no work in process or finished goods inventory balances. Inventory is added to the books upon the purchase of supplies (inclusive of freight and sales tax costs) to use on well sites, and inventory is reduced by material transfers for inventory usage based on the initial invoiced value. The Company reports the balance of its inventory at the lower of cost or net realizable value. Inventory balances are excluded from the Company's calculation of depletion.

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

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

Table of Contents

All capitalized costs of oil and natural gas properties, including the estimated future costs to develop proved reserves and estimated future costs to plug and abandon wells and costs of site restoration, less the estimated salvage value of equipment associated with the oil and natural gas properties, are amortized on the unit-of-production method using estimates of proved reserves as determined by independent petroleum engineers. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is offset to the capitalized costs to be amortized. The following table shows total depletion and the depletion per barrel-of-oil-equivalent rate, for the three and nine months ended September 30, 2024 and 2023.


	For the Three Months Ended				For the Nine Months Ended
	September 30, 2024		September 30, 2023		September 30, 2024		September 30, 2023
Depletion	$	25,302,058	$	21,711,123	$	73,056,856	$	63,203,473
Depletion rate, per barrel-of-oil-equivalent (Boe)	$	13.68	$	13.48	$	13.57	$	13.09

In addition, capitalized costs less accumulated depletion 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.

No impairments on oil and natural gas properties as a result of the ceiling test were recorded for the three and nine months ended September 30, 2024 and 2023.

Land, Buildings, Equipment, Software, Leasehold Improvements, Automobiles, Buildings and Structures – Land, buildings, equipment, software, leasehold improvements, automobiles, buildings and structures are carried at historical cost, adjusted for impairment loss and accumulated depreciation (except for land). Historical costs include all direct costs associated with the acquisition of land, buildings, equipment, software, leasehold improvements, automobiles, buildings and structures and placing them in service. Upon sale or abandonment, the cost of the fixed asset(s) and related accumulated depreciation are removed from the accounts and any gain or loss is recognized.

Depreciation of buildings, equipment, software, leasehold improvements, automobiles, buildings and structures is calculated using the straight-line method based upon the following estimated useful lives:


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

The following table provides information on the Company's depreciation expense for the three and nine months ended September 30, 2024 and 2023.


	For the Three Months Ended				For the Nine Months Ended
	September 30, 2024		September 30, 2023		September 30, 2024		September 30, 2023
Depreciation	$	102,043	$	80,690	$	306,752	$	277,420

Notes Payable – At the end of May 2023, the Company renewed its control of well, general liability, pollution, umbrella, property, workers' compensation, auto, and D&O (directors and officers) insurance policies, and funded the premiums with a promissory note with a total face value after down payments of $1,565,071. In November 2023, the Company renewed its cybersecurity insurance policy, and funded the premium with a promissory note with a total face value after down

Table of Contents

payments of $72,442. The annual percentage rate (APR) for both notes was 7.08%. At the end of May 2024, the Company renewed its control of well, general liability, pollution, umbrella, property, workers' compensation, auto, and D&O insurance policies, funding the premiums with a promissory note with a face value after down payments of $1,501,507. The APR for this note is 7.98%. As of September 30, 2024 and December 31, 2023, the notes payable balances included in current liabilities on the Condensed Balance Sheet were $912,819 and $533,734, respectively.

The following table reflects the weighted average notes payable balances and the weighted average interest rate on the weighted average notes payable outstanding during the period as of and for the three and nine months ended September 30, 2024 and 2023.


	Three Months Ended						Nine Months Ended
	September 30, 2024			September 30, 2023			September 30, 2024			September 30, 2023
Weighted average notes payable balance	$	1,181,511		$	1,228,923		$	616,090		$	651,564
Weighted average interest rate on weighted average notes payable	8.16		%	7.25		%	8.76		%	7.21		%

The following table shows interest paid related to notes payable for the three and nine months ended September 30, 2024 and 2023. This interest is included within "Interest (expense)" in the Condensed Statements of Operations.


	Three Months Ended				Nine Months Ended
	September 30, 2024		September 30, 2023		September 30, 2024		September 30, 2023
Interest paid for notes payable	$	24,115	$	22,286	$	40,481	$	35,211

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

Income Taxes – Provisions for income taxes are based on taxes payable or refundable for the current year and deferred taxes. Deferred income taxes are provided on differences between the tax basis of assets and liabilities and their carrying amounts in the condensed financial statements, and tax carryforwards. Deferred tax assets and liabilities are included in the condensed 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.

In assessing the Company’s deferred tax assets, we consider whether a valuation allowance should be recorded for some or all of the deferred tax assets which may not be realized. The ultimate realization of deferred tax assets is assessed at each reporting period and is dependent upon the generation of future taxable income and the Company’s ability to utilize operation loss carryforwards during the periods in which the temporary differences become deductible. We also consider the reversal of deferred tax liabilities and available tax planning strategies. As of September 30, 2024 and December 31, 2023, the Company did not carry a valuation allowance against its federal and state deferred tax assets.

The Company recorded the following federal and state income tax benefits (provisions) for the three and nine months ended September 30, 2024 and 2023.

Table of Contents


	For the Three Months Ended				For the Nine Months Ended
	September 30, 2024		September 30, 2023		September 30, 2024		September 30, 2023
Deferred federal income tax benefit (provision)	$	(9,637,849)	$	3,381,104	$	(17,617,436)	$	8,492,595
Current state income tax benefit (provision)	(74,899)		(165,780)		(329,917)		(264,261)
Deferred state income tax benefit (provision)	(375,206)		196,012		(689,972)		(490,646)
Benefit from (Provision for) Income Taxes	$	(10,087,954)	$	3,411,336	$	(18,637,325)	$	7,737,688

Effective tax rate (1)	22.94%		31.15%		23.17%		16.74%

(1) The Company’s overall effective tax rate is calculated as Benefit from (Provision for) Income Taxes divided by Income Before Benefit from (Provision for) Income Taxes. The effective tax rate for the three and nine months ended September 30, 2024 was higher than the federal statutory corporate tax rate primarily due to nondeductible expenses and state income taxes. For the three and nine months ended September 30, 2023, the Company's overall effective tax rates were primarily impacted by the release of valuation allowance on its federal net deferred tax asset. A tax benefit of $10.5 million was recorded as a discrete item in the nine months ended September 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 a “major” tax jurisdiction. The Company’s federal income tax returns for the years ended December 31, 2019 and after remain subject to examination. The Company’s federal income tax returns for the years ended December 31, 2007 and after remain subject to examination to the extent of the net operating loss (NOL) carryforwards. The Company’s franchise tax returns in Texas remain subject to examination for 2018 and after. The Company currently believes that all significant filing positions are highly certain and that all of its significant income tax filing positions and deductions would be sustained upon audit. Therefore, the Company has no significant reserves for uncertain tax positions and no adjustments to such reserves were required by GAAP. No interest or penalties have been levied against the Company and none are anticipated; therefore, no interest or penalty has been included in our provision for income taxes in the Condensed Statements of Operations.

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, restricted stock unit awards, and performance stock unit awards to directors, officers and employees, which are described more fully below 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.

Table of Contents

Share-Based Compensation - 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 nine months ended September 30, 2024 and 2023.


	Three Months Ended				Nine Months Ended
	September 30, 2024		September 30, 2023		September 30, 2024		September 30, 2023
Share-based compensation	$	32,087	$	2,170,735	$	3,833,697	$	6,374,743

Recently Adopted Accounting Pronouncements – In October 2021, the FASB issued ASU 2021-08, "Business Combinations (Topic 805) – Accounting for Contract Assets and Contract Liabilities from Contracts with Customers” ("ASU 2021-08"). This update requires the acquirer in a business combination to record contract asset and liabilities following Topic 606 – “Revenue from Contracts with Customers” at acquisition as if it had originated the contract, rather than at fair value. This update became effective for public business entities beginning after December 15, 2022. The Company adopted ASU 2021-08 effective January 1, 2023. The adoption and implementation of this ASU did not have a material impact on the Company’s financial statements, as its revenue is recognized when control transfers to the purchaser at the point of delivery, and no contract liabilities or assets are recognized in accordance with Accounting Standards Codification ("ASC") 606.

In July 2023, the FASB issued ASU 2023-03, Presentation of Financial Statements (Topic 205), Income Statement - Reporting Comprehensive Income (Topic 220), Distinguishing Liabilities from Equity (Topic 480), Equity (Topic 505), and Compensation - Stock Compensation (Topic 718): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 120, SEC Staff Announcement at the March 24, 2022 EITF Meeting, and Staff Accounting Bulletin Topic 6.B, Accounting Series Release 280 - General Revision of Regulation S-X: Income or Loss Applicable to Common Stock. The ASU provided updated views from the SEC Staff on employee and non-employee share-based payment accounting, including guidance related to spring-loaded awards. As the ASU did not provide any new ASC guidance, and there was no transition or effective date provided, the Company adopted this standard upon issuance, and the adoption did not have a material impact on the Company's condensed financial statements.

Recent Accounting Pronouncements – In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”), which provided optional expedients and exceptions for applying GAAP to contract modifications and hedging relationships, subject to meeting certain criteria, that referenced LIBOR ("London Inter-Bank Offered Rate") or another rate. ASU 2020-04 was in effect through December 31, 2022. In January 2021, the FASB issued ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), to provide clarifying guidance regarding the scope of Topic 848. ASU 2020-04 was issued to provide optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the 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 Credit Agreement, 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 2023, the FASB issued ASU 2023-06, "Disclosure Improvements: Codification Amendments in Response to the SEC's Disclosure Update and Simplification Initiative." This update modifies the disclosure or presentation requirements of a variety of Topics in the Codification, which should be applied prospectively. For instance, within ASC 230-10 Statement of Cash Flows - Overall, the amendment requires an accounting policy disclosure in annual periods of where cash flows associated with their derivative instruments and their related gains and losses are presented in the statement of cash flows. Additionally, within ASC 260-10 Earnings Per Share - Overall, the amendment requires disclosure of the methods used in the diluted earnings-per-share computation for each dilutive security and clarifies that certain disclosures should be made during interim periods. The Company is currently assessing the impact of this update on its financial statements and related notes. If by June 30, 2027, the SEC has not removed the applicable requirement from Regulation S-X or Regulation S-K, the pending content of the related amendment will be removed from the Codification and will not become effective for any entity.

In November 2023, the FASB issued ASU 2023-07 "Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures." This update requires that a public entity with multiple reportable segments disclose significant segment expenses that are regularly provided to the chief operating decision maker ("CODM"), as well as other segment

Table of Contents

items that are included in the calculation of segment profit or loss. A public entity will also be required to disclose all annual disclosures about a reportable segment's profit or loss currently required by Topic 280 in interim periods. Although a public entity is permitted to disclose multiple measures of a segment's profit or loss, at least one of the reported segment profit or loss measures should be consistent with the measurement principles used in measuring the corresponding amounts of the public entity's consolidated financial statements. Further, a public entity must disclose the title and position of the CODM as well as how the CODM uses the reported measure(s) of segment profit or loss in assessing segment performance and deciding how to allocate resources. Finally, the update requires that a public entity that has a single reportable segment provide all the disclosures required by the amendments in this update and all existing segment disclosures in Topic 280. The Company is currently assessing the impact of adopting this new guidance on its financial disclosures. The amendments in this update are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024.

In December 2023, the FASB issued ASU 2023-09 "Income Taxes (Topic 740): Improvements to Income Tax Disclosures." The amendments from this update provide for more transparency about income tax information through improvements to income tax disclosures primarily related to the rate reconciliation and income taxes paid information. Specifically, public business entities are required to disclose a tabular reconciliation, using both percentages and reporting currency amounts, showing detail from eight specific categories: (a) state and local income tax net of federal (national) income tax effect, (b) foreign tax effects, (c) effect of changes in tax laws or rates enacted in the current period, (d) effect of cross-border tax laws, (e) tax credits, (f) changes in valuation allowances, (g) nontaxable or nondeductible items, and (h) changes in unrecognized tax benefits. In addition, public business entities are required to separately disclose any reconciling item, disaggregated by nature and/or jurisdiction, in which the effect of the reconciling item is equal to or greater than five percent of the amount computed by multiplying the income (or loss) from continuing operations before income taxes by the applicable statutory income tax rate. Also, for the state and local category, a public business entity is required to provide a qualitative description of the states and local jurisdictions that make up the majority (greater than 50 percent) of the category. Further, the amount of income taxes paid (net of refunds received) are required to be disaggregated by (i) federal (national), state, and foreign taxes, and (ii) by individual jurisdictions in which income taxes paid (net of refunds received) is equal to or greater than five percent of total income taxes paid (net of refunds received). Finally, the amendments from this update require that all entities disclose (i) income (or loss) from continuing operations before income tax expense (or benefit) disaggregated between domestic and foreign and (ii) income tax expense (or benefit) from continuing operations disaggregated by federal, state, and foreign. The Company is currently assessing the impact of adopting this new guidance on its financial disclosures. For public business entities, the amendments in this update are effective for annual periods beginning after December 15, 2024.

In March 2024, the FASB issued ASU 2024-02 "Codification Improvements - Amendments to Remove References to the Concepts Statements" ("ASU 2024-02"), which contains amendments to the Codification to remove references to various FASB Concepts Statements. In most instances, the references are extraneous and not required to understand or apply the guidance. Generally, ASU 2024-02 is not intended to result in significant accounting changes for most entities. ASU 2024-02 is effective for the Company for fiscal years beginning after December 15, 2024. The Company does not expect this update to have a material impact on its condensed financial statements.

NOTE 2 — REVENUE RECOGNITION

The Company predominantly derives its revenue from the sale of produced crude oil, natural gas, and NGLs. The contractual performance obligation is satisfied when the product is delivered to the purchaser. Revenue is recorded in the 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 ASC 606-10-50-14, which states an entity is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company’s sales contracts, each unit of production delivered to a purchaser represents a separate performance obligation, therefore, future volumes to be delivered are wholly unsatisfied and disclosure of transaction price allocated to remaining performance obligation is not required. The transaction price includes variable consideration, as product pricing is based on published market prices and adjusted for contract specified differentials such as quality, energy content and transportation. The guidance does not require that the transaction price be fixed or stated in the contract. Estimating the variable consideration does not require significant judgment and the

Table of Contents

Company engages third party sources to validate the estimates. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration the Company expects to receive in exchange for those products.

Oil sales

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

Natural gas and NGL sales

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

Until April 30, 2022, under the Company's natural gas sales processing contracts for the bulk of our Northwest Shelf assets, the Company delivered unprocessed natural gas to a midstream processing entity at the wellhead. However, the Company maintained ownership of the gas through processing and received proceeds from the marketing of the resulting products. Under this processing agreement, the Company recognized the fees associated with the processing as an expense rather than netting these costs against Oil, 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. There remains only one contract with a natural gas processing entity in place where point of control of gas dictates requiring the fees be recorded as an expense.

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


	For the Three Months Ended				For the Nine Months Ended
	September 30, 2024		September 30, 2023		September 30, 2024		September 30, 2023
Oil, Natural Gas, and Natural Gas Liquids Revenues
Oil	$	90,416,363	$	90,392,004	$	282,000,446	$	252,020,403
Natural gas	(3,859,603)		562,374		(7,650,645)		526,161
Natural gas liquids	2,687,623		2,727,420		8,537,067		8,566,719
Total oil, natural gas, and natural gas liquids revenues	$	89,244,383	$	93,681,798	$	282,886,868	$	261,113,283

NOTE 3 — LEASES

The Company has operating leases for its offices in Midland, Texas and The Woodlands, Texas. The Midland office is under a five-year lease which began January 1, 2021. The Midland office lease was amended effective October 1, 2022, with the revised five-year lease ending September 30, 2027. Beginning January 15, 2021, the Company entered into a five-and-a-half-year sub-lease for office space in The Woodlands, Texas; however, effective as of May 31, 2023, The Woodlands office sub-lease was terminated. On May 9, 2023, the Company entered into a 71-month (five years and 11-month) new lease for a larger amount of office space in The Woodlands, Texas. At the time of the new lease commencement, the additional office space that was added was under construction and until completed, the rental obligation for this space had not yet commenced, because the Company did not have control of the additional office space in accordance with ASC 842-40-55-5. On September 27, 2023, the Company provided a certificate of acceptance of premises to the lessor of the additional office space, and accordingly, the future payments for this space are included along with the other operating leases, reflected in the future lease payments schedule below.

Table of Contents

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

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

Future lease payments associated with these operating and financing leases as of September 30, 2024 are as follows:


	2024		2025		2026		2027		2028		Other Future Years
Operating lease payments (1)	$	177,466	$	727,460	$	636,649	$	460,497	$	250,606	$	149,628
Financing lease payments (2)	255,854		821,792		367,872		23,914		—		—

(1)The weighted average annual discount rate as of September 30, 2024 for operating leases was 4.50%. Based on this rate, the future lease payments above include imputed interest of $195,057. The weighted average remaining term of operating leases was 3.66 years.

(2)The weighted average annual discount rate as of September 30, 2024 for financing leases was 7.15%. Based on this rate, the future lease payments above include imputed interest of $92,880. The weighted average remaining term of financing leases was 1.75 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:

Table of Contents


	As of
	September 30, 2024		December 31, 2023
Operating lease liability, current portion	$	633,132	$	568,176
Operating lease liability, non-current portion	1,574,117		2,054,041
Operating lease liability, total	$	2,207,249	$	2,622,217
Total undiscounted future cash flows (sum of future operating lease payments)	2,402,306		2,900,050
Imputed interest	195,057		277,833
Undiscounted future cash flows less imputed interest	$	2,207,249	$	2,622,217

Financing lease liability, current portion	$	879,598	$	956,254
Financing lease liability, non-current portion	496,954		906,330
Financing lease liability, total	$	1,376,552	$	1,862,584
Total undiscounted future cash flows (sum of future financing lease payments)	1,469,432		2,006,453
Imputed interest	92,880		143,869
Undiscounted future cash flows less imputed interest	$	1,376,552	$	1,862,584

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


	For the Three Months Ended				For the Nine Months Ended
	September 30, 2024		September 30, 2023		September 30, 2024		September 30, 2023
Operating lease costs	$	175,091	$	138,220	$	525,272	$	366,711
Short-term lease costs (1)	1,225,729		1,012,525		3,311,077		4,042,160
Financing lease costs:
Amortization of financing lease assets (2)	258,022		197,221		790,386		572,744
Interest on financing lease liabilities (3)	27,224		23,416		89,963		73,115

(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 nine months ended September 30, 2024 and 2023. For all dilutive securities, the treasury stock method of calculating the incremental shares is applied.


	For the Three Months Ended				For the Nine Months Ended
	September 30, 2024		September 30, 2023		September 30, 2024		September 30, 2023
Net Income (Loss)	$	33,878,424	$	(7,539,222)	$	61,812,795	$	53,968,162
Basic Weighted-Average Shares Outstanding	198,177,046		195,361,476		197,850,538		188,865,752
Effect of dilutive securities:
Stock options	—		—		—		—
Restricted stock units	1,905,628		—		1,628,164		1,310,409
Performance stock units	597,939		—		619,555		361,406
Common warrants	43,250		—		41,221		4,045,648

Diluted Weighted-Average Shares Outstanding	200,723,863		195,361,476		200,139,478		194,583,215
Basic Earnings (Loss) per Share	$	0.17	$	(0.04)	$	0.31	$	0.29
Diluted Earnings (Loss) per Share	$	0.17	$	(0.04)	$	0.31	$	0.28

Table of Contents

The following table presents the securities which were excluded from the Company's computation of diluted earnings per share for the three and nine months ended September 30, 2024 and 2023, as their effect would have been anti-dilutive.


	For the Three Months Ended		For the Nine Months Ended
	September 30, 2024	September 30, 2023	September 30, 2024	September 30, 2023
Antidilutive securities:
Stock options to purchase common stock	65,500	265,500	66,850	265,500
Unvested restricted stock units	51,622	3,866,023	56,530	61,212
Unvested performance stock units	516,450	2,882,594	1,198,361	1,396,446

NOTE 5 — ACQUISITIONS AND DIVESTITURES

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 “Stronghold Purchase Agreement”). Pursuant to the Stronghold Purchase Agreement, Ring acquired (the “Stronghold Acquisition”) interests in oil and gas leases and related property of Stronghold consisting of approximately 37,000 net acres located in the Central Basin Platform of the Texas Permian Basin. On August 31, 2022, Ring completed the Stronghold Acquisition.

The fair value of consideration paid to Stronghold was approximately $394.0 million, of which $165.9 million, net of customary purchase price adjustments, was paid in cash at closing, $15.0 million was paid in cash on the sixth-month anniversary of the closing date. Shortly after closing, approximately $4.5 million was paid for inventory and vehicles and approximately $1.8 million was paid for August oil derivative settlements for certain novated hedges. The cash portion of the consideration was funded primarily from borrowings under a new fully committed revolving credit facility (the "Credit Facility,") underwritten by Truist Securities, Citizens Bank, N.A., KeyBanc Capital Markets, Inc., and Mizuho Bank, Ltd. The borrowing base of the $1.0 billion Credit Facility was increased from $350 million to $600 million at the closing of the Stronghold Acquisition. The remaining consideration consisted of 21,339,986 shares of common stock and 153,176 shares of newly created Series A Convertible Preferred Stock, par value $0.001 (“Preferred Stock”), which was converted into 42,548,892 shares of common stock on October 27, 2022. In addition, Ring assumed $24.8 million of derivative liabilities, $1.7 million of items in suspense, and $14.5 million in asset retirement obligations.

Delaware Basin Divestiture

On May 11, 2023, the Company completed the divestiture of its Delaware Basin assets to an unaffiliated party for $8.3 million. The sale had an effective date of March 1, 2023. The final cash consideration was approximately $7.6 million. As part of the divestiture, the buyer assumed an asset retirement obligation balance of approximately $2.3 million.

Founders Acquisition

On July 10, 2023, the Company, as buyer, and Founders Oil & Gas IV, LLC (“Founders”), as seller, entered into an Asset Purchase Agreement (the “Founders Purchase Agreement”). Pursuant to the closing of the Purchase Agreement, on August 15, 2023 the Company acquired (the “Founders Acquisition”) interests in oil and gas leases and related property of Founders located in the Central Basin Platform of the Texas Permian Basin in Ector County, Texas, for a purchase price (the “Purchase Price”) of (i) a cash deposit of $7.5 million paid on July 11, 2023 into a third-party escrow account as a deposit pursuant to the Founders Purchase Agreement, (ii) approximately $42.5 million in cash paid on the closing date, net of approximately $10 million of preliminary and customary purchase price adjustments with an effective date of April 1, 2023, and (iii) a deferred cash payment of $11.9 million paid on December 18, 2023, net of customary purchase price adjustments.

The Founders Acquisition was accounted for as an asset acquisition in accordance with ASC 805. The fair value of the consideration paid by Ring and allocation of that amount to the underlying assets acquired, on a relative fair value basis, was recorded on Ring’s books as of the date of the closing of the Founders Acquisition. Additionally, costs directly related to the Founders Acquisition were capitalized as a component of the purchase price. Determining the fair value of the assets and liabilities acquired required judgment and certain assumptions to be made, the most significant of these being related to

Table of Contents

the valuation of Founder’s oil and gas properties. The inputs and assumptions related to the oil and gas properties were categorized as level 3 in the fair value hierarchy.

The following table represents the final allocation of the total cost of the Founders Acquisition to the assets acquired and liabilities assumed as of the Founders Acquisition date:


Consideration:
Cash consideration
Escrow deposit released at closing	$	7,500,000
Closing amount paid to Founders	42,502,799
Interest from escrow deposit	1,747
Fair value of deferred payment liability	14,657,383
Post-close adjustments	(4,139,244)
Total cash consideration	$	60,522,685
Direct transaction costs	1,361,843
Total consideration	$	61,884,528

Fair value of assets acquired:
Oil and natural gas properties	$	64,886,472

Amount attributable to assets acquired	$	64,886,472
Fair value of liabilities assumed:
Suspense liability	$	677,116
Asset retirement obligations	2,090,777
Ad valorem tax liability	234,051
Amount attributable to liabilities assumed	$	3,001,944
Net assets acquired	$	61,884,528

New Mexico Divestiture

On September 27, 2023, the Company completed the divestiture of its operated New Mexico assets to an unaffiliated party for $4.5 million, resulting in cash consideration of approximately $3.6 million. The sale had an effective date of June 1, 2023. As part of the divestiture, the buyer assumed an asset retirement obligation balance of approximately $2.4 million.

Gaines County Texas Sale

On December 29, 2023, the Company completed the sale of certain oil and gas properties in Gaines County, Texas to an unaffiliated party for $1.5 million, which resulted in cash proceeds of $1.4 million, net of $0.1 million in sales fees. The sale had an effective date of December 1, 2023. As part of the sale, the buyer assumed an asset retirement obligation balance of approximately $0.5 million.

CBP Vertical Well Sale

On September 30, 2024, the Company completed the sale of certain oil and gas properties, including vertical wells and associated facilities, within Andrews County, Texas and Gaines County, Texas to an unaffiliated party for $5.5 million. As part of the sale, the buyer assumed an asset retirement obligation balance of approximately $2.7 million.

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. A deferred premium put contract has the premium established upon entering the contract, and due upon settlement of the contract.

The use of derivative transactions involves the risk that the counterparties, which generally are financial institutions, will be unable to meet the financial terms of such transactions. All of our derivative contracts are with lenders under our Credit Facility. Non-performance risk is incorporated in the discount rate by adding the quoted bank (counterparty) credit default swap (CDS) rates to the risk free rate. Although the counterparties hold the right to offset (i.e. netting) the settlement amounts with the Company, in accordance with ASC 815-10-50-4B, the Company classifies the fair value of all its derivative positions on a gross basis in the Company's 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" 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
	September 30, 2024		December 31, 2023
Commodity derivative instruments, marked to market:

Derivative assets, current	$	8,605,087	$	7,768,697
Discounted deferred premiums	(229,103)		(1,553,323)
Derivatives assets, current, net of premiums	$	8,375,984	$	6,215,374



Derivative assets, noncurrent	$	8,735,674	$	11,634,714

Derivative liabilities, current	$	3,929,188	$	7,520,336

Derivative liabilities, noncurrent	$	4,535,777	$	11,510,368

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 Nine Months Ended
	September 30, 2024		September 30, 2023		September 30, 2024		September 30, 2023
Oil derivatives:
Realized gain (loss) on oil derivatives	$	(3,109,660)	$	(5,825,427)	$	(9,921,757)	$	(7,323,030)
Unrealized gain (loss) on oil derivatives	27,238,245		(34,077,473)		12,552,517		(21,425,316)
Gain (loss) on oil derivatives	$	24,128,585	$	(39,902,900)	$	2,630,760	$	(28,748,346)

Natural gas derivatives:
Realized gain (loss) on natural gas derivatives	1,226,895		474,629		$	3,982,980	$	1,493,302
Unrealized gain (loss) on natural gas derivatives	(623,855)		205,516		(2,725,209)		771,854
Gain (loss) on natural gas derivatives	$	603,040	$	680,145	$	1,257,771	$	2,265,156

Gain (loss) on derivative contracts	$	24,731,625	$	(39,222,755)	$	3,888,531	$	(26,483,190)

The components of “Cash received (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 Nine Months Ended
	September 30, 2024		September 30, 2023		September 30, 2024		September 30, 2023
Cash flows from operating activities
Cash received (paid) for oil derivatives	$	(3,109,660)	$	(5,825,427)	$	(9,921,757)	$	(7,323,030)
Cash received (paid) for natural gas derivatives	1,226,895		474,629		3,982,980		1,493,302
Cash received (paid) for derivative settlements, net	$	(1,882,765)	$	(5,350,798)	$	(5,938,777)	$	(5,829,728)

The following tables reflect the details of current derivative contracts as of September 30, 2024 (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)
	Q4 2024		Q1 2025		Q2 2025		Q3 2025		Q4 2025		Q1 2026		Q2 2026		Q3 2026

Swaps:
Hedged volume (Bbl)	368,000		71,897		52,063		265,517		64,555		449,350		432,701		—
Weighted average swap price	$	68.43	$	72.03	$	72.03	$	72.94	$	72.03	$	70.38	$	69.53	$	—

Deferred premium puts:
Hedged volume (Bbl)	88,405		—		—		—		—		—		—		—
Weighted average strike price	$	75.00	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Weighted average deferred premium price	$	2.61	$	—	$	—	$	—	$	—	$	—	$	—	$	—

Two-way collars:
Hedged volume (Bbl)	128,800		474,750		464,100		225,400		404,800		—		—		379,685
Weighted average put price	$	60.00	$	57.06	$	60.00	$	65.00	$	60.00	$	—	$	—	$	60.00
Weighted average call price	$	73.24	$	75.82	$	69.85	$	78.91	$	75.68	$	—	$	—	$	72.50


	Gas Hedges (Henry Hub)
	Q4 2024		Q1 2025		Q2 2025		Q3 2025		Q4 2025		Q1 2026		Q2 2026		Q3 2026

NYMEX Swaps:
Hedged volume (MMBtu)	431,800		616,199		594,400		289,550		—		—		532,500		—
Weighted average swap price	$	4.44	$	3.78	$	3.43	$	3.72	$	—	$	—	$	3.38	$	—

Two-way collars:
Hedged volume (MMBtu)	18,300		33,401		27,300		308,200		598,000		553,500		—		515,728
Weighted average put price	$	3.00	$	3.00	$	3.00	$	3.00	$	3.00	$	3.50	$	—	$	3.00

Weighted average call price	$	4.15	$	4.39	$	4.15	$	4.75	$	4.15	$	5.03	$	—	$	3.93


	Oil Hedges (basis differential)
	Q4 2024		Q1 2025		Q2 2025		Q3 2025		Q4 2025		Q1 2026		Q2 2026		Q3 2026

Argus basis swaps:
Hedged volume (Bbl)	244,000		270,000		273,000		276,000		276,000		—		—		—
Weighted average spread price (1)	$	1.15	$	1.00	$	1.00	$	1.00	$	1.00	$	—	$	—	$	—

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

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.

Table of Contents

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.

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, 2023

Commodity Derivatives - Assets	$	—	$	17,850,088	$	—	$	17,850,088
Commodity Derivatives - Liabilities	$	—	$	(19,030,704)	$	—	$	(19,030,704)

Total	$	—	$	(1,180,616)	$	—	$	(1,180,616)

As of September 30, 2024

Commodity Derivatives - Assets	$	—	$	17,111,658	$	—	$	17,111,658
Commodity Derivatives - Liabilities	$	—	$	(8,464,965)	$	—	$	(8,464,965)

Total	$	—	$	8,646,693	$	—	$	8,646,693

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 Bank), 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 “Amended Credit Facility”).

On August 31, 2022, the Company modified its Amended Credit Facility through that certain Second Amended and Restated Credit Agreement (the "Second Credit Agreement"), extending the maturity date of the facility to August 2026 and the syndicate was modified to add five lenders, replacing five lenders. On February 12, 2024, the Company, Truist Bank as the Administrative Agent and Issuing Bank, and the lenders party thereto (the "Lenders") entered into an amendment (the "Amendment") to the Second Credit Agreement. Among other things, the Amendment amends the definition of Free Cash Flow so amounts used by the Company for acquisitions will no longer be subtracted from the calculation of Free Cash Flow.

The Second Credit Agreement has a borrowing base of $600 million, which 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 and cancellation of certain hedging positions.

Rather than Eurodollar loans, the reference rate in the Second Credit Agreement is the Secured Overnight Financing Rate ("SOFR"). Also, the Second Credit Agreement permits the Company to declare dividends for its equity owners, subject to

Table of Contents

certain limitations, including (i) no default or event of default has occurred or will occur upon such payments, (ii) the pro forma Leverage Ratio (outstanding debt to adjusted earnings before interest, taxes, depreciation and amortization, exploration expenses, and all other non-cash charges acceptable to the Administrative Agent) does not exceed 2.00 to 1.00, (iii) the amount of such payments does not exceed Available Free Cash Flow (as defined in the Second Credit Agreement), and (iv) the Borrowing Base Utilization Percentage (as defined in the Second Credit Agreement) is not greater than 80%.

The interest rate on each SOFR Loan will be the adjusted term SOFR for the applicable interest period plus a margin between 3.0% and 4.0% (depending on the then-current level of borrowing base usage). The annual interest rate on each base rate loan is (a) the greatest of (i) the Administrative Agent’s prime lending rate, (ii) the Federal Funds Rate (as defined in the Second Credit Agreement) plus 0.5% per annum, (iii) the adjusted term SOFR determined on a daily basis for an interest period of one month, plus 1.00% per annum and (iv) 0.00% per annum, plus (b) a margin between 2.0% and 3.0% per annum (depending on the then-current level of borrowing base usage).

The Second Credit Agreement contains certain covenants, which, among other things, require the maintenance of (i) a total Leverage Ratio of not more than 3.0 to 1.0 and (ii) a minimum ratio of Current Assets to Current Liabilities (as such terms are defined in the Second Credit Agreement) of 1.0 to 1.0. The Second Credit Agreement also contains other customary affirmative and negative covenants and events of default. The Company is required to maintain on a rolling 24 months basis, hedging transactions in respect of crude oil and natural gas, on not less than 50% of the projected production from its proved, developed, and producing oil and gas. However, if the borrowing base utilization is less than 25% at the hedge testing date and the Leverage Ratio is not greater than 1.25 to 1.00, the required hedging percentage for months 13 through 24 of the rolling 24 month period provided for will be 0% from such hedge testing date to the next succeeding hedge testing date and if the borrowing base utilization percentage is equal to or greater than 25%, but less than 50% and the Leverage Ratio is not greater than 1.25 to 1.00, the required hedging percentage for months 13 through 24 of the rolling 24 month period provided for will be 25% from such hedge testing date to the next succeeding hedge testing date.

As of September 30, 2024, $392 million was outstanding on the Credit Facility and the Company was in compliance with all covenants in the Second Credit Agreement.

Under the Second Credit Agreement, the applicable percentage for the unused commitment fee is 0.5% per annum for all levels of borrowing base utilization. As of September 30, 2024, the Company's unused line of credit was $208.0 million, which was calculated by subtracting the outstanding Credit Facility balance of $392 million and standby letters of credit of $35,000 ($10,000 with state and federal agencies and $25,000 with an insurance company for New Mexico state surety bonds) from the $600 million borrowing base.

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. A reconciliation for the asset retirement obligation during the nine months ended September 30, 2024 is as follows:


Balance, December 31, 2023	$	28,248,084

Liabilities incurred	505,721
Liabilities sold	(3,219,651)
Liabilities settled	(492,167)
Revision of estimate (1)	133,794
Accretion expense	1,057,213
Balance, September 30, 2024	$	26,232,994

(1) The revisions recorded during the nine months ended September 30, 2024 were related to shorter estimated useful lives, with regards to planned dates to plug and abandon such assets.

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

Table of Contents


	September 30, 2024		December 31, 2023
Asset retirement obligations, current	$	836,421	$	165,642
Asset retirement obligations, non-current	25,396,573		28,082,442
Asset retirement obligations	$	26,232,994	$	28,248,084

NOTE 10 — STOCKHOLDERS' EQUITY

As of December 31, 2023, the Company had 78,200 exercisable common warrants outstanding, with a contractual exercise price of $0.80 per warrant, expiring five years from initial issuance in October 2020. During the nine months ended September 30, 2024, no common warrants were exercised. The following table reflects the common warrants exercised, including the proceeds received for such exercises. As of September 30, 2024, there remained 78,200 exercisable common warrants.


	Common Warrants	Exercise Price		Proceeds Received
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
Exercised	—	—		$	—
Exercisable, September 30, 2023	78,200	$	0.80

Exercisable, December 31, 2023	78,200	$	0.80
Exercised	—	0.80		$	—
Exercisable, March 31, 2024	78,200	$	0.80
Exercised	—	0.80		$	—
Exercisable, June 30, 2024	78,200	$	0.80
Exercised	—	—		$	—
Exercisable, September 30, 2024	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 immediate exercise of the common warrants held by such Participating Holders in full at the Reduced Exercise Price in cash. The Company received aggregate gross proceeds of $8,997,543 from the exercise of the common warrants by the Participating Holders pursuant to the Exercise Agreement, which was recognized as an equity issuance cost in accordance with ASC 815-40-35-17(a). In the Condensed Statements of Stockholders' Equity, the net impact to Stockholders' Equity was $8,687,655, which was net of $309,888 in advisory fees.

NOTE 11 — EMPLOYEE STOCK OPTIONS AND RESTRICTED STOCK UNITS

Share-based compensation expense for share-based awards during the three and nine months ended September 30, 2024 and 2023 was as follows. These amounts are included in General and administrative expense in the Condensed Statements of Operations.


	Three Months Ended				Nine Months Ended
	September 30, 2024		September 30, 2023		September 30, 2024		September 30, 2023
Share-based compensation	$	32,087	$	2,170,735	$	3,833,697	$	6,374,743

Table of Contents

In 2011, the Board of Directors (the "Board") of the Company approved and adopted a long-term incentive plan (the “2011 Plan”), which was subsequently approved and amended by the shareholders. There were 541,755 shares eligible for grant, either as stock options or as restricted stock, as of September 30, 2024.

In 2021, the Board and Company shareholders approved and adopted the Ring Energy, Inc. 2021 Omnibus Incentive Plan (the “2021 Plan”). The 2021 Plan provides that the Company may grant options, stock appreciation rights, restricted shares, restricted stock units, performance-based awards, other share-based awards, other cash-based awards, or any combination of the foregoing. At the 2023 Annual Meeting of Shareholders, the shareholders approved an amendment to the 2021 Plan to increase the number of shares available under the 2021 Plan by 6.0 million. There were 5,107,795 shares available for grant as of September 30, 2024 under the 2021 Plan.

Table of Contents

Stock Options

A summary of the status of the stock options as of September 30, 2024 and 2023 and changes during the respective nine month periods then ended are as follows:


	Options	Weighted- Average Exercise Price		Weighted-Average Remaining Contractual Term	Aggregate Intrinsic Value
Outstanding, December 31, 2022	265,500	$	4.21
Granted	—	—
Forfeited	—	—
Exercised	—	—
Outstanding, March 31, 2023	265,500	$	4.21	1.39 years	$	—
Exercisable, March 31, 2023	265,500	$	4.21	1.39 years
Granted	—	—
Forfeited	—	—
Exercised	—	—
Outstanding, June 30, 2023	265,500	$	4.21	1.14 years	$	—
Exercisable, June 30, 2023	265,500	$	4.21	1.14 years
Granted	—	—
Forfeited	—	—
Exercised	—	—
Outstanding, September 30, 2023	265,500	$	4.21	0.89 years	$	—
Exercisable, September 30, 2023	265,500	$	4.21	0.89 years

Outstanding, December 31, 2023	70,500	$	10.33
Granted	—	—
Forfeited	—	—
Expired	(5,000)	5.50
Exercised	—	—
Outstanding, March 31, 2024	65,500	$	10.70	2.31 years	$	—
Exercisable, March 31, 2024	65,500	$	10.70	2.31 years
Granted	—	—
Forfeited	—	—
Expired	—	—
Exercised	—	—
Outstanding, June 30, 2024	65,500	$	10.70	2.06 years	$	—
Exercisable, June 30, 2024	65,500	$	10.70	2.06 years
Granted	—	$	—
Forfeited	—	$	—
Expired	—	$	—
Exercised	—	$	—
Outstanding, September 30, 2024	65,500	$	10.70	1.81 years	$	—
Exercisable, September 30, 2024	65,500	$	10.70	1.81 years

The intrinsic values were calculated using the closing price on September 30, 2024 of $1.60 and the closing price on September 30, 2023 of $1.95. As of September 30, 2024, the Company had $0 of unrecognized compensation cost related to stock options.

Table of Contents

Restricted Stock Units

A summary of the restricted stock unit activity as of September 30, 2024 and 2023, respectively, and changes during the respective nine month periods then ended are as follows:


	Restricted Stock Units	Weighted- Average Grant Date Fair Value
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
Granted	—	—
Forfeited or rescinded	(4,997)	2.22
Vested	(39,443)	2.87
Outstanding, September 30, 2023	3,840,827	$	2.12

Outstanding, December 31, 2023	3,148,226	$	2.40
Granted	2,647,970	1.30
Forfeited or rescinded	(26,802)	1.30
Vested	(1,342,112)	2.35
Outstanding, March 31, 2024	4,427,282	$	1.77
Granted	60,000	2.04
Forfeited or rescinded	(66,101)	1.43
Vested	(303,797)	2.74
Outstanding, June 30, 2024	4,117,384	$	1.70
Granted	76,600	1.97
Forfeited or rescinded	(399,552)	1.67
Vested	(57,338)	2.38
Outstanding, September 30, 2024	3,737,094	$	1.70

As of September 30, 2024, the Company had $2,925,708 of unrecognized compensation cost related to restricted stock unit grants that will be recognized over a weighted average period of 1.87 years. Grant activity for the nine months ended September 30, 2024 was primarily restricted stock units for the annual long-term incentive plan awards for employees.

Table of Contents

Performance Stock Units

A summary of the status of the performance stock unit ("PSU") grants as of September 30, 2024 and 2023, respectively, along with changes during the respective nine month periods then ended are as follows:


	Performance Stock Units	Weighted- Average Grant Date Fair Value
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
Granted	—	—
Forfeited or rescinded	—	—
Vested	—	—
Outstanding, September 30, 2023	2,882,594	$	3.34

Outstanding, December 31, 2023	2,022,378	$	3.11
Granted	—	—
Forfeited or rescinded	—	—
Vested	—	—
Outstanding, March 31, 2024	2,022,378	$	3.11
Granted	1,378,378	$	2.27
Forfeited or rescinded	—	$	—
Vested	—	$	—
Outstanding, June 30, 2024	3,400,756	$	2.77
Granted	—	—
Forfeited or rescinded	(863,702)	2.75
Vested	—	—
Outstanding, September 30, 2024	2,537,054	$	2.77

As of September 30, 2024, the Company had $4,353,631 of unrecognized compensation cost related to the PSU awards that will be recognized over a weighted average period of 1.67 years.

NOTE 12 — COMMITMENTS AND CONTINGENCIES

Standby Letters of Credit – A commercial bank previously issued standby letters of credit on behalf of the Company for $250,000 to the State of Texas, $10,000 to a federal agency, and $500,438 to an insurance company to secure the surety bonds described below. On February 23, 2024, the bank reduced the $500,438 standby letter of credit to $25,000 after approval of the insurance company, reduced the $250,000 standby letter of credit to the State of Texas to $0, and retained the standby letter of credit to the federal agency at $10,000. As of September 30, 2024, the Company had total standby letters of credit outstanding of $35,000. The standby letters of credit are valid until cancelled or matured and are collateralized by the Credit Facility with the bank. The terms of the letter of credit to the federal agency is extended for a term of one year at a time. The Company intends to renew the standby letter of credit to the federal agency for as long as required. As the Company no longer operates any wells in the State of New Mexico, that standby letter of credit will not need to be renewed. No amounts have been drawn under the standby letters of credit.

Table of Contents

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. As of September 30, 2024, the Company still had a surety bond in place of $25,000 for the State of New Mexico; however, these bonds are expected to be eliminated once change of ownership is approved by the New Mexico Oil Conservation Division. On January 10, 2024, two insurance companies issued surety bonds on behalf of the Company, one for $250,000, a Texas Railroad Commission ("RRC") required blanket performance bond to operate 100 wells or more in the State of Texas, and one for $2,000,000, an RRC required blanket plugging extension bond, each with zero collateral requirements. The term for these two surety bonds ends on July 1, 2025 and they can be renewed at that time. As of September 30, 2024, the Company had $2,275,000 in total surety bonds.

NOTE 13 — SUBSEQUENT EVENTS

In accordance with ASC Topic 855, Subsequent Events, the Company has evaluated all events subsequent to the balance sheet date of September 30, 2024, through the date these condensed financial statements were issued, November 6, 2024. The Company did not have any material subsequent events to report.

Table of Contents

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 condensed financial statements and the notes to those condensed 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 reduction of 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 vertical and horizontal drilling. In an effort to maximize its value and resources potential, Ring intends to drill and develop its acreage base in both its 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 September 30, 2024, the Company made net paydowns of $15 million on its revolving line of credit, resulting in the outstanding long-term debt balance of $392 million.

•Employ industry leading drilling and completion techniques. Ring’s executive team utilizes 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 returns generated by our drilling programs.

•Pursue strategic acquisitions with attractive upside potential. Ring has a history of acquiring leasehold positions that it believes to have additional resource potential that meet its targeted returns on invested capital and are comparable to its existing inventory of drilling locations. We pursue an acquisition strategy designed to increase reserves at attractive finding costs and complement our existing core properties. Management intends to continue to pursue strategic acquisitions and structure them financially, to improve balance sheet metrics and be accretive to income metrics. 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 is a competitive advantage in identifying potential acquisition targets.

Table of Contents

2024 Developments and Highlights

Drilling and Completion

In the first quarter of 2024, in the Northwest Shelf, the Company drilled and completed two 1-mile horizontal wells (one with a working interest of 99.5% and the other with a working interest of 100%). In the Central Basin Platform, the Company drilled and completed nine wells, all with a working interest of 100%. Specifically, in our Andrews County acreage the Company drilled and completed three 1-mile horizontal wells, in the Ector County acreage the Company drilled three vertical wells, and in the Crane County acreage the Company drilled and completed three vertical wells. Additionally, within the Central Basin Platform, the Company drilled and completed one salt water disposal ("SWD") well in Crane County.

In the second quarter of 2024, in the Central Basin Platform, the Company drilled and completed eleven wells, all with a working interest of 100%. Specifically, in our Andrews County acreage the Company drilled and completed five 1-mile horizontal wells, in the Ector County acreage the Company drilled three vertical wells, and in the Crane County acreage the Company drilled and completed three vertical wells.

In the third quarter of 2024, in the Northwest Shelf in Yoakum County, the Company drilled and completed two 1-mile horizontal wells, each with a working interest of 100%, and one 1.5-mile horizontal well with a working interest of approximately 94.2%. Meanwhile, in the Central Basin Platform, the Company drilled and completed six vertical wells, all with a working interest of 100%, three in Ector County and three in Crane County. Finally, in the Central Basin Platform in Andrews County, the Company drilled four 1-mile horizontal wells, all with a working interest of 100%. Two of these wells were completed. The remaining two wells will be completed in the fourth quarter of 2024.

The table below sets forth our drilling and completion activities for the nine months ended September 30, 2024.


Quarter	Area	Wells Drilled	Wells Completed	Drilled Uncompleted ("DUC")

1Q 2024	Northwest Shelf (Horizontal)	2	2	—
	Central Basin Platform (Horizontal)	3	3	—
	Central Basin Platform (Vertical)	6	6	—
	Total (1)	11	11	—

2Q 2024	Northwest Shelf (Horizontal)	—	—	—
	Central Basin Platform (Horizontal)	5	5	—
	Central Basin Platform (Vertical)	6	6	—
	Total	11	11	—

3Q 2024	Northwest Shelf (Horizontal)	3	3	—
	Central Basin Platform (Horizontal)	4	2	2
	Central Basin Platform (Vertical)	6	6	—
	Total	13	11	2

(1) First quarter total does not include the SWD well drilled and completed in the Central Basin Platform.

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.

Table of Contents

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 2023 and 2024 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.

Natural Gas Takeaway Capacity

The Permian Basin has been experiencing a shortage of pipeline transportation in order to sell natural gas produced in the Basin, resulting in negative natural gas prices, whereby the seller is actually paying the purchaser to take the gas. We have experienced negative realized gas prices at times and conditions are continuing. If these depressed or inverted natural gas prices continue in the region, our natural gas revenues will continue to be negatively impacted.

Inflation

Since 2022 inflation has increased costs associated with our capital program and production operations. We have experienced increases in the costs of many of the materials, supplies, equipment and services used in our operation. While 2024 costs have risen compared to prior years, overall industry activity has been muted and therefore service costs have remained flat or slightly decreased. In addition, the attempts to reduce inflation by the U.S. Federal Reserve have resulted in increased interest rates on debt. We continue to closely monitor costs and take all reasonable steps to mitigate the inflationary effect on our cost structure and also work to enhance our efficiency to minimize additional cost increases where possible.

Table of Contents

Results of Operations

Oil, Natural Gas, and Natural Gas Liquids Revenues for the Three Months Ended September 30, 2024 and 2023


	For the Three Months Ended
	September 30, 2024		September 30, 2023		Change		% Change
Net sales:
Oil	$	90,416,363	$	90,392,004	$	24,359	—	%
Natural gas	(3,859,603)		562,374		(4,421,977)		(786)	%
Natural gas liquids	2,687,623		2,727,420		(39,797)		(1)	%
Total sales	$	89,244,383	$	93,681,798	$	(4,437,415)	(5)	%

Net production:
Oil (Bbls)	1,214,788		1,106,531		108,257		10	%
Natural gas (Mcf)	1,705,027		1,567,104		137,923		9	%
Natural gas liquids (Bbls)	350,975		243,142		107,833		44	%
Total production (Boe)(1)	1,849,934		1,610,857		239,077		15	%

Average sales price:
Oil (per Bbl)	$	74.43	$	81.69	$	(7.26)	(9)	%
Natural gas (per Mcf)	(2.26)		0.36		(2.62)		(728)	%
Natural gas liquids (Bbl)	7.66		11.22		(3.56)		(32)	%
Total per Boe	$	48.24	$	58.16	$	(9.92)	(17)	%

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

Oil sales. Oil sales increased approximately $0.02 million from $90.4 million to $90.4 million due to a increase in sales volume from 1,106,531 barrels of oil to 1,214,788 barrels of oil, partially offset by a decrease in the average realized price per barrel from $81.69 to $74.43. Of the increase in volume of 108,257 barrels of oil, 94,512 barrels were from wells acquired and new wells drilled in the acreage acquired in the Founders Acquisition (which closed in August of 2023), as well as drilling activity in other areas, offset by natural declines from our legacy assets. The decreased average realized price per barrel was primarily a result of weaker market conditions.

Natural gas sales. Natural gas sales decreased approximately $4.4 million from $0.6 million to a negative $3.9 million. While our natural gas sales volume marginally increased from 1,567,104 Mcf to 1,705,027 Mcf, the average realized price per Mcf decreased from $0.36 to $(2.26). Of the increase in volume of 137,923 Mcf, an increase of 95,557 Mcf was from the Founders Acquisition and 42,366 Mcf was attributable to legacy assets. The price decrease was driven by a significant reduction in realized revenue pricing due to low demand as a result of current pipeline capacity constraints. The realized revenue pricing included the impact of gas plant processing fees that were netted from revenue. For the three months ended September 30, 2024, gross revenues were $(0.50) per Mcf and fees were $(1.76) per Mcf, compared to gross revenues of $2.16 per Mcf and fees of $(1.80) per Mcf for the three months ended September 30, 2023. This resulted in a net realized price of $(2.26) per Mcf for the three months ended September 30, 2024 compared to $0.36 per Mcf for the three months ended September 30, 2023.

Natural gas liquids sales. NGL sales decreased approximately $0.04 million from $2.7 million to $2.7 million. NGL sales volumes for the three months ended September 30, 2024 were 350,975 barrels of NGLs compared to 243,142 barrels of NGLs for the comparable period in 2023. Of the increase in volume of 107,833 barrels, 28,066 barrels were attributable to wells acquired and new wells drilled in the acreage acquired in the Founders Acquisition, with the remaining 79,767 barrels attributable to our legacy assets due to increased NGL yields. The average realized price per barrel of NGLs was $7.66 for the three months ended September 30, 2024 compared to $11.22 for the three months ended September 30, 2023, due to weaker market conditions.

Table of Contents

Oil, Natural Gas, and Natural Gas Liquids Revenues for the Nine Months Ended September 30, 2024 and 2023


	For the Nine Months Ended
	September 30, 2024		September 30, 2023		Change		% Change
Net sales:
Oil	$	282,000,446	$	252,020,403	$	29,980,043	12	%
Natural gas	(7,650,645)		526,161		(8,176,806)		NM (2)
Natural gas liquids	8,537,067		8,566,719		(29,652)		0	%
Total sales	$	282,886,868	$	261,113,283	$	21,773,585	8	%

Net production:
Oil (Bbls)	3,673,356		3,325,323		348,033		10	%
Natural gas (Mcf)	4,739,881		4,726,056		13,825		—	%
Natural gas liquids (Bbls)	919,225		715,832		203,393		28	%
Total production (Boe)(1)	5,382,561		4,828,831		553,730		11	%

Average sales price:
Oil (per Bbl)	$	76.77	$	75.79	$	0.98	1	%
Natural gas (per Mcf)	(1.61)		0.11		(1.72)		NM (2)
Natural gas liquids (Bbl)	9.29		11.97		(2.68)		(22)	%
Total per Boe	$	52.56	$	54.07	$	(1.51)	(3)	%

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

(2) Not meaningful.

Oil sales. Oil sales increased approximately $30.0 million from $252.0 million to $282.0 million due to an increase in sales volume from 3,325,323 barrels of oil to 3,673,356 barrels of oil, further supported by a increase in the average realized price per barrel from $75.79 to $76.77. Of the increase in volume of 348,033 barrels, 431,512 barrels were from wells acquired and new wells drilled in the acreage acquired in the Founders Acquisition, as well as drilling activity in other areas, offset by natural declines from our legacy assets and sale of non-core assets. The increased average realized price per barrel was primarily the result of stronger market conditions.

Natural gas sales. Natural gas sales decreased approximately $8.2 million from $0.5 million to a negative $7.7 million. While the natural gas sales volume increased from 4,726,056 Mcf to 4,739,881 Mcf, the average realized price per Mcf decreased from $0.11 to $(1.61). Of the increase in volume of 13,825 Mcf, 341,102 Mcf was from wells acquired and new wells drilled in the acreage acquired in the Founders Acquisition, and the offsetting decrease of (327,277) Mcf was attributable to natural declines in our legacy assets. The price decrease was driven by lower market conditions. The realized revenue pricing includes the impact of gas plant processing fees that were netted from revenue. For the nine months ended September 30, 2024, gross revenues were $0.09 per Mcf and fees were $(1.70) per Mcf, compared to gross revenues of $1.73 per Mcf and fees of $(1.62) per Mcf for the nine months ended September 30, 2023. This resulted in a net realized price of $(1.61) for the nine months ended September 30, 2024 compared to $0.11 per Mcf for the nine months ended September 30, 2023.

Natural gas liquids sales. NGL sales slightly decreased by $0.03 million from $8.6 million to $8.5 million. NGL sales volumes for the nine months ended September 30, 2024 were 919,225 barrels of NGLs compared to 715,832 barrels of NGLs for the comparable period in 2023. Of the increase in volume of 203,393 barrels, 95,515 barrels were attributable to the wells acquired and new wells drilled in the acreage acquired in the Founders Acquisition, and 107,878 barrels were from our legacy assets. The average realized price per barrel of NGLs was $9.29 for the nine months ended September 30, 2024 compared to $11.97 for the nine months ended September 30, 2023, attributable to weaker market conditions.

Table of Contents

Production Costs for the Three Months Ended September 30, 2024 and 2023


	For the Three Months Ended
	September 30, 2024			September 30, 2023			Change			% Change

Lease operating expenses ("LOE")	$	20,315,282		$	18,015,348		$	2,299,934		13	%
Average LOE per Boe	$	10.98		$	11.18		$	(0.20)		(2)	%

Gathering, transportation and processing costs ("GTP")	$	102,420		$	(4,530)		$	106,950		NM (1)
Average GTP per Boe	$	0.06		$	0.00		$	0.06		100	%

Ad valorem taxes	$	2,164,562		$	1,779,163		$	385,399		22	%
Average Ad valorem taxes per Boe	$	1.17		$	1.10		$	0.07		6	%

Oil and natural gas production taxes	$	4,203,851		$	4,753,289		$	(549,438)		(12)	%
Average Production taxes per Boe	$	2.27		$	2.95		$	(0.68)		(23)	%
Production taxes as a percentage of total sales	4.71		%	5.07		%	(0.36)		%	(7)	%

(1) Not meaningful.

Lease operating expenses. Our total lease operating expenses (“LOE”) increased from $18.0 million to $20.3 million and decreased on a per Boe basis from $11.18 to $10.98. 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 a 15% increase in production of 239,077 Boe as a result of the new wells acquired in the Founders Acquisition as well as new wells drilled and completed from our development program. Specific cost categories with significant increases included electricity and chemical.

Gathering, transportation and processing costs. Our total gathering, transportation and processing costs (“GTP”) increased from negative $4,530 to $102,420 and increased on a per Boe basis from $0.00 to $0.06. Beginning May 1, 2022, due to a natural gas processing entity taking control of transportation at the wellhead, GTP costs were re-classified as a reduction to oil and natural gas sales revenues. However, GTP costs increased on the period shown due to one remaining contract with a natural gas processing entity in place where point of control of gas dictates requiring the fees be recorded as an expense.

Ad valorem taxes. Our total ad valorem taxes increased from $1.8 million to $2.2 million and increased on a per Boe basis from $1.10 to $1.17. Of the $0.4 million increase in ad valorem taxes, $0.4 million was for Yoakum County properties, and $0.2 million for Ector County properties, offset by a reduction in $0.3 million related to Crane County tax estimates.

Oil and natural gas production taxes. Oil and natural gas production taxes as a percentage of oil and natural gas sales were 5.07% for the three months ended September 30, 2023 and decreased to 4.71% for the three months ended September 30, 2024. The change in average tax percentage is due to the divestiture of the New Mexico assets in the third quarter of 2023, which had higher tax rates on both oil and gas than the remaining Texas assets.

Table of Contents

Production Costs for the Nine Months Ended September 30, 2024 and 2023


	For the Nine Months Ended
	September 30, 2024			September 30, 2023			Change			% Change

Lease operating expenses ("LOE")	$	57,984,733		$	51,426,145		$	6,558,588		13	%
Average LOE per Boe	$	10.77		$	10.65		$	0.12		1	%

Gathering, transportation and processing costs ("GTP")	$	376,103		$	(6,985)		$	383,088		NM (1)
Average GTP per Boe	$	0.07		$	0.00		$	0.07		100	%

Ad valorem taxes	$	5,647,469		$	5,120,119		$	527,350		10	%
Average Ad valorem taxes per Boe	$	1.05		$	1.06		$	(0.01)		(1)	%

Oil and natural gas production taxes	$	12,259,418		$	13,173,568		$	(914,150)		(7)	%
Average Production taxes per Boe	$	2.28		$	2.73		$	(0.45)		(16)	%
Production taxes as a percentage of total sales	4.33		%	5.05		%	(0.72)		%	(14)	%

(1) Not meaningful.

Lease operating expenses. Our total LOE increased from $51.4 million to $58.0 million and LOE per Boe increased from $10.65 to $10.77. Total LOE increased primarily due to an 11% increase in production of 553,730 Boe as a result of the new wells acquired in the Founders Acquisition as well as new wells drilled and completed from our development program. Specific cost categories with significant increases included chemical, electricity, salaries, and other employee expenses.

Gathering, transportation and processing costs. Our total GTP increased from negative $6,985 to $376,103 and increased on a per Boe basis from $0.00 to $0.07. Beginning May 1, 2022, due to a natural gas processing entity taking control of transportation at the wellhead, GTP costs were re-classified as a reduction to oil and natural gas sales revenues. However, GTP costs increased on the period shown due to one remaining contract with a natural gas processing entity in place where point of control of gas dictates requiring the fees be recorded as an expense.

Ad valorem taxes. Our total ad valorem taxes increased from $5.1 million to $5.6 million and decreased on a per Boe basis from $1.06 to $1.05. Of the approximate $0.5 million increase in ad valorem taxes, $0.9 million was from the addition of Ector County properties acquired in the Founders Acquisition, offset by a net reduction in estimates for other jurisdictions of $0.4 million.

Oil and natural gas production taxes. Oil and natural gas production taxes as a percentage of oil and natural gas sales were 5.05% for the nine months ended September 30, 2023 and decreased to 4.33% for the nine months ended September 30, 2024. The overall average percentage of production taxes to oil and gas sales in 2024 is 4.7% which is in line with historical rates. However, in May 2024, an accrual of $(0.9) million was made for estimated severance tax refunds expected, which lowered the average for the nine months ended September 30, 2024.

Table of Contents

Other Costs and Operating Expenses for the Three Months Ended September 30, 2024 and 2023


	For the Three Months Ended
	September 30, 2024		September 30, 2023		Change		% Change

Depreciation, depletion and amortization (DD&A):
Depletion	$	25,302,058	$	21,711,123	$	3,590,935	17	%
Depreciation	102,043		80,690		21,353		26	%
Amortization of financing lease assets	258,022		197,221		60,801		31	%
Total depreciation, depletion and amortization	$	25,662,123	$	21,989,034	$	3,673,089	17	%

Depletion per Boe	$	13.68	$	13.48	$	0.20	1	%
Depreciation, depletion and amortization per Boe	$	13.87	$	13.65	$	0.22	2	%

Asset retirement obligation ("ARO") accretion	$	354,195	$	354,175	$	20	0	%

Operating lease expense	$	175,091	$	138,220	$	36,871	27	%

General and administrative expense ("G&A"):
General and administrative expense (excluding Share-based compensation)	$	6,389,480	$	4,912,839	$	1,476,641	30	%
Share-based compensation	32,087		2,170,735		(2,138,648)		(99)	%
Total general and administrative expense	$	6,421,567	$	7,083,574	$	(662,007)	(9)	%

G&A per Boe	$	3.47	$	4.40	$	(0.93)	(21)	%
G&A excluding Share-based compensation, per Boe	$	3.45	$	3.05	$	0.40	13	%

Depreciation, depletion and amortization. Our depreciation, depletion and amortization increased from $22.0 million to $25.7 million due to a higher depletion rate as well as an increase of 239,077 in Boe produced. Additional trucks were leased for field operations, resulting in higher finance lease amortization costs. Our average depreciation, depletion and amortization per Boe increased from $13.65 per Boe to $13.87 per Boe, due to the higher percentage reduction in the Boe amortization base compared to the reduction in the total estimated costs of property.

Asset retirement obligation accretion. Our asset retirement obligation (“ARO”) accretion increased slightly from $354,175 to $354,195 due to additional ARO accretion associated with properties acquired in the Founders Acquisition as well as new drilled and completed wells, offset by wells plugged and abandoned and sold.

Operating lease expense. Our operating lease expense increased from $138,220 to $175,091 due to additional office space leased in The Woodlands office expansion beginning in October 2023.

General and administrative expense. General and administrative ("G&A") expense decreased from $7.1 million to $6.4 million. Of the $0.7 million cost decrease, there was a decrease of $2.1 million in share-based compensation costs, offset by $0.7 million of an increase in salaries and wages, $0.5 million in bonus compensation, $0.2 million in transaction costs, and $0.1 million in other professional fees.

Table of Contents

Other Costs and Operating Expenses for the Nine Months Ended September 30, 2024 and 2023


	For the Nine Months Ended
	September 30, 2024		September 30, 2023		Change		% Change

Depreciation, depletion and amortization (DD&A):
Depletion	$	73,056,856	$	63,203,473	$	9,853,383	16	%
Depreciation	306,752		277,420		29,332		11	%
Amortization of financing lease assets	790,386		572,744		217,642		38	%
Total depreciation, depletion and amortization	$	74,153,994	$	64,053,637	$	10,100,357	16	%

Depletion per Boe	$	13.57	$	13.09	$	0.48	4	%
Depreciation, depletion and amortization per Boe	$	13.78	$	13.26	$	0.52	4	%

Asset retirement obligation ("ARO") accretion	$	1,057,213	$	1,073,900	$	(16,687)	(2)	%

Operating lease expense	$	525,272	$	366,711	$	158,561	43	%

General and administrative expense ("G&A"):
General and administrative expense (excluding Share-based compensation)	$	17,770,626	$	14,649,213	$	3,121,413	21	%
Share-based compensation	3,833,697		6,374,743		(2,541,046)		(40)	%
Total general and administrative expense	$	21,604,323	$	21,023,956	$	580,367	3	%

G&A per Boe	$	4.01	$	4.35	$	(0.34)	(8)	%
G&A excluding Share-based compensation, per Boe	$	3.30	$	3.03	$	0.27	9	%

Depreciation, depletion and amortization. Our depreciation, depletion and amortization increased from $64.1 million to $74.2 million due to a higher depletion rate as well as an increase of 553,730 in Boe produced. Our average depreciation, depletion and amortization per Boe increased from $13.26 per Boe to $13.78 per Boe, due to the increase in the total estimated costs of property, as well as the reduction in the Boe amortization base.

Asset retirement obligation accretion. Our ARO accretion decreased from $1,073,900 to $1,057,213 primarily as a result of wells plugged and abandoned and sold, offset by the additional ARO accretion associated with the properties acquired in the Founders Acquisition.

Operating lease expense. Our operating lease expense increased from $366,711 to $525,272 due to the additional office space leased in The Woodlands office.

General and administrative expense. G&A expense increased from $21.0 million to $21.6 million, with the $0.6 million cost increase due to an increase of $1.6 million in salaries and wages, $0.6 million for an employee retention tax credit that was received in 2023, $0.4 million in bonus compensation, $0.3 million in other professional fees, and $0.3 million in legal fees. This was offset by a decrease of $2.5 million in share-based compensation costs and $0.3 million in lower transaction costs.

Table of Contents

Other Income (Expense) for the Three Months Ended September 30, 2024 and 2023


	For the Three Months Ended
	September 30, 2024		September 30, 2023		Change		% Change

Interest income	$	143,704	$	80,426	$	63,278	79	%

Interest expense:
Interest on revolving line of credit	$	9,209,180	$	9,711,871	$	(502,691)	(5)	%
Fees associated with revolving line of credit	266,291		239,218		27,073		11	%
Amortization of deferred financing costs	1,226,881		1,258,466		(31,585)		(3)	%
Interest on financing lease liabilities	27,224		23,416		3,808		16	%
Interest paid for notes payable	24,115		22,286		1,829		8	%
Deferred cash payment accretion	—		126,497		(126,497)		(100)	%
Other interest	552		—		552		100	%
Total interest expense	$	10,754,243	$	11,381,754	$	(627,511)	(6)	%

Gain (loss) on derivative contracts:
Realized gain (loss):
Crude oil	$	(3,109,660)	$	(5,825,427)	$	2,715,767	(47)	%
Natural gas	1,226,895		474,629		752,266		158	%
Total realized gain (loss)	$	(1,882,765)	$	(5,350,798)	$	3,468,033	(65)	%
Unrealized gain (loss):
Crude oil	$	27,238,245	$	(34,077,473)	$	61,315,718	(180)	%
Natural gas	(623,855)		205,516		(829,371)		(404)	%
Total unrealized gain (loss)	$	26,614,390	$	(33,871,957)	$	60,486,347	(179)	%
Total gain (loss) on derivative contracts:	$	24,731,625	$	(39,222,755)	$	63,954,380	(163)	%

Gain (loss) on disposal of assets	$	—	$	—	$	—	—	%
Other income	$	—	$	—	$	—	—	%

Interest income. During the three months ended September 30, 2024, interest income of $143,704 was earned from excess cash balances in bank sweep accounts. During the three months ended September 30, 2023, interest income of $78,679 was earned from depositing excess cash balances in bank sweep accounts and $1,747 was from interest on an escrow account.

Interest expense. Interest expense decreased from $11.4 million to $10.8 million primarily due to lower amounts outstanding on our Credit Facility, with a weighted average daily debt of approximately $406.5 million during the third quarter of 2024 compared to approximately $422.6 million during the third quarter of 2023. Offsetting this change was an increase in interest rates, with a weighted average annual interest rate of 9.3% in the third quarter of 2024 compared to 9.2% in the third quarter of 2023.

Gain (loss) on derivative contracts. We recorded a gain on derivative contracts of $24.7 million for the three months ended September 30, 2024 compared to a loss on derivative contracts of $39.2 million for the three months ended September 30, 2023. For the derivative contract settlements, we recorded a realized loss of $1.9 million for the three months ended September 30, 2024 and a realized loss of $5.4 million for the three months ended September 30, 2023. The reduction of $3.5 million in the realized loss was a result of more favorable settlements of crude oil derivative contracts during the current year. For the marked-to-market contracts, we recorded an unrealized gain of $26.6 million for the three months ended September 30, 2024 and an unrealized loss of $33.9 million for the three months ended September 30, 2023. The change in position was primarily due to the changes in crude oil futures prices.

Table of Contents

Other Income (Expense) for the Nine Months Ended September 30, 2024 and 2023


	For the Nine Months Ended
	September 30, 2024		September 30, 2023		Change		% Change

Interest income	$	367,181	$	160,171	$	207,010	129	%

Interest expense:
Interest on revolving line of credit	$	28,497,006	$	27,478,591	$	1,018,415	4	%
Fees associated with revolving line of credit	751,216		717,468		33,748		5	%
Amortization of deferred financing costs	3,670,096		3,699,235		(29,139)		(1)	%
Interest on financing lease liabilities	89,963		73,115		16,848		23	%
Interest paid for notes payable	40,481		35,211		5,270		15	%
Deferred cash payment accretion	—		319,220		(319,220)		(100)	%
Other interest	150,552		—		150,552		100	%
Total interest expense	$	33,199,314	$	32,322,840	$	876,474	3	%

Gain (loss) on derivative contracts:
Realized gain (loss):
Crude oil	$	(9,921,757)	$	(7,323,030)	$	(2,598,727)	35	%
Natural gas	3,982,980		1,493,302		2,489,678		167	%
Total realized gain (loss)	$	(5,938,777)	$	(5,829,728)	$	(109,049)	2	%
Unrealized gain (loss):
Crude oil	$	12,552,517	$	(21,425,316)	$	33,977,833	(159)	%
Natural gas	(2,725,209)		771,854		(3,497,063)		(453)	%
Total unrealized gain (loss)	$	9,827,308	$	(20,653,462)	$	30,480,770	(148)	%
Total gain (loss) on derivative contracts:	$	3,888,531	$	(26,483,190)	$	30,371,721	(115)	%

Gain (loss) on disposal of assets	$	89,693	$	(132,109)	$	221,802	(168)	%
Other income	$	25,686	$	126,210	$	(100,524)	(80)	%

Interest income. During the nine months ended September 30, 2024, interest income of $367,181 was earned from excess cash balances in bank sweep accounts. During the nine months ended September 30, 2023, interest income of $129,382 was depositing excess cash balances in bank sweep accounts beginning May 2023, $29,042 was earned from the employee retention tax credit, and $1,747 was from interest on an escrow account.

Interest expense. Interest expense increased from $32.3 million to $33.2 million primarily due to the result of higher interest rates, with a weighted average annual interest rate of 9.3% during the nine months ended September 30, 2024 compared to 8.7% during the nine months ended September 30, 2023. This change was offset by lower amounts outstanding on our Credit Facility, with a weighted average daily debt of approximately $418.5 million during the nine months ended September 30, 2024 compared to approximately $420.6 million during the nine months ended September 30, 2023.

Gain (loss) on derivative contracts. We recorded a gain on derivative contracts of $3.9 million for the nine months ended September 30, 2024 and a loss on derivative contracts of $26.5 million for the nine months ended September 30, 2023. For the derivative contract settlements, we recorded a realized loss of $5.9 million for the nine months ended September 30, 2024 and a realized loss of $5.8 million for the nine months ended September 30, 2023. The increase of $0.1 million in the realized loss was a result of slightly less favorable settlements of crude oil derivative contracts during the current year. For the marked-to-market contracts, we recorded an unrealized gain of $9.8 million for the nine months ended September 30,

Table of Contents

2024 and an unrealized loss of $20.7 million for the nine months ended September 30, 2023. This change in unrealized derivatives primarily was due to the changes in crude oil futures prices on derivative contracts in the Company's portfolio.

Gain (loss) on disposal of assets. During the nine months ended September 30, 2024 the Company recognized a gain of $89,693 on disposal from selling multiple Company owned vehicles. Also, during the nine months ended September 30, 2023, the Company recognized a loss of $132,109 on disposal from selling multiple Company owned vehicles.

Other income. During the nine months ended September 30, 2024, the Company recorded other income of $25,686 from an additional bank rebate related to the use of a vendor payment program. During the nine months ended September 30, 2023, the Company recorded $126,210 of other income, primarily from the termination of the Woodlands office operating lease as of May 31, 2023.

Benefit from (Provision for) Income Taxes for the Three Months Ended September 30, 2024 and 2023


	For the Three Months Ended
	September 30, 2024		September 30, 2023		Change		% Change

Benefit from (Provision for) Income Taxes:
Deferred federal income tax benefit (provision)	$	(9,637,849)	$	3,381,104	$	(13,018,953)	(385)	%
Current state income tax benefit (provision)	(74,899)		(165,780)		90,881		(55)	%
Deferred state income tax benefit (provision)	(375,206)		196,012		(571,218)		(291)	%
Benefit from (Provision for) Income Taxes	$	(10,087,954)	$	3,411,336	$	(13,499,290)	(396)	%

Benefit from (Provision for) income taxes. The benefit from (provision for) income taxes changed from a benefit of $3.4 million for the three months ended September 30, 2023 to a provision of $10.1 million for the three months ended September 30, 2024. The benefit from (provision for) income taxes was calculated using the annual effective tax rate method based on our estimated earnings and estimated state and federal income taxes due for 2024, taking into account all applicable tax rates and laws.

Benefit from (Provision for) Income Taxes for the Nine Months Ended September 30, 2024 and 2023


	For the Nine Months Ended
	September 30, 2024		September 30, 2023		Change		% Change

Benefit from (Provision for) Income Taxes:
Deferred federal income tax benefit (provision)	$	(17,617,436)	$	8,492,595	$	(26,110,031)	(307)	%
Current state income tax benefit (provision)	(329,917)		(264,261)		(65,656)		25	%
Deferred state income tax benefit (provision)	(689,972)		(490,646)		(199,326)		41	%
Benefit from (Provision for) Income Taxes	$	(18,637,325)	$	7,737,688	$	(26,375,013)	(341)	%

Benefit from (Provision for) income taxes. The benefit from (provision for) income taxes changed from a benefit of $7.7 million for the nine months ended September 30, 2023 to a provision of $18.6 million for the nine months ended September 30, 2024. The benefit from (provision for) income taxes was calculated using the annual effective tax rate method based on our estimated earnings and estimated state and federal income taxes due for 2024, taking into account all applicable tax rates and laws.

Table of Contents

Liquidity and Capital Resources

As of September 30, 2024, we had cash on hand of $0.0 million, compared to $0.3 million as of December 31, 2023. We strive to keep our cash balance as low as possible to minimize our outstanding debt and associated interest. At certain times we reflect a zero book balance while utilizing the float on outstanding checks. We had net cash provided by operating activities for the nine months ended September 30, 2024 of $147.1 million, compared to net cash provided by operating activities of $142.4 million for the same period in 2023, which was 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 $113.2 million for the nine months ended September 30, 2024, compared to net cash used in investing activities of $170.9 million for the same period in 2023, driven by the deferred cash payment made for the Stronghold Acquisition in the first quarter of 2023 as well as the payment for the Founders Acquisition in the third quarter of 2023, with no comparable payments made to date in 2024. Net cash used in financing activities was $34.3 million for the nine months ended September 30, 2024 during which time $33 million was the net paydown of principal on our Credit Facility.

We will continue to focus on maximizing cash flow in 2024 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 2024, 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 September 30, 2024, $392 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 and November. 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 September 30, 2024 (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)
	Q4 2024		Q1 2025		Q2 2025		Q3 2025		Q4 2025		Q1 2026		Q2 2026		Q3 2026

Swaps:
Hedged volume (Bbl)	368,000		71,897		52,063		265,517		64,555		449,350		432,701		—
Weighted average swap price	$	68.43	$	72.03	$	72.03	$	72.94	$	72.03	$	70.38	$	69.53	$	—

Deferred premium puts:
Hedged volume (Bbl)	88,405		—		—		—		—		—		—		—
Weighted average strike price	$	75.00	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Weighted average deferred premium price	$	2.61	$	—	$	—	$	—	$	—	$	—	$	—	$	—

Two-way collars:
Hedged volume (Bbl)	128,800		474,750		464,100		225,400		404,800		—		—		379,685
Weighted average put price	$	60.00	$	57.06	$	60.00	$	65.00	$	60.00	$	—	$	—	$	60.00
Weighted average call price	$	73.24	$	75.82	$	69.85	$	78.91	$	75.68	$	—	$	—	$	72.50

Table of Contents


	Gas Hedges (Henry Hub)
	Q4 2024		Q1 2025		Q2 2025		Q3 2025		Q4 2025		Q1 2026		Q2 2026		Q3 2026

NYMEX Swaps:
Hedged volume (MMBtu)	431,800		616,199		594,400		289,550		—		—		532,500		—
Weighted average swap price	$	4.44	$	3.78	$	3.43	$	3.72	$	—	$	—	$	3.38	$	—

Two-way collars:
Hedged volume (MMBtu)	18,300		33,401		27,300		308,200		598,000		553,500		—		515,728
Weighted average put price	$	3.00	$	3.00	$	3.00	$	3.00	$	3.00	$	3.50	$	—	$	3.00

Weighted average call price	$	4.15	$	4.39	$	4.15	$	4.75	$	4.15	$	5.03	$	—	$	3.93


	Oil Hedges (basis differential)
	Q4 2024		Q1 2025		Q2 2025		Q3 2025		Q4 2025		Q1 2026		Q2 2026		Q3 2026

Argus basis swaps:
Hedged volume (Bbl)	244,000		270,000		273,000		276,000		276,000		—		—		—
Weighted average spread price (1)	$	1.15	$	1.00	$	1.00	$	1.00	$	1.00	$	—	$	—	$	—

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

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 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 September 30, 2024, 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 is highly competitive and may require substantially greater capital than we currently have available and obtaining additional capital may require that we obtain either short-

Table of Contents

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 likely increase our debt levels. 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 pro forma information regarding oil and gas properties. Even though we may incur these costs, there is no assurance that we will ultimately be able to consummate additional acquisitions of oil and gas producing properties.

Table of Contents

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 decreases in oil and natural gas prices. Realized pricing is primarily driven by the prevailing domestic price for crude oil and spot prices in the Permian Basin. 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 decrease 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 $32.5 million as of September 30, 2024). 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 nine months ended September 30, 2024. We believe that the loss of any of these purchasers would not materially impact our business because we could readily find other purchasers for our oil and natural gas.

For the Nine Months Ended

As of

September 30, 2024

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

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

Purchaser:

Phillips 66 Company ("Phillips")

61%

69%

Concord Energy LLC ("Concord")

14%

11%

LPC Crude III, LLC ("LPC Crude")

13%

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 September 30, 2024, we had $392 million outstanding on our Credit Facility with a weighted average annual interest rate for the nine months ended September 30, 2024 of 9.3%. A 1% change in the interest rate on our Credit Facility would result in an estimated $3.9 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 of our Credit Facility.

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

Table of Contents

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.

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 September 30, 2024 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

There were no material developments during the quarter ended September 30, 2024 in the legal proceeding described in our Annual Report on Form 10-K for the year ended December 31, 2023.

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 Annual Report on Form 10-K for the year ended December 31, 2023 as filed with the SEC. 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.

Table of Contents

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 September 30, 2024, none of our directors or officers (as defined in Rule 16a-1(f) of the Securities Exchange Act of 1934) 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).

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)

Table of Contents

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: November 6, 2024	By:	/s/ Paul D. McKinney
		Paul D. McKinney
		Chief Executive Officer
		(Principal Executive Officer)

Date: November 6, 2024	By:	/s/ Travis T. Thomas
		Travis T. Thomas
		Chief Financial Officer
		(Principal Financial and Accounting Officer)