rei-20260630

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United States

Securities and Exchange Commission

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended June 30, 2026

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

For the transition period from ______ to ______

Commission file number 001-36057

Ring Energy, Inc.

(Exact name of registrant as specified in its charter)


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

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

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

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


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

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

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

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

Large accelerated filer

Accelerated filer

Non-accelerated filer

(Do not check if a smaller reporting company)

Smaller reporting company

Emerging growth company

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is shell company (as defined in Rule 12b-2 of the Act). Yes o No x

As of August 5, 2026, the registrant had outstanding 260,539,607 shares of common stock ($0.001 par value).

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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	39
	Item 3:	Quantitative and Qualitative Disclosures About Market Risk	55
	Item 4:	Controls and Procedures	56
PART II — OTHER INFORMATION
	Item 1:	Legal Proceedings	56
	Item 1A:	Risk Factors	56
	Item 2:	Unregistered Sales of Equity Securities and Use of Proceeds	56
	Item 3:	Defaults Upon Senior Securities	56
	Item 4:	Mine Safety Disclosures	57
	Item 5:	Other Information	57
	Item 6:	Exhibits	57
SIGNATURES			58

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Forward Looking Statements

This Quarterly Report on Form 10-Q (herein, “Quarterly Report”) contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Quarterly Report regarding our strategy, future operations, financial position, estimated revenues and expenses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report, the words “may,” “will,” “could,” “would,” “should,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “plan,” “pursue,” “target,” “continue,” “potential,” “guidance,” “project” or other similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. All forward-looking statements speak only as of the date of this Quarterly Report. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Quarterly Report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We are making investors aware that such forward-looking statements, because they relate to future events, are by their very nature subject to many important factors that could cause actual results to differ materially from those contemplated. Such factors include:

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

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

•our ability to generate sufficient 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 and potential full-cost ceiling impairment;

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

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

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

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

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

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

•geological concentration of our oil and natural gas reserves;

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

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

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

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

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

•future 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 (including the recent conflict between the United States and Iran), Russia, and Ukraine and acts of terrorism or sabotage;

•the short and long-term potential impact to us of worsening trade relations and related economic disruptions including, but not limited to, inflation, energy price volatility, tariffs, trade wars, and supply chain disruptions;

•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, 2025, 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.

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PART I — FINANCIAL INFORMATION

Item 1. Condensed Financial Statements

The following (a) condensed balance sheet as of December 31, 2025 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.

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RING ENERGY, INC.

CONDENSED BALANCE SHEETS

(Unaudited)


	June 30, 2026		December 31, 2025
ASSETS
Current Assets
Cash and cash equivalents	$	1,137,410	$	902,913
Accounts receivable	43,460,514		30,938,908
Joint interest billing receivables, net	1,083,368		1,623,991
Derivative assets	6,335,601		21,468,134
Inventory	5,626,261		5,312,715
Prepaid expenses and other assets	3,195,806		1,822,751
Total Current Assets	60,838,960		62,069,412
Properties and Equipment
Oil and natural gas properties, full cost method	1,804,582,372		1,891,510,431
Financing lease asset subject to depreciation	3,687,531		3,633,586
Fixed assets subject to depreciation	3,389,403		3,504,788
Total Properties and Equipment	1,811,659,306		1,898,648,805
Accumulated depreciation, depletion and amortization	(610,047,201)		(569,180,901)
Net Properties and Equipment	1,201,612,105		1,329,467,904
Operating lease asset	963,396		1,285,159
Derivative assets	10,154,821		9,739,430
Deferred financing costs	7,987,814		9,337,344
Total Assets	$	1,281,557,096	$	1,411,899,249

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	98,068,202	$	90,258,731
Income tax liability	514,966		356,436
Financing lease liability	693,432		730,564
Operating lease liability	491,796		586,614
Derivative liabilities	11,373,096		841,193
Notes payable	1,496,304		505,752

Asset retirement obligations	291,844		418,526
Total Current Liabilities	112,929,640		93,697,816

Non-current Liabilities

Deferred income taxes	11,243,098		22,298,701
Revolving line of credit	360,000,000		420,000,000
Financing lease liability, less current portion	533,212		593,146
Operating lease liability, less current portion	569,328		819,223
Derivative liabilities	12,035,055		2,512,692
Asset retirement obligations	30,823,001		29,972,429
Total Liabilities	528,133,334		569,894,007
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; 260,520,291 shares and 207,656,929 shares issued and outstanding, respectively	260,520		207,657
Additional paid-in capital	879,941,415		812,777,586
Retained earnings (Accumulated deficit)	(126,778,173)		29,019,999
Total Stockholders’ Equity	753,423,762		842,005,242
Total Liabilities and Stockholders' Equity	$	1,281,557,096	$	1,411,899,249

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

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RING ENERGY, INC.

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)


	For the Three Months Ended				For the Six Months Ended
	June 30, 2026		June 30, 2025		June 30, 2026		June 30, 2025

Oil, Natural Gas, and Natural Gas Liquids Revenues	$	104,681,489	$	82,602,759	$	178,353,153	$	161,693,966

Costs and Operating Expenses
Lease operating expenses	18,409,462		20,245,981		36,531,806		39,923,533
Gathering, transportation and processing costs	101,902		133,809		218,951		337,421
Ad valorem taxes	2,202,160		1,648,647		4,404,697		3,180,755
Oil and natural gas production taxes	5,047,619		3,832,607		8,601,510		7,417,062
Depreciation, depletion and amortization	20,114,890		25,569,914		41,520,838		48,185,897
Ceiling test impairment	—		—		162,086,257		—
Asset retirement obligation accretion	401,944		382,251		797,440		708,800
Operating lease expense	175,090		175,090		350,181		350,181
General and administrative expense	7,954,230		7,138,519		15,393,008		15,758,495

Total Costs and Operating Expenses	54,407,297		59,126,818		269,904,688		115,862,144

Income (Loss) from Operations	50,274,192		23,475,941		(91,551,535)		45,831,822

Other Income (Expense)
Interest income	148,540		69,658		219,069		159,716
Interest (expense)	(8,379,552)		(11,757,404)		(16,979,161)		(21,256,190)
Gain (loss) on derivative contracts	23,724,426		14,648,054		(58,506,499)		13,719,264
Gain (loss) on disposal of assets	104,150		155,293		104,150		279,903
Other income	9,600		150,770		15,437		159,712
Net Other Income (Expense)	15,607,164		3,266,371		(75,147,004)		(6,937,595)

Income (Loss) Before Benefit from (Provision for) Income Taxes	65,881,356		26,742,312		(166,698,539)		38,894,227

Benefit from (Provision for) Income Taxes	(1,088,046)		(6,107,425)		10,900,367		(9,148,602)

Net Income (Loss)	$	64,793,310	$	20,634,887	$	(155,798,172)	$	29,745,625

Basic Earnings (Loss) per Share	$	0.28	$	0.10	$	(0.70)	$	0.15
Diluted Earnings (Loss) per Share	$	0.27	$	0.10	$	(0.70)	$	0.15

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

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RING ENERGY, INC.

CONDENSED STATEMENT OF STOCKHOLDERS’ EQUITY

(Unaudited)


	Common Stock			Additional Paid-in Capital		Retained Earnings (Accumulated Deficit)		Total Stockholders' Equity
For the Six Months Ended June 30, 2026	Shares	Amount
Balance, December 31, 2025	207,656,929	$	207,657	$	812,777,586	$	29,019,999	$	842,005,242



Restricted stock vested	2,400,525	2,401		(2,401)		—		—
Shares to cover tax withholdings for restricted stock vested	(662,344)	(663)		663		—		—
Payments to cover tax withholdings for restricted stock vested, net	—	—		(960,620)		—		(960,620)


Share-based compensation	—	—		1,524,808		—		1,524,808
Net loss	—	—		—		(220,591,482)		(220,591,482)
Balance, March 31, 2026	209,395,110	$	209,395	$	813,340,036	$	(191,571,483)	$	621,977,948



Restricted stock vested	20,000	20		(20)		—		—
Shares to cover tax withholdings for restricted stock vested	(5,930)	(6)		6		—		—



Share-based compensation	—	—		2,149,596		—		2,149,596
Issuance of shares for underwritten public offering	51,111,111	51,111		64,451,797		—		64,502,908
Net income	—	—		—		64,793,310		64,793,310
Balance, June 30, 2026	260,520,291	$	260,520	$	879,941,415	$	(126,778,173)	$	753,423,762














For the Six Months Ended June 30, 2025
Balance, December 31, 2024	198,561,378	$	198,561	$	800,419,719	$	63,751,198	$	864,369,478



Restricted stock vested	1,983,465	1,983		(1,983)		—		—
Shares to cover tax withholdings for restricted stock vested	(488,596)	(488)		488		—		—
Payments to cover tax withholdings for restricted stock vested, net	—	—		(896,431)		—		(896,431)
Common stock issuance for Lime Rock Acquisition	6,452,879	6,453		7,414,358		—		7,420,811

Share-based compensation	—	—		1,690,958		—		1,690,958
Net income	—	—		—		9,110,738		9,110,738
Balance, March 31, 2025	206,509,126	$	206,509	$	808,627,109	$	72,861,936	$	881,695,554



Restricted stock vested	41,834	42		(42)		—		—
Shares to cover tax withholdings for restricted stock vested	(8,345)	(9)		9		—		—
Payments to cover tax withholdings for restricted stock vested, net	—	—		(57,015)		—		(57,015)


Share-based compensation	—	—		1,351,839		—		1,351,839
Net income	—	—		—		20,634,887		20,634,887
Balance, June 30, 2025	206,542,615	$	206,542	$	809,921,900	$	93,496,823	$	903,625,265

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

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RING ENERGY, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)


	For the Six Months Ended
	June 30, 2026		June 30, 2025
Cash Flows From Operating Activities
Net income (loss)	$	(155,798,172)	$	29,745,625
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization	41,520,838		48,185,897
Ceiling test impairment	162,086,257		—
Asset retirement obligation accretion	797,440		708,800
Amortization of deferred financing costs	1,384,990		3,074,667
Share-based compensation	3,674,404		3,042,797
Credit loss expense	92,432		18,122
(Gain) loss on disposal of assets	(104,150)		(279,903)
Deferred income tax expense (benefit)	(11,216,495)		8,755,985
Excess tax expense (benefit) related to share-based compensation	160,892		108,763
(Gain) loss on derivative contracts	58,506,499		(13,719,264)
Cash received (paid) for derivative settlements, net	(23,735,091)		124,249
Changes in operating assets and liabilities:
Accounts receivable	(12,073,415)		(2,373,460)
Inventory	(313,546)		(1,336,734)
Prepaid expenses and other assets	(1,373,055)		(935,483)
Accounts payable	3,717,851		(12,880,531)
Settlement of asset retirement obligation	(643,685)		(571,271)
Net Cash Provided by Operating Activities	66,683,994		61,668,259
Cash Flows From Investing Activities
Payments for Lime Rock Acquisition	—		(70,859,769)

Payments to purchase oil and natural gas properties	(4,393,338)		(797,289)
Payments to develop oil and natural gas properties	(72,435,456)		(49,256,881)
Payments to acquire or improve fixed assets subject to depreciation	—		(169,661)
Proceeds from sale of fixed assets subject to depreciation	100,832		17,360
Proceeds from divestiture of oil and natural gas properties	4,868,950		—



Insurance proceeds received for damage to oil and natural gas properties	—		99,913
Net Cash Used in Investing Activities	(71,859,012)		(120,966,327)
Cash Flows From Financing Activities
Proceeds from revolving line of credit	103,000,000		170,322,997
Payments on revolving line of credit	(163,000,000)		(107,322,997)
Proceeds from issuance of common stock	64,780,500		—

Payments for taxes withheld on vested restricted shares, net	(965)		(953,446)
Proceeds from notes payable	1,657,810		1,648,539
Payments on notes payable	(667,258)		(656,517)
Payment of deferred financing costs	(35,460)		(5,381,602)
Reduction of financing lease liabilities	(325,112)		(225,301)
Net Cash Provided by (Used in) Financing Activities	5,409,515		57,431,673
Net Increase (Decrease) in Cash	234,497		(1,866,395)
Cash at Beginning of Period	902,913		1,866,395
Cash at End of Period	$	1,137,410	$	—

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RING ENERGY, INC.

CONDENSED STATEMENTS OF CASH FLOWS (CONTINUED)

(Unaudited)


	For the Six Months Ended
	June 30, 2026		June 30, 2025
Supplemental Cash Flow Information
Cash paid for interest	$	16,454,079	$	20,958,502
Cash paid (refunded) for income taxes	(3,295)		(62,513)

Noncash Investing and Financing Activities
Asset retirement obligation incurred during development	$	26,854	$	23,158
Asset retirement obligation acquired	—		2,587,179
Asset retirement obligation revision of estimate	233,184		—
Asset retirement obligation sold	(51,635)		—


Financing lease assets obtained in exchange for new financing lease liability, net (1)	92,445		264,114

Change in capitalized expenditures attributable to drilling projects financed through current liabilities	2,989,952		(781,392)
Offering costs incurred and not yet paid	277,592		—















Lime Rock Acquisition Supplemental Schedule
Investing Activities - Cash Paid
Cash paid to Lime Rock on closing	$	—	$	63,599,939
Escrow deposit released at closing	—		5,000,000
Direct transaction costs	—		2,294,105

Cash paid for fixed assets acquired	—		(34,275)



Payments for the Lime Rock Acquisition	$	—	$	70,859,769
Investing Activities - Noncash
Assumption of suspense liability	$	—	$	561,977


Assumption of asset retirement obligation	—		2,587,179
Deferred cash payment at fair value	—		9,415,066
Financing Activities - Noncash
Common stock issued for acquisition	$	—	$	7,420,811

(1) Included within the financing lease assets obtained in exchange for new financing lease liability, net is $216,608 of finance lease asset terminations for the six months ended June 30, 2026. For the six months ended June 30, 2025, the Company had $95,845 in finance lease asset terminations.

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

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RING ENERGY, INC.

NOTES TO CONDENSED FINANCIAL STATEMENTS

(UNAUDITED)

Index to the Notes to the Condensed Financial Statements


Note 1 — Basis of Presentation & Significant Accounting Policies			Note 8 — Revolving Line of Credit
Note 2 — Revenue Recognition			Note 9 — Asset Retirement Obligation
Note 3 — Leases			Note 10 — Common Warrants and Equity Offering
Note 4 — Earnings (Loss) Per Share Information			Note 11 — Share-Based Compensation
Note 5 — Acquisitions and Divestitures			Note 12 — Commitments and Contingencies
Note 6 — Derivative Financial Instruments			Note 13 — Segment Reporting
Note 7 — Fair Value Measurements			Note 14 — Subsequent Events

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 six months ended June 30, 2026 are not necessarily indicative of the results to be expected for the full year ending December 31, 2026, 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, 2025.

Organization and Nature of Operations – Ring Energy is a growth oriented independent oil and natural gas 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 in Texas.

Correction of an Immaterial Error – In connection with the preparation of our condensed financial statements for the three months ended March 31, 2026, we identified an immaterial error that existed in our previously issued financial statements. We determined that certain revenues held in suspense deriving from operations during the annual and interim periods for fiscal years 2017 through 2025 were done so in error, and as such the Company made corrections to the prior period financial statements resulting in a decrease to Accounts payable of $7.3 million as of December 31, 2025, an increase to Retained earnings (Accumulated deficit) of $5.7 million as of December 31, 2024 and 2025, and an increase to Deferred income taxes of $1.5 million as of December 31, 2025. This error is a result of the incorrect initial assignment of ownership interests for other interest owners without consideration of recovery of capital and normal operating costs by Ring. We evaluated the materiality of this error and quantified the effect of prior period misstatements on financial statements and have determined that the impact of this error on our prior period financial statements is immaterial. We have revised the prior period amounts to correct this immaterial error.

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.

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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 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.

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 $887,410 and $652,913 as of June 30, 2026 and December 31, 2025, respectively. The Company places its cash with a high credit quality financial institution. The Company has not experienced any losses in such accounts and believes it is not exposed to significant credit risk in this area.

Accounts receivable – Substantially all of the Company’s accounts receivable is from purchasers of oil and natural gas. Oil and natural gas sales are generally unsecured. Accounts receivable from purchasers outstanding longer than the contractual payment terms are considered past due. The Company has not had any significant credit losses in the past and believes its accounts receivable are materially collectable. During the six months ended June 30, 2026, sales to three purchasers represented 72%, 13% and 11%, respectively, of total oil, natural gas, and natural gas liquids sales. As of June 30, 2026, receivables outstanding from these three purchasers represented 72%, 13% and 9%, respectively, of accounts receivable.

The following table reflects the Company's beginning and ending balances of its accounts receivables from purchasers of its oil and gas for the three and six months ended June 30, 2026 and June 30, 2025.

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	For the Three Months Ended
	June 30, 2026		June 30, 2025
Beginning balance of accounts receivable from purchasers of oil and gas	$	43,249,561	$	35,111,264
Ending balance of accounts receivable from purchasers of oil and gas	41,907,240		36,251,914


	For the Six Months Ended
	June 30, 2026		June 30, 2025
Beginning balance of accounts receivable from purchasers of oil and gas	$	29,591,571	$	33,774,968
Ending balance of accounts receivable from purchasers of oil and gas	41,907,240		36,251,914

The following table indicates the Company's provisions for credit loss expense associated with its accounts receivable from purchasers of its oil and gas ("O&G") during the three and six months ended June 30, 2026 and June 30, 2025.


	For the Three Months Ended				For the Six Months Ended
	June 30, 2026		June 30, 2025		June 30, 2026		June 30, 2025
Credit loss expense, O&G	$	92,432	$	—	$	92,432	$	—

The following table reflects the Company's accounts receivable from purchasers of its oil and gas and allowance for credit losses as of June 30, 2026 and December 31, 2025.


	June 30, 2026		December 31, 2025
Accounts receivable from purchasers of oil and gas	$	41,999,672	$	29,591,571
Allowance for credit losses	(92,432)		—
Accounts receivable from purchasers of oil and gas, net	$	41,907,240	$	29,591,571

Joint interest billing receivables, net – The Company also has joint interest billing ("JIB") 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 credit loss expense associated with its joint interest billing receivables during the three and six months ended June 30, 2026 and June 30, 2025.


	For the Three Months Ended				For the Six Months Ended
	June 30, 2026		June 30, 2025		June 30, 2026		June 30, 2025
Credit loss expense, JIB	$	—	$	205	$	—	$	18,122

The following table reflects the Company's joint interest billing receivables and allowance for credit losses as of June 30, 2026 and December 31, 2025.


	June 30, 2026		December 31, 2025
Joint interest billing receivables	$	1,284,130	$	1,824,753
Allowance for credit losses	(200,762)		(200,762)
Joint interest billing receivables, net	$	1,083,368	$	1,623,991

For receivables, the Company's estimated credit loss allowance is estimated using historical loss information, current industry conditions and payment practices, as well as reasonable and supportable forecasts of future economic conditions. Credit risk is assessed based on days outstanding and other available information. The Company has elected the practical expedient to assume that the current conditions as of the balance sheet date do not change for the remaining life of the receivables.

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

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share of remaining estimated natural gas reserves. The Company recorded no imbalances as of June 30, 2026 or December 31, 2025.

Cash and Cash Equivalents – The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. At June 30, 2026 and December 31, 2025, 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.

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 six months ended June 30, 2026 and 2025.


	For the Three Months Ended				For the Six Months Ended
	June 30, 2026		June 30, 2025		June 30, 2026		June 30, 2025
Depletion	$	19,846,120	$	25,224,638	$	40,971,496	$	47,479,214
Depletion rate, per barrel-of-oil-equivalent (Boe)	$	10.91	$	13.02	$	11.51	$	13.21

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.

Due to the lower oil prices impacting the present value of estimated future net revenues, during the six months ended June 30, 2026, the Company recorded impairments on oil and natural gas properties as a result of the ceiling test of $162,086,257. The Company did not record an impairment on oil and natural gas properties during the three months ended June 30, 2026. No such impairments were recorded during the three and six months ended June 30, 2025.

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Land, Buildings and Structures, Equipment, Software, Leasehold Improvements, Automobiles, and UAV – Land, buildings and structures, equipment, software, leasehold improvements, automobiles, and unmanned aerial vehicles ("UAV") 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 and structures, equipment, software, leasehold improvements, automobiles, and UAV 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 and structures, equipment, software, leasehold improvements, automobiles, and UAV 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
UAV						3 years

The following table provides information on the Company's depreciation expense for the three and six months ended June 30, 2026 and 2025.


	For the Three Months Ended				For the Six Months Ended
	June 30, 2026		June 30, 2025		June 30, 2026		June 30, 2025
Depreciation	$	55,298	$	106,658	$	142,433	$	203,278

During the three and six months ended June 30, 2026 and 2025, the Company recorded a gain (loss) on disposal of assets, which was impacted by the sale of owned vehicles, as follows:


	For the Three Months Ended				For the Six Months Ended
	June 30, 2026		June 30, 2025		June 30, 2026		June 30, 2025
Sale of owned vehicles	$	81,008	$	155,293	$	81,008	$	286,877
Sale of leased vehicles	23,142		—		23,142		(6,974)
Gain (loss) on disposal of assets	$	104,150	$	155,293	$	104,150	$	279,903

Notes Payable – In May 2026, the Company renewed its control of well, general liability, pollution, umbrella, property, workers' compensation, auto, D&O (directors and officers), and drone insurance policies, funding the premiums with a promissory note with a face value after down payments of $1,657,810. The APR for this note is 6.95%. In May 2025, 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 $1,648,539. The APR for this note was 7.75%.

As of June 30, 2026 and December 31, 2025, the notes payable balances included in current liabilities on the Condensed Balance Sheets were $1,496,304 and $505,752, 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 six months ended June 30, 2026 and 2025.


	Three Months Ended						Six Months Ended
	June 30, 2026			June 30, 2025			June 30, 2026			June 30, 2025
Weighted average notes payable balance	$	351,930		$	330,644		$	330,029		$	316,501
Weighted average interest rate on weighted average notes payable	10.91		%	12.88		%	9.79		%	10.85		%

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The following table shows interest paid related to notes payable for the three and six months ended June 30, 2026 and 2025. This interest is included within "Interest (expense)" in the Condensed Statements of Operations.


	Three Months Ended				Six Months Ended
	June 30, 2026		June 30, 2025		June 30, 2026		June 30, 2025
Interest paid for notes payable	$	9,600	$	10,645	$	16,147	$	17,166

Revenue Recognition – 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 the Company engages third party sources to validate the estimates. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration the Company expects to receive in exchange for those products. 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, the Company considers whether a valuation allowance should be recorded for some or all of the deferred tax assets which may not be realized. During the three months ended March 31, 2026, the Company determined that certain existing deferred tax assets will not be offset by existing deferred tax liabilities as a result of the 80% limitation on the utilization net operating losses incurred after 2017. As of June 30, 2026, the Company is in a three-year cumulative loss position mainly driven by the book impairment recognized in the first quarter of 2026. As a result, future forecasted pre-tax book income was not considered in assessing the valuation allowance. We also consider the reversal of deferred tax liabilities and available tax planning strategies. Based on our evaluation of the realizability of the related federal deferred tax assets in the current year, the Company recorded $16.3 million of valuation allowance as part of the estimated annual effective tax rate in the six months ended June 30, 2026. As of December 31, 2025, the Company did not carry a valuation allowance against its federal and state deferred tax assets.

On July 4, 2025, the One Big Beautiful Bill Act ("OBBBA") was enacted, that, among other items, allows for 100% bonus depreciation on a permanent basis for certain property acquired after January 19, 2025. Further, the OBBBA basis for Section 163(j) of the Internal Revenue Code of 1986, as amended (the "Code"), net interest expense deduction is based on EBITDA (earnings before interest, taxes, depreciation and amortization) rather than EBIT (earnings before interest and taxes) for taxable years beginning after December 31, 2024, and any disallowed interest expense can be carried forward indefinitely. We incorporated these changes into our income tax provision beginning in the third quarter of 2025.

The Company recorded the following federal and state income tax benefits (provisions) for the three and six months ended June 30, 2026 and 2025.


	For the Three Months Ended				For the Six Months Ended
	June 30, 2026		June 30, 2025		June 30, 2026		June 30, 2025
Deferred federal income tax benefit (provision)	$	(542,196)	$	(5,776,325)	$	10,160,342	$	(8,592,403)
Current state income tax (provision)	(59,649)		(147,461)		(155,236)		(283,854)
Deferred state income tax benefit (provision)	(486,201)		(183,639)		895,261		(272,345)
Benefit from (Provision for) Income Taxes	$	(1,088,046)	$	(6,107,425)	$	10,900,367	$	(9,148,602)

Effective tax rate (1)	1.65%		22.84%		6.54%		23.52%

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(1) The Company’s overall effective tax rate is calculated as Benefit from (Provision for) Income Taxes divided by Income (Loss) Before Benefit from (Provision for) Income Taxes. The effective tax rates for the three and six months ended June 30, 2026 were lower than the federal statutory corporate tax rate, primarily impacted by the recording of a valuation allowance on the Company's federal net deferred tax assets. A tax expense of $16.3 million was recorded as part of the estimated annual effective tax rate in the six months ended June 30, 2026. The effective tax rates for the three and six months ended June 30, 2025 were higher than the federal statutory corporate tax rates, primarily impacted by state income taxes.

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, 2022 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 2021 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 – Upon adoption of ASU 2016-02, 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 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 adoption. 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 per share is 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 — SHARE-BASED COMPENSATION". 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.

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 six months ended June 30, 2026 and 2025.


	Three Months Ended				Six Months Ended
	June 30, 2026		June 30, 2025		June 30, 2026		June 30, 2025
Share-based compensation	$	2,149,596	$	1,351,839	$	3,674,404	$	3,042,797

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

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the commodity derivative contracts are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company for its oil and natural gas production.

As the Company has not designated its derivative instruments as hedges for accounting purposes, any gains or losses resulting from changes in fair value of outstanding derivative financial instruments and from the settlement of derivative financial instruments are recognized in earnings and included as a component of Other Income (Expense) in the 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. Refer to "NOTE 6 — DERIVATIVE FINANCIAL INSTRUMENTS" 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.

Recently Adopted Accounting Pronouncements – 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.

In July 2025, the FASB issued ASU 2025-05, "Financial Instruments - Credit Losses (Topic 326) - Measurement of Credit Losses for Accounts Receivable and Contract Assets," that provides for a practical expedient for estimating expected credit losses which assumes that current conditions as of the balance sheet date do not change for the remaining life of the asset. The amendments are effective prospectively for annual reporting periods beginning after December 15, 2025, and interim periods within those annual reporting periods. The Company adopted ASU 2025-05 effective January 1, 2026, electing the practical expedient for its accounts receivable to assume that the current conditions as of the balance sheet date do not change for the remaining life of the asset.

Recent Accounting Pronouncements – 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 2024, the FASB issued ASU 2024-03, "Income Statement – Reporting Comprehensive Income – Expenses Disaggregation Disclosures (Subtopic 220-40) – Disaggregation of Income Statement Expenses" ("ASU 2024-03"). The purpose of this update is to improve the disclosures about a public business entity's expenses and address requests from investors for more detailed information about the types of expenses (including purchases of inventory, employee compensation, depreciation, amortization, and depletion) in commonly presented expense captions (such as cost of sales, SG&A, and research and development). As clarified in ASU 2025-01, "Income Statement – Reporting Comprehensive Income – Expenses Disaggregation Disclosures (Subtopic 220-40) – Clarifying the Effective Date," the amendments in this update are effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods within annual reporting periods beginning after December 15, 2027, with early adoption permitted, and either prospective or

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retrospective application permitted. The Company is currently assessing the impact of adopting this new guidance on its financial disclosures.

In December 2025, the FASB issued ASU 2025-11, "Interim Reporting (Topic 270) - Narrow-Scope Improvements," that is intended to provide clarity on current interim disclosure requirements. The update also includes the addition of a disclosure principle that requires entities to disclose events since the last annual reporting period that have a material impact on the entity. The application of the update is effective for interim reporting periods within annual reporting periods beginning after December 15, 2027, with early adoption permitted, and either prospective or retrospective application permitted. The Company is currently assessing the impact of adopting this new guidance on its interim financial disclosures.

NOTE 2 — REVENUE RECOGNITION

The Company predominantly derives its revenue from the sale of produced crude oil, natural gas, and natural gas liquids ("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 606-10-50-14A, which states an entity is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company’s sales contracts, each unit of production delivered to a purchaser represents a separate performance obligation, therefore, future volumes to be delivered are wholly unsatisfied and disclosure of transaction price allocated to remaining performance obligation is not required. The transaction price includes variable consideration, as product pricing is based on published market prices and adjusted for contract specified differentials such as quality, energy content, and transportation. The guidance does not require that the transaction price be fixed or stated in the contract. Estimating the variable consideration does not require significant judgment and the Company engages third party sources to validate the estimates. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration the Company expects to receive in exchange for those products. Once consideration is received from the purchaser, the Company records any variances between the estimates and actual amounts, which has historically not been significant.

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 majority of the Company’s natural gas sales processing contracts, the Company delivers unprocessed natural gas and NGLs to midstream processing entities at the wellhead, and the midstream processing entities obtain control of the natural gas and NGLs at the wellhead. The midstream processing entities gather and process the natural gas and NGLs and remit 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 purchasers 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.

The Company has only one immaterial agreement with a natural gas processing entity in place where the point of control does not pass at the wellhead. Under this agreement, the point of control of the natural gas dictates that the associated fees are recorded as an expense.

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Disaggregation of revenue – The following table presents revenues disaggregated by product for the three and six months ended June 30, 2026 and 2025.


	For the Three Months Ended				For the Six Months Ended
	June 30, 2026		June 30, 2025		June 30, 2026		June 30, 2025
Oil, Natural Gas, and Natural Gas Liquids Revenues
Oil	$	110,167,205	$	82,778,476	$	186,372,219	$	159,283,526
Natural gas (1)	(9,179,381)		(2,238,937)		(13,475,469)		(2,541,664)
Natural gas liquids	3,693,665		2,063,220		5,456,403		4,952,104
Total oil, natural gas, and natural gas liquids revenues	$	104,681,489	$	82,602,759	$	178,353,153	$	161,693,966

(1) In the three and six months ended June 30, 2026 and 2025, the Company experienced a net negative total gas revenue, due to lower gross realized sales prices per Mcf compared to the plant fees per Mcf.

NOTE 3 — LEASES

The Company has operating leases for its offices in Midland, Texas and The Woodlands, Texas. The Midland office is currently under a five-year lease, effective October 1, 2022. The Woodlands office is currently under a 71-month (five years and 11-month) lease, effective May 9, 2023. The future payments for these office spaces are reflected in the future lease payments schedule below.

The Company has month to month leases for office equipment and compressors used in its operations on which the Company has elected to apply ASU 2016-02 (i.e. 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 are reflected in the short-term lease costs within Lease operating expenses, shown below.

The Company has financing leases for vehicles. These leases have an initial 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 are settled in cash or applied to a new vehicle.

Future lease payments associated with these operating and financing leases as of June 30, 2026 are as follows:


	2026		2027		2028		2029		2030		Other Future Years		Total
Operating lease payments	$	263,518	$	460,497	$	250,606	$	149,628	$	—	$	—	$	1,124,249
Financing lease payments	435,932		581,242		274,736		27,508		—		—		1,319,418

The following table shows the weighted average remaining lease term and the weighted average discount rate for the Company's leases as of the dates indicated.


	As of
	June 30, 2026	December 31, 2025
Operating leases
Weighted average remaining lease term (in years)	2.48	2.71
Weighted average discount rate	4.50%	4.50%

Finance leases
Weighted average remaining lease term (in years)	1.89	1.99
Weighted average discount rate	7.50%	7.50%

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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:


	As of
	June 30, 2026		December 31, 2025
Operating lease liability, current portion	$	491,796	$	586,614
Operating lease liability, non-current portion	569,328		819,223
Operating lease liability, total	$	1,061,124	$	1,405,837
Total undiscounted future cash flows (sum of future operating lease payments)	1,124,249		1,497,380
Imputed interest	63,125		91,543
Undiscounted future cash flows less imputed interest	$	1,061,124	$	1,405,837

Financing lease liability, current portion	$	693,432	$	730,564
Financing lease liability, non-current portion	533,212		593,146
Financing lease liability, total	$	1,226,644	$	1,323,710
Total undiscounted future cash flows (sum of future financing lease payments)	1,319,418		1,428,999
Imputed interest	92,774		105,289
Undiscounted future cash flows less imputed interest	$	1,226,644	$	1,323,710

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


	For the Three Months Ended				For the Six Months Ended
	June 30, 2026		June 30, 2025		June 30, 2026		June 30, 2025
Operating lease costs	$	175,090	$	175,090	$	350,181	$	350,181
Short-term lease costs (1)	791,606		1,260,098		1,634,993		2,412,402
Financing lease costs:
Amortization of financing lease assets (2)	213,472		238,618		406,909		503,405
Interest on financing lease liabilities (3)	25,661		27,638		49,547		56,379

(1)Amount included in Lease operating expenses

(2)Amount included in Depreciation, depletion and amortization

(3)Amount included in Interest (expense)

During the three and six months ended June 30, 2026 and 2025, the Company recorded a gain (loss) on disposal of assets, which was impacted by the sale of leased vehicles, as follows:


	For the Three Months Ended				For the Six Months Ended
	June 30, 2026		June 30, 2025		June 30, 2026		June 30, 2025
Sale of owned vehicles	$	81,008	$	155,293	$	81,008	$	286,877
Sale of leased vehicles	23,142		—		23,142		(6,974)
Gain (loss) on disposal of assets	$	104,150	$	155,293	$	104,150	$	279,903

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NOTE 4 — EARNINGS (LOSS) PER SHARE INFORMATION

The following table presents the calculation of the Company's basic and diluted earnings (loss) per share for the three and six months ended June 30, 2026 and 2025. For all dilutive securities, the treasury stock method of calculating the incremental shares was applied.


	For the Three Months Ended				For the Six Months Ended
	June 30, 2026		June 30, 2025		June 30, 2026		June 30, 2025
Net Income (Loss)	$	64,793,310	$	20,634,887	$	(155,798,172)	$	29,745,625
Basic Weighted-Average Shares Outstanding	233,951,765		206,522,356		221,259,803		202,964,856
Effect of dilutive securities:
Stock options	—		—		—		—
Restricted stock units	2,646,296		341,611		—		852,082
Performance stock units	1,210,428		113,760		—		250,931
Common warrants	—		4,600		—		17,338

Diluted Weighted-Average Shares Outstanding	237,808,489		206,982,327		221,259,803		204,085,207
Basic Earnings (Loss) per Share	$	0.28	$	0.10	$	(0.70)	$	0.15
Diluted Earnings (Loss) per Share	$	0.27	$	0.10	$	(0.70)	$	0.15

The following table presents the securities which were excluded from the Company's computation of diluted earnings (loss) per share for the three and six months ended June 30, 2026 and 2025, as their effect would have been anti-dilutive.


	For the Three Months Ended		For the Six Months Ended
	June 30, 2026	June 30, 2025	June 30, 2026	June 30, 2025
Anti-dilutive securities:
Stock options to purchase common stock	41,275	65,500	46,110	65,500
Unvested restricted stock units	—	3,745,348	7,253,914	2,598,851
Unvested performance stock units	2,495,027	2,570,776	3,464,397	1,000,000

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NOTE 5 — ACQUISITIONS AND DIVESTITURES

Lime Rock Acquisition

On February 25, 2025, the Company, as buyer, and Lime Rock Resources IV-A, L.P. (“LRRA”) and Lime Rock Resources IV-C, L.P. ("LRRC" and with LRRA, "Lime Rock"), as seller, entered into a purchase and sale agreement (the “Purchase Agreement”), which provided that the Company would acquire (the “Lime Rock Acquisition”) interests in oil and gas leases and related property of Lime Rock located in the Central Basin Platform of the Texas Permian Basin in Andrews County, Texas the "Lime Rock Assets"). On March 31, 2025, the Company and Lime Rock consummated the transactions contemplated in the Lime Rock Acquisition whereby the Company acquired the Lime Rock Assets for aggregate consideration consisting of: (i) approximately $69.3 million in cash, net of customary purchase price adjustments, paid at the closing of the Lime Rock Acquisition, (ii) $10.0 million paid on December 31, 2025, and (iii) 6,452,879 shares of common stock.

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


Consideration:
Common stock consideration
Shares of common stock issued	6,452,879
Common stock price as of March 31, 2025	$	1.15
Total common stock consideration	$	7,420,811
Cash consideration
Escrow deposit released at closing	$	5,000,000
Closing amount paid to Lime Rock	63,599,939

Fair value of deferred payment liability	9,415,066
Post-close adjustments	721,116
Total cash consideration	$	78,736,121
Direct transaction costs	2,576,648
Total consideration	$	88,733,580

Fair value of assets acquired:
Oil and natural gas properties	$	92,111,309
Fixed assets	34,275
Joint interest billing receivable	39,820
Amount attributable to assets acquired	$	92,185,404
Fair value of liabilities assumed:
Suspense liability	$	459,096
Asset retirement obligations	2,587,179
Ad valorem tax liability	405,549
Amount attributable to liabilities assumed	$	3,451,824
Net assets acquired	$	88,733,580

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Non-Operated Interest Sale

On January 30, 2026, the Company completed the sale of certain non-operated interests in Yoakum County, Texas and Lea County, New Mexico. The purchase price was $4.5 million, and cash consideration received was approximately $4.3 million. The sale had an effective date of January 1, 2026.

Yoakum County Acquisition

On February 11, 2026, the Company completed the acquisition of a working interest partner's interest in certain existing horizontal wells in Yoakum County, Texas. The acquisition also included interest attributable to five one-mile horizontal wells drilled and completed in the Northwest Shelf in the first quarter of 2026. Cash consideration paid was approximately $2.0 million. The acquisition had an effective date of January 1, 2026.

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 West Texas Intermediate ("WTI") crude oil prices and natural gas contracts 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 (Expense)" under the heading "Gain (loss) on derivative contracts" in the accompanying Condensed Statements of Operations.

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


	As of
	June 30, 2026		December 31, 2025
Commodity derivative instruments, marked to market:



Derivatives assets, current	$	6,335,601	$	21,468,134



Derivative assets, noncurrent	$	10,154,821	$	9,739,430

Derivative liabilities, current	$	11,373,096	$	841,193

Derivative liabilities, noncurrent	$	12,035,055	$	2,512,692

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


	For the Three Months Ended				For the Six Months Ended
	June 30, 2026		June 30, 2025		June 30, 2026		June 30, 2025
Oil derivatives:
Realized gain (loss) on oil derivatives	$	(19,617,172)	$	433,301	$	(25,675,828)	$	(206,966)
Unrealized gain (loss) on oil derivatives	39,356,764		12,145,940		(40,436,306)		14,487,365
Gain (loss) on oil derivatives	$	19,739,592	$	12,579,241	$	(66,112,134)	$	14,280,399

Natural gas derivatives:
Realized gain (loss) on natural gas derivatives	$	1,158,092	$	244,542	$	1,940,737	$	331,215
Unrealized gain (loss) on natural gas derivatives	2,826,742		1,824,271		5,664,898		(892,350)
Gain (loss) on natural gas derivatives	$	3,984,834	$	2,068,813	$	7,605,635	$	(561,135)

Gain (loss) on derivative contracts	$	23,724,426	$	14,648,054	$	(58,506,499)	$	13,719,264

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 Six Months Ended
	June 30, 2026		June 30, 2025		June 30, 2026		June 30, 2025
Cash flows from operating activities
Cash received (paid) for oil derivatives	$	(19,617,172)	$	433,301	$	(25,675,828)	$	(206,966)
Cash received (paid) for natural gas derivatives	1,158,092		244,542		1,940,737		331,215
Cash received (paid) for derivative settlements, net	$	(18,459,080)	$	677,843	$	(23,735,091)	$	124,249

The following tables reflect the details of current derivative contracts as of June 30, 2026 (quantities are in barrels (Bbl) for the oil derivative contracts and in million British thermal units (MMBtu) for the natural gas derivative contracts).

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Oil Hedges (WTI)	Q3 2026		Q4 2026		Q1 2027		Q2 2027		Q3 2027		Q4 2027		Q1 2028		Q2 2028

Swaps:
Hedged volume (Bbl)	263,400		529,000		509,500		492,000		432,000		412,963		—		—
Weighted average swap price	$	61.77	$	65.34	$	62.82	$	60.45	$	61.80	$	57.59	$	—	$	—






Two-way collars:
Hedged volume (Bbl)	563,685		368,000		2,935		—		32,910		33,435		430,080		415,580
Weighted average put price	$	60.82	$	65.00	$	62.50	$	—	$	60.00	$	60.00	$	55.59	$	57.50
Weighted average call price	$	76.19	$	80.00	$	73.65	$	—	$	72.30	$	72.30	$	66.02	$	73.02


Gas Hedges (Henry Hub)	Q3 2026		Q4 2026		Q1 2027		Q2 2027		Q3 2027		Q4 2027		Q1 2028		Q2 2028

NYMEX Swaps:
Hedged volume (MMBtu)	600,016		1,072,305		439,678		423,035		1,079,906		1,046,151		1,012,567		984,322
Weighted average swap price	$	4.19	$	3.99	$	4.02	$	4.02	$	3.86	$	4.02	$	3.77	$	3.77

Two-way collars:
Hedged volume (MMBtu)	648,728		128,000		717,000		694,000		—		—		—		—
Weighted average put price	$	3.10	$	3.50	$	3.99	$	3.00	$	—	$	—	$	—	$	—
Weighted average call price	$	4.24	$	5.42	$	5.21	$	4.32	$	—	$	—	$	—	$	—


Gas Hedges (Henry Hub)	Q3 2028		Q4 2028		Q1 2029		Q2 2029		Q3 2029		Q4 2029		Q1 2030

NYMEX Swaps:
Hedged volume (MMBtu)	956,865		931,539		908,117		886,933		866,585		846,134		—
Weighted average swap price	$	3.77	$	3.77	$	3.67	$	3.67	$	3.67	$	3.67	$	—


Gas Hedges (basis differential)	Q3 2026		Q4 2026		Q1 2027		Q2 2027		Q3 2027		Q4 2027		Q1 2028		Q2 2028

Waha basis swaps:
Hedged volume (MMBtu)	374,623		411,451		196,372		480,325		464,360		449,846		435,403		—
Weighted average spread price (1)	$	2.15	$	1.81	$	0.78	$	0.78	$	0.78	$	0.78	$	0.68	$	—

El Paso Permian Basin basis swaps:
Hedged volume (MMBtu)	874,121		788,851		960,307		636,710		615,547		596,306		577,163		—
Weighted average spread price (1)	$	2.16	$	1.92	$	0.72	$	0.67	$	0.67	$	0.67	$	0.60	$	—

(1) The gas basis swap hedges are calculated as the Henry Hub natural gas price less the fixed amount specified as the weighted average spread price above.

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NOTE 7 — FAIR VALUE MEASUREMENTS

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


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

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

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

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

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

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

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The following table summarizes the valuation of our assets and liabilities that are measured at fair value on a recurring basis (further detail in "NOTE 6 — DERIVATIVE FINANCIAL INSTRUMENTS").


	Fair Value Measurement Classification
	Quoted prices in Active Markets for Identical Assets or (Liabilities) (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
As of December 31, 2025

Commodity Derivatives - Assets	$	—	$	31,207,564	$	—	$	31,207,564
Commodity Derivatives - Liabilities	$	—	$	(3,353,885)	$	—	$	(3,353,885)

Total	$	—	$	27,853,679	$	—	$	27,853,679

As of June 30, 2026

Commodity Derivatives - Assets	$	—	$	16,490,422	$	—	$	16,490,422
Commodity Derivatives - Liabilities	$	—	$	(23,408,151)	$	—	$	(23,408,151)

Total	$	—	$	(6,917,729)	$	—	$	(6,917,729)

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.

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NOTE 8 — REVOLVING LINE OF CREDIT

On June 18, 2025, the Company, as borrower, Bank of America, N.A. as the Administrative Agent and Issuing Bank, and the lenders party thereto (the "Lenders") entered into that certain Third Amended and Restated Credit Agreement (as amended, the "Credit Agreement"), with a maximum borrowing base of $1 billion secured by substantially all of the assets of the Company and a maturity date of June 2029.

The Credit Agreement has a borrowing base of $585 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.

The Credit Agreement permits the Company to declare restricted payments (including dividends) for its equity owners, subject to certain limitations, including (a) (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, income tax expense, depreciation, depletion 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 Credit Agreement), and (iv) the Borrowing Base Utilization Percentage (as defined in the Credit Agreement) is not greater than 80%; or (b) (i) no default or event of default has occurred or will occur upon such payments, (ii) the pro forma Leverage Ratio does not exceed 1.50 to 1.00, and (iii) the Borrowing Base Utilization Percentage is not greater than 75%.

The reference rate in the Credit Agreement with respect to determination of the interest rate is the Secured Overnight Financing Rate ("SOFR"). The interest rate on each SOFR Loan will be (i) the adjusted term SOFR for the applicable interest period plus (ii) a margin between 2.75% and 3.75% (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 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) 1.00% per annum, plus (b) a margin between 1.75% and 2.75% per annum (depending on the then-current level of borrowing base usage).

The Credit Agreement contains certain covenants, that, 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 Credit Agreement) of 1.0 to 1.0. The 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, on any hedge testing date, (a) if the borrowing base utilization is less than 25% 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 (b) 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 June 30, 2026, $360 million was outstanding on the Credit Facility and the Company was in compliance with all covenants in the Credit Agreement.

Under the Credit Agreement, the applicable percentage for the unused commitment fee is 0.5% per annum for all levels of borrowing base utilization. As of June 30, 2026, the Company's unused line of credit was approximately $225.0 million, which was calculated by subtracting the outstanding Credit Facility balance of $360 million and standby letters of credit of $35,000 in total ($10,000 with a federal agency and $25,000 with an insurance company for New Mexico state surety bonds) from the $585 million borrowing base.

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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 six months ended June 30, 2026 is as follows:


Balance, December 31, 2025	$	30,390,955
Liabilities acquired	—
Liabilities incurred	26,854
Liabilities sold	(51,635)
Liabilities settled	(281,953)
Revision of estimate (1)	233,184
Accretion expense	797,440
Balance, June 30, 2026	$	31,114,845

(1) The revisions recorded during the six months ended June 30, 2026 consisted of additional acquired working interests in certain wells.

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


	June 30, 2026		December 31, 2025
Asset retirement obligations, current	$	291,844	$	418,526
Asset retirement obligations, non-current	30,823,001		29,972,429
Asset retirement obligations	$	31,114,845	$	30,390,955

NOTE 10 — COMMON WARRANTS AND EQUITY OFFERING

Common Warrants – During the year ended December 31, 2024 and through October 2025, the Company had 78,200 exercisable common warrants outstanding, with a contractual exercise price of $0.80 per warrant. All of the common warrants expired in October 2025. During the six months ended June 30, 2025, no common warrants were exercised.

Equity Offering – On May 14, 2026, the Company completed an underwritten public offering of 44,444,445 shares of common stock at a public offering price of $1.35 per share and gross proceeds of $60.0 million. On June 12, 2026, the underwriters exercised an option to purchase an additional 6,666,666 shares of common stock at a public offering price of $1.35 per share and gross proceeds of $9.0 million. The sale of common stock resulted in total gross proceeds of $69.0 million and net proceeds of $64.5 million, after deducting underwriting fees and offering expenses.

Common Warrants

Exercise Price

Proceeds Received

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NOTE 11 — SHARE-BASED COMPENSATION

Share-based compensation expense charged against income for share-based awards during the three and six months ended June 30, 2026 and 2025 was as follows. These amounts are included in General and administrative expense in the Condensed Statements of Operations.


	Three Months Ended				Six Months Ended
	June 30, 2026		June 30, 2025		June 30, 2026		June 30, 2025
Share-based compensation expense from:
Employee stock options	$	—	$	—	$	—	$	—
Restricted stock unit grants	1,445,550		1,022,645		2,730,333		2,269,974
Performance stock unit awards	704,046		329,194		944,071		772,823
Total share-based compensation	$	2,149,596	$	1,351,839	$	3,674,404	$	3,042,797

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 stockholders. As of June 30, 2026, there were no shares available for grant under the 2011 Plan.

In 2021, the Board and Company stockholders approved and adopted the Ring Energy, Inc. 2021 Omnibus Incentive Plan (as amended, 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. As of June 30, 2026, there were 3,424,002 shares available for grant under the 2021 Plan.

In connection with the hiring of the Company’s Executive Vice President and Chief Financial Officer in February 2026, the Board approved inducement awards to the executive officer that are comprised of 317,460 (the “Inducement RSUs”) restricted stock units (“RSUs”) and 476,190 performance stock units (“PSUs”) (for which up to 952,380 shares may be earned) (the “Inducement PSUs”). The Inducement RSUs will vest in three equal annual installments beginning on March 5, 2027, subject to continued service through the applicable vesting date. The Inducement PSUs have a performance period of January 1, 2026 to December 31, 2028, subject to performance goals and continued service through December 31, 2028. These inducement awards were granted outside of the 2021 Plan; however, they have terms and conditions consistent with those set forth under the 2021 Plan and generally vest under the same respective vesting schedules as RSU and PSU awards granted under the 2021 Plan. The Inducement RSUs are included in the RSU award table below. The Inducement PSUs are included in the PSU award table below.

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Employee Stock Options

A summary of the status of the stock options as of June 30, 2026 and 2025 and changes during the respective six month periods then ended are as follows:


	Options	Weighted- Average Exercise Price		Weighted-Average Remaining Contractual Term	Aggregate Intrinsic Value
Outstanding, December 31, 2024	65,500	$	10.70
Granted	—	—
Forfeited	—	—
Expired	—	—
Exercised	—	—
Outstanding, March 31, 2025	65,500	$	10.70	1.31 years	$	—
Exercisable, March 31, 2025	65,500	$	10.70	1.31 years
Granted	—	—
Forfeited	—	—
Expired	—	—
Exercised	—	—
Outstanding, June 30, 2025	65,500	$	10.70	1.06 years	$	—
Exercisable, June 30, 2025	65,500	$	10.70	1.06 years







Outstanding, December 31, 2025	51,000	$	10.18
Granted	—	—
Forfeited	—	—
Expired	—	—
Exercised	—	—
Outstanding, March 31, 2026	51,000	$	10.18	0.52 years	$	—
Exercisable, March 31, 2026	51,000	$	10.18	0.52 years
Granted	—	—
Forfeited	—	—
Expired	(15,000)	$	6.42
Exercised	—	—
Outstanding, June 30, 2026	36,000	$	11.75	0.45 years	$	—
Exercisable, June 30, 2026	36,000	$	11.75	0.45 years

The intrinsic values were calculated using the closing price on June 30, 2026 of $1.08 and the closing price on June 30, 2025 of $0.79. As of June 30, 2026, the Company had $0 of unrecognized compensation cost related to stock options.

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Restricted Stock Units

A summary of the RSUs outstanding as of June 30, 2026 and 2025, respectively, and changes during the respective six month periods then ended are as follows:


	Restricted Stock Units	Weighted- Average Grant Date Fair Value
Outstanding, December 31, 2024	3,817,128	$	1.70
Granted	3,691,373	1.31
Forfeited or rescinded	—	—
Vested	(1,983,465)	1.75
Outstanding, March 31, 2025	5,525,036	$	1.42
Granted	76,177	0.92
Forfeited or rescinded	(86,238)	1.31
Vested	(41,834)	2.12
Outstanding, June 30, 2025	5,473,141	$	1.41





Outstanding, December 31, 2025	4,912,110	$	1.40
Granted	5,716,485	1.28
Forfeited or rescinded	(39,395)	1.29
Vested	(2,400,525)	1.46
Outstanding, March 31, 2026	8,188,675	$	1.29
Granted	25,000	1.33
Forfeited or rescinded	(79,768)	1.28
Vested	(20,000)	2.04
Outstanding, June 30, 2026	8,113,907	$	1.29

As of June 30, 2026, the Company had $6,944,824 of unrecognized compensation cost related to RSU grants that will be recognized over a weighted average period of 2.25 years. Grant activity for the six months ended June 30, 2026 was primarily RSU grants for the annual long-term incentive plan awards for employees.

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Performance Stock Units

A summary of the PSUs outstanding as of June 30, 2026 and 2025, respectively, along with changes during the respective six month periods then ended are as follows:


	Performance Stock Units	Weighted- Average Grant Date Fair Value
Outstanding, December 31, 2024	1,891,892	$	2.47
Granted	—	—
Forfeited or rescinded	—	—
Vested	—	—
Outstanding, March 31, 2025	1,891,892	$	2.47
Granted	1,624,756	$	0.93
Forfeited or rescinded	—	$	—
Vested	—	$	—
Outstanding, June 30, 2025	3,516,648	$	1.76





Outstanding, December 31, 2025	2,209,991	$	1.42
Granted	—	—
Forfeited or rescinded	—	—
Vested	—	—
Outstanding, March 31, 2026	2,209,991	$	1.42
Granted	3,547,617	$	2.18
Forfeited or rescinded	—	$	—
Vested	—	$	—
Outstanding, June 30, 2026	5,757,608	$	1.89

As of June 30, 2026, the Company had $8,388,870 of unrecognized compensation cost related to the PSU awards that will be recognized over a weighted average period of 2.32 years.

NOTE 12 — COMMITMENTS AND CONTINGENCIES

Surety Bonds – As of June 30, 2026, the Company had $3,582,614 in total surety bonds. As of December 31, 2025, the Company had $2,275,000 in total surety bonds. A Texas Railroad Commission ("RRC") required blanket performance bond to operate 100 or more wells in the State of Texas in the amount of $250,000 and another RRC required blanket plugging extension bond in the amount of $2,000,000. Both RRC bonds have zero collateral requirements. A surety bond in the amount of $25,000 to operate wells in the State of New Mexico was also in place as of June 30, 2026 and December 31, 2025; however, that bond will likely be released as the Company no longer operates wells in New Mexico. In February 2026, the Company added an RRC required bond in the amount of $99,740 covering a produced water recycling pit. In April 2026, the Company obtained an RRC required bond in the amount of $1,207,874 covering another produced water recycling pit. Total expenses related to the surety bonds were $27,441 and $15,000 for the six months ended June 30, 2026 and 2025, respectively. The New Mexico bond is supported by a $25,000 standby letter of credit collateralized by the Credit Facility.

Standby Letters of Credit – As of June 30, 2026 and December 31, 2025, the Company had total standby letters of credit outstanding of $35,000, consisting of a $10,000 standby letter of credit in favor of a federal agency and a $25,000 standby letter of credit issued to support bonding requirements related to the Company's former operations in the State of New Mexico. The Company no longer conducts operations in New Mexico and expects the standby letter of credit related to the New Mexico bonding requirements to be released, subject to regulatory approval. No amounts had been drawn under either standby letter of credit as of June 30, 2026 and December 31, 2025, and no liability has been recorded in the accompanying Condensed Balance Sheets related to these arrangements.

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NOTE 13 — SEGMENT REPORTING

In accordance with ASU 2023-07 "Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures," the Company has performed an assessment of its reporting to comply with the new requirements for the fiscal year beginning January 1, 2024 and for interim periods beginning January 1, 2025. The Company's operations consist of the exploration, production, and sale of oil, natural gas, and NGLs, primarily within the Permian Basin of Texas, and is regulated by the RRC. The Company operates different areas within the Permian Basin, including the Northwest Shelf and Central Basin Platform.

The Company's operations and financials are managed by one cohesive group of individuals, identified as the chief operating decision maker ("CODM"), consisting of the Chairman of the Board and Chief Executive Officer; Executive Vice President and Chief Financial Officer; Executive Vice President and Chief Operations Officer; Executive Vice President and Chief Exploration Officer; Senior Vice President of Operations; and Vice President and Chief Accounting Officer. The CODM group reviews the Company's operating results, including condensed financial statements on a monthly basis for evaluating performance and determining resource allocation. The significant expense categories provided to the CODM include lease operating expenses; gathering, transportation and processing costs; ad valorem taxes; and oil and natural gas production taxes. Each of these costs are deducted from oil, natural gas, and natural gas liquids revenues by operating segment to arrive at operating segment profit, used to assess performance.

The Company assessed whether its operating segments exhibited similar economic characteristics and whether its operating segments had a similar nature of products, services, production processes, purchaser types/classes, product distribution, and regulatory environment. Each operating segment has similar products (oil, natural gas, and NGLs), similar production processes, similar types of purchasers (midstream companies, or companies with midstream components), similar methods of product delivery, and is governed by the same regulations. After a thorough analysis of each of these factors with regards to the Company's operating segments, it has been determined that it is appropriate to aggregate its operating segments into a single reportable segment, Exploration and Production, which includes all of its revenues, lease operating expenses, gathering, transportation and processing costs, ad valorem taxes, and oil and natural gas production taxes. Refer to the table below.


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2026		2025		2026		2025
Exploration and Production
Oil, natural gas, and natural gas liquids revenues (1)	$	104,681,489	$	82,602,759	$	178,353,153	$	161,693,966
Lease operating expenses (2)	(18,409,462)		(20,245,981)		(36,531,806)		(39,923,533)
Gathering, transportation and processing costs	(101,902)		(133,809)		(218,951)		(337,421)
Ad valorem taxes	(2,202,160)		(1,648,647)		(4,404,697)		(3,180,755)
Oil and natural gas production taxes	(5,047,619)		(3,832,607)		(8,601,510)		(7,417,062)
Exploration and Production segment profit	$	78,920,346	$	56,741,715	$	128,596,189	$	110,835,195

(1) All of the Company's revenues are generated within the Permian Basin within the United States.

(2) The CODM also reviews the following cost categories within lease operating expenses. Refer to the following table.


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2026		2025		2026		2025
Lease operating expenses:


Workovers	$	3,443,178	$	3,173,838	$	6,686,781	$	5,990,047
Other lease operating expenses	$	14,966,284	$	17,072,143	$	29,845,025	$	33,933,486
Total lease operating expenses	$	18,409,462	$	20,245,981	$	36,531,806	$	39,923,533

The following tables include a reconciliation of the total reportable segments' measures of profit or loss to the Company's total income (loss) before income taxes. Additionally included is a reconciliation between the reportable segments' assets to the Company's total assets.

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	For the Three Months Ended June 30, 2026
	Exploration and Production		Corporate		Total Company
Oil, Natural Gas, and Natural Gas Liquids Revenues	$	104,681,489	$	—	$	104,681,489
Lease operating expenses	(18,409,462)		—		(18,409,462)
Gathering, transportation and processing costs	(101,902)		—		(101,902)
Ad valorem taxes	(2,202,160)		—		(2,202,160)
Oil and natural gas production taxes	(5,047,619)		—		(5,047,619)
Depreciation, depletion and amortization (3)	—		(20,114,890)		(20,114,890)
Ceiling test impairment (3)	—		—		—
Asset retirement obligation accretion	—		(401,944)		(401,944)
Operating lease expense	—		(175,090)		(175,090)
General and administrative expense	—		(7,954,230)		(7,954,230)
Interest income	—		148,540		148,540
Interest (expense)	—		(8,379,552)		(8,379,552)
Gain (loss) on derivative contracts	—		23,724,426		23,724,426
Gain (loss) on disposal of assets	—		104,150		104,150
Other income	—		9,600		9,600
Income (Loss) Before Benefit from (Provision for) Income Taxes	$	78,920,346	$	(13,038,990)	$	65,881,356

Total Assets (3)	$	1,251,132,823	$	30,424,273	$	1,281,557,096
Capital expenditures	$	43,169,155	$	—	$	43,169,155

(3) All of the Company's assets are located within the United States. As the CODM does not view depreciation, depletion and amortization or ceiling test impairment as a significant Exploration and Production segment expense, the Company has included these amounts within the Corporate column of the reconciliation table.

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	For the Three Months Ended June 30, 2025
	Exploration and Production		Corporate		Total Company
Oil, Natural Gas, and Natural Gas Liquids Revenues	$	82,602,759	$	—	$	82,602,759
Lease operating expenses	(20,245,981)		—		(20,245,981)
Gathering, transportation and processing costs	(133,809)		—		(133,809)
Ad valorem taxes	(1,648,647)		—		(1,648,647)
Oil and natural gas production taxes	(3,832,607)		—		(3,832,607)
Depreciation, depletion and amortization (3)	—		(25,569,914)		(25,569,914)
Ceiling test impairment (3)	—		—		—
Asset retirement obligation accretion	—		(382,251)		(382,251)
Operating lease expense	—		(175,090)		(175,090)
General and administrative expense	—		(7,138,519)		(7,138,519)
Interest income	—		69,658		69,658
Interest (expense)	—		(11,757,404)		(11,757,404)
Gain (loss) on derivative contracts	—		14,648,054		14,648,054
Gain (loss) on disposal of assets	—		155,293		155,293
Other income	—		150,770		150,770
Income (Loss) Before Benefit from (Provision for) Income Taxes	$	56,741,715	$	(29,999,403)	$	26,742,312

Total Assets (3)	$	1,479,364,319	$	36,966,552	$	1,516,330,871
Capital expenditures	$	16,827,513	$	—	$	16,827,513

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	For the Six months ended June 30, 2026
	Exploration and Production		Corporate		Total Company
Oil, Natural Gas, and Natural Gas Liquids Revenues	$	178,353,153	$	—	$	178,353,153
Lease operating expenses	(36,531,806)		—		(36,531,806)
Gathering, transportation and processing costs	(218,951)		—		(218,951)
Ad valorem taxes	(4,404,697)		—		(4,404,697)
Oil and natural gas production taxes	(8,601,510)		—		(8,601,510)
Depreciation, depletion and amortization (3)	—		(41,520,838)		(41,520,838)
Ceiling test impairment (3)	—		(162,086,257)		(162,086,257)
Asset retirement obligation accretion	—		(797,440)		(797,440)
Operating lease expense	—		(350,181)		(350,181)
General and administrative expense	—		(15,393,008)		(15,393,008)
Interest income	—		219,069		219,069
Interest (expense)	—		(16,979,161)		(16,979,161)
Gain (loss) on derivative contracts	—		(58,506,499)		(58,506,499)
Gain (loss) on disposal of assets	—		104,150		104,150
Other income	—		15,437		15,437
Income (Loss) Before Benefit from (Provision for) Income Taxes	$	128,596,189	$	(295,294,728)	$	(166,698,539)

Total Assets (3)	$	1,251,132,823	$	30,424,273	$	1,281,557,096
Capital expenditures	$	77,674,665	$	—	$	77,674,665

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	For the Six months ended June 30, 2025
	Exploration and Production		Corporate		Total Company
Oil, Natural Gas, and Natural Gas Liquids Revenues	$	161,693,966	$	—	$	161,693,966
Lease operating expenses	(39,923,533)		—		(39,923,533)
Gathering, transportation and processing costs	(337,421)		—		(337,421)
Ad valorem taxes	(3,180,755)		—		(3,180,755)
Oil and natural gas production taxes	(7,417,062)		—		(7,417,062)
Depreciation, depletion and amortization (3)	—		(48,185,897)		(48,185,897)
Ceiling test impairment (3)	—		—		—
Asset retirement obligation accretion	—		(708,800)		(708,800)
Operating lease expense	—		(350,181)		(350,181)
General and administrative expense	—		(15,758,495)		(15,758,495)
Interest income	—		159,716		159,716
Interest (expense)	—		(21,256,190)		(21,256,190)
Gain (loss) on derivative contracts	—		13,719,264		13,719,264
Gain (loss) on disposal of assets	—		279,903		279,903
Other income	—		159,712		159,712
Income (Loss) Before Benefit from (Provision for) Income Taxes	$	110,835,195	$	(71,940,968)	$	38,894,227

Total Assets (3)	$	1,479,364,319	$	36,966,552	$	1,516,330,871
Capital expenditures	$	49,279,044	$	—	$	49,279,044

The following table discloses the purchasers from which 10% or more of revenues were derived in the periods noted.


	For the Three Months Ended June 30,		For the Six Months Ended June 30,
	2026	2025	2026	2025
Purchasers with 10% or more percentage of total revenue (4)
Phillips 66 Company	75%	65%	72%	66%
Concord Energy LLC	11%	14%	11%	13%


Energy Transfer Crude Marketing	13%	11%	13%	*

(4) All the Company's purchasers are within the Exploration and Production operating segment.

* Represents less than 10%.

NOTE 14 — SUBSEQUENT EVENTS

Subsequent to June 30, 2026, the Company completed the acquisition of certain oil and gas leasehold interests. Management evaluated the transaction, and concluded the transaction represents a nonrecognized subsequent event. Accordingly, no adjustments to the accompanying condensed financial statements were required.

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Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our accompanying 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 an independent, growth-oriented oil and natural gas exploration and production company headquartered in The Woodlands, Texas and focused on the Permian Basin. Our operations are concentrated in the Northwest Shelf and Central Basin Platform, where we pursue disciplined development of oil weighted, long life production assets while maintaining a strong focus on capital efficiency, cost control, and balance sheet strength.

Business Description and Plan of Operation

The Company is focused on balancing the reduction of long-term debt with the continued development of our oil and gas properties in order to maintain or grow annual production. We intend to achieve these objectives through disciplined allocation of cash flow generated from operations and, where appropriate, through the sale of non-core assets. In addition, we continue to evaluate potential acquisitions of strategic producing assets with attractive acreage positions that we believe can generate competitive returns for our stockholders.

Our operating strategy is centered on the following priorities:

•Growing production and reserves through disciplined development. Ring seeks to develop its oil-rich resource base through a combination of conventional and horizontal drilling across the Northwest Shelf and Central Basin Platform, with an emphasis on operating within cash flow and generating competitive returns.

•Reducing long-term debt and strengthening the balance sheet. The Company intends to reduce leverage primarily through the use of excess cash flow and, where appropriate, selective non-core asset sales. The Company's field-level margins and asset quality position it to continue deleveraging over time while preserving financial flexibility.

•Employing industry-leading drilling and completion techniques. Ring’s executive team leverages technological advancements in completion design, geological evaluation, and reservoir engineering to optimize well performance and capital efficiency, contributing to a competitive cost structure and generating new organic development opportunities across the Company's asset base.

•Pursuing strategic, accretive acquisitions. The Company has a history of acquiring accretive assets with additional development potential that complement its existing property portfolio. Management intends to continue evaluating acquisition opportunities that improve balance sheet metrics, enhance inventory depth, and are accretive to stockholders. Many of these opportunities are often sourced through the executive team's longstanding operating and transactional relationships in the Permian Basin.

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2026 Developments and Operational Highlights

During the first quarter of 2026, the Company continued execution of its development program across its core operated positions. In the Northwest Shelf (Yoakum County), Ring drilled and completed five one-mile horizontal wells, each with a working interest of approximately 91%. In addition, the Company in the Central Basin Platform (Crane County), completed one previously drilled one-mile horizontal DUC well, and drilled and completed one vertical well, with a 100% working interest.

During the second quarter of 2026, the Company drilled a total of seven wells and completed a total of four wells. Specifically, in the Northwest Shelf the Company drilled and completed one 1.5-mile horizontal well and one 1-mile horizontal well in Yoakum County, with a working interest of approximately 98% and 100%, respectively. In the Central Basin Platform, the Company drilled and completed one 1.5-mile horizontal well in Andrews County with a working interest of approximately 99%, and one 1.5-mile horizontal well in Crane County with a working interest of of approximately 96%. The latter of these two wells, while completed, was not put on pump until the third quarter of 2026 and did not contribute significant volumes in the second quarter of 2026. Also in Crane County, the Company drilled three 2-mile horizontal wells, each with a working interest of 100%, and was in the process of drilling one SWD well. The three 2-mile horizontal wells represent the first laterals of this length drilled by the Company in an area that has been historically developed with vertical wells. All four of these wells are to be completed during the third quarter of 2026.


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

1Q 2026	Northwest Shelf (Horizontal)	5	5	—
	Central Basin Platform (Horizontal) (1)	—	1	—
	Central Basin Platform (Vertical)	1	1	—
	Total	6	7	—

2Q 2026	Northwest Shelf (Horizontal)	2	2	—
	Central Basin Platform (Horizontal)	5	2	3

	Total	7	4	3

(1) The horizontal well completed in the Central Basin Platform in the first quarter of 2026 is the completion of a previously drilled but uncompleted (“DUC”) well.(1) Total does not include the SWD well(s) drilled and completed in the [ ].

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Market Conditions and Commodity Prices

Our financial results are significantly affected by crude oil and natural gas prices. Commodity prices are influenced by numerous factors beyond our control, including changes in domestic and global supply and demand, geopolitical events, macroeconomic conditions, transportation and processing constraints, and other market factors. As a result, commodity prices have been volatile and are expected to remain volatile.

During the second quarter of 2026, crude oil prices remained elevated through much of the quarter before declining toward quarter-end. In addition, natural gas prices in the Permian Basin continued to be adversely affected by regional takeaway constraints and elevated processing and transportation costs. These conditions adversely affected realized natural gas prices during the quarter. The Company continues to monitor market conditions and evaluate available alternatives with respect to the marketing of its production and commodity price risk management activities.

Future changes in commodity prices may materially affect the Company's financial condition, results of operations and cash flows.

Commodity Price Environment and Hedging Impact

During the second quarter of 2026, crude oil prices increased meaningfully relative to the levels when a significant portion of the Company's hedge portfolio was established. As a result, while the Company benefited from higher oil prices, realized settlements on crude oil derivative contracts reduced realized pricing and cash flow relative to unhedged market prices. During the quarter, the Company recognized realized losses on crude oil derivative contracts of approximately $19.6 million.

Our hedge program is largely required under our Credit Facility and was designed to protect cash flows, support liquidity, and provide greater certainty around capital allocation and balance sheet objectives. While our hedge positions reduced participation in higher oil prices during the quarter, they also provide downside protection in a volatile commodity price environment.

The Company continues to evaluate its commodity price risk management strategy and hedge profile in light of requirements under the Credit Facility, market conditions, balance sheet strength, capital allocation priorities, and anticipated commodity price exposure.

Ceiling Test

We perform a ceiling test at the end of each reporting period to evaluate for potential non-cash impairments. Under the full cost method of accounting, the net book value of properties, less related deferred income taxes, may not exceed a calculated “ceiling,” which is defined as the estimated after-tax future net revenues from proved oil and natural gas properties, discounted at an annual rate of 10%. The discounted future net revenues are estimated using spot prices for oil and natural gas, based on the average price during the preceding twelve months. This average is calculated as an unweighted arithmetic mean of the first-day-of-the-month prices for each month within that period, except when changes are fixed and determinable by existing contracts.

Estimating potential future non-cash impairments is complex due to numerous factors affecting the ceiling test calculation, including but not limited to future prices, operating costs, upward or downward reserve revisions, reserve additions, and tax attributes. The amount of any additional non-cash impairment, if any, is not estimable at this time given the uncertainty of these factors.

No impairment was recorded for the three months ended June 30, 2026. For the six months ended June 30, 2026, the Company recorded a non-cash impairment charge of $162.1 million as a result of lower oil prices impacting the present value of estimated future net revenues.

Natural Gas Takeaway Capacity

The Permian Basin has been experiencing a lack of sufficient pipeline transportation that is connected to markets that are purchasing the natural gas produced. This has resulted in negative natural gas prices for us in 2025 and continuing through 2026 to date, whereby we actually pay the purchaser to take our natural gas. These 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.

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Inflation

Inflation has increased costs associated with our capital program and production operations. We have experienced increases in the costs of many of the materials, supplies, equipment and services used in our operations and we expect inflation to continue based on current economic circumstances, including tariffs, trade wars, and supply chain disruptions. We continue to closely monitor costs and take all reasonable steps to mitigate the inflationary effect on our cost structure and also work to enhance our efficiency to minimize additional cost increases where possible.

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Results of Operations

Oil, Natural Gas, and Natural Gas Liquids Revenues for the Three Months Ended June 30, 2026 and 2025


	For the Three Months Ended
	June 30, 2026		June 30, 2025		Change		% Change
Net sales:
Oil	$	110,167,205	$	82,778,476	$	27,388,729	33	%
Natural gas	(9,179,381)		(2,238,937)		(6,940,444)		(310)	%
Natural gas liquids	3,693,665		2,063,220		1,630,445		79	%
Total sales	$	104,681,489	$	82,602,759	$	22,078,730	27	%

Net production:
Oil (Bbls)	1,154,147		1,320,508		(166,361)		(13)	%
Natural gas (Mcf)	1,764,659		1,703,808		60,851		4	%
Natural gas liquids (Bbls)	370,819		333,374		37,445		11	%
Total production (Boe)(1)	1,819,076		1,937,850		(118,774)		(6)	%

Average sales price:
Oil (per Bbl)	$	95.45	$	62.69	$	32.76	52	%
Natural gas (per Mcf)	(5.20)		(1.31)		(3.89)		(297)	%
Natural gas liquids (Bbl)	9.96		6.19		3.77		61	%
Total per Boe	$	57.55	$	42.63	$	14.92	35	%

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

Oil sales. Oil sales increased approximately $27.4 million from $82.8 million to $110.2 million, driven by a price variance of $37.8 million from an increase in the average realized price per barrel from $62.69 to $95.45 as a result of higher oil commodity prices. This was offset by a volume variance of $(10.4) million from a decrease in sales volume from 1,320,508 barrels to 1,154,147 barrels. The decrease in volume of (166,361) barrels was attributed to natural production declines from our legacy assets.

Natural gas sales. Natural gas sales decreased approximately $6.9 million from a negative $2.2 million to a negative $9.2 million. Our natural gas sales volumes increased from 1,703,808 Mcf to 1,764,659 Mcf, and the average realized price per Mcf decreased from $(1.31) to $(5.20). Of the increase in volume of 60,851 Mcf, an increase of 30,268 Mcf was from the wells acquired and drilled in the Lime Rock acquisition area and an increase of 30,583 Mcf was attributable to legacy assets. The price decrease was driven by depressed market conditions. The realized revenue pricing included the impact of gas plant processing fees that were netted from revenue. For the three months ended June 30, 2026, gross revenues were $(3.01) per Mcf and fees were $(2.19) per Mcf, compared to gross revenues of $0.87 per Mcf and fees of $(2.18) per Mcf for the three months ended June 30, 2025. This resulted in a net realized price of $(5.20) per Mcf for the three months ended June 30, 2026 compared to $(1.31) per Mcf for the three months ended June 30, 2025.

Natural gas liquids sales. NGL sales increased approximately $1.6 million from $2.1 million to $3.7 million. NGL sales volumes for the three months ended June 30, 2026 were 370,819 barrels compared to 333,374 barrels for the comparable period in 2025. Of the increase in volume of 37,445 barrels, 17,360 barrels were attributable to wells acquired and drilled in the Lime Rock acquisition area, and an increase of 20,085 barrels was attributable to our legacy assets in correlation with gas sales. The average realized price per barrel of NGLs was $9.96 for the three months ended June 30, 2026 compared to $6.19 for the three months ended June 30, 2025, due to stronger market conditions. Specifically, the gross realized price per NGL barrel was $22.38 and the average fees per barrel were $(12.42), resulting in a net realized price of $9.96 for the three months ended June 30, 2026, while the gross realized price per NGL barrel was $19.02 and the average fees per barrel were $(12.83), resulting in a net realized price of $6.19 for the same period in 2025.

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Oil, Natural Gas, and Natural Gas Liquids Revenues for the Six Months Ended June 30, 2026 and 2025


	For the Six Months Ended
	June 30, 2026		June 30, 2025		Change		% Change
Net sales:
Oil	$	186,372,219	$	159,283,526	$	27,088,693	17	%
Natural gas	(13,475,469)		(2,541,664)		(10,933,805)		(430)	%
Natural gas liquids	5,456,403		4,952,104		504,299		10	%
Total sales	$	178,353,153	$	161,693,966	$	16,659,187	10	%

Net production:
Oil (Bbls)	2,258,970		2,407,202		(148,232)		(6)	%
Natural gas (Mcf)	3,454,171		3,319,004		135,167		4	%
Natural gas liquids (Bbls)	725,992		632,740		93,252		15	%
Total production (Boe)(1)	3,560,657		3,593,109		(32,452)		(1)	%

Average sales price:
Oil (per Bbl)	$	82.50	$	66.17	$	16.33	25	%
Natural gas (per Mcf)	(3.90)		(0.77)		(3.13)		(406)	%
Natural gas liquids (Bbl)	7.52		7.83		(0.31)		(4)	%
Total per Boe	$	50.09	$	45.00	$	5.09	11	%

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

Oil sales. Oil sales increased approximately $27.1 million from $159.3 million to $186.4 million, with a price variance of $36.9 million from an increase in the average realized price per barrel from $66.17 to $82.50 as a result of higher oil commodity prices. This was offset by a volume variance of $(9.8) million due to a decrease in sales volume from 2,407,202 barrels to 2,258,970 barrels. The decrease in volume of 148,232 barrels was impacted by a decrease of 274,977 attributable to natural production declines in the legacy assets, offset by an increase in volumes of 126,745 from wells acquired and drilled in the Lime Rock acquisition area.

Natural gas sales. Natural gas sales decreased approximately $10.9 million from a negative $2.5 million to a negative $13.5 million. The natural gas sales volume increased from 3,319,004 Mcf to 3,454,171 Mcf, and the average realized price per Mcf decreased from $(0.77) to $(3.90). Of the increase in volume of 135,167 Mcf, an increase of 176,790 was due to wells acquired and drilled in the Lime Rock acquisition area, offset by a decrease of 41,623 for 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 six months ended June 30, 2026, gross revenues were $(1.77) per Mcf and fees were $(2.13) per Mcf, compared to gross revenues of $1.35 per Mcf and fees of $(2.12) per Mcf for the six months ended June 30, 2025. This resulted in a net realized price of $(3.90) for the six months ended June 30, 2026 compared to $(0.77) per Mcf for the six months ended June 30, 2025.

Natural gas liquids sales. NGL sales increased approximately $0.5 million from $5.0 million to $5.5 million. NGL sales volumes for the six months ended June 30, 2026 were 725,992 barrels compared to 632,740 barrels for the comparable period in 2025. Of the increase in volume of 93,252 barrels, an increase of 57,810 was due to wells acquired and drilled in the Lime Rock acquisition area, and an increase of 35,442 was from legacy assets. The average realized price per barrel decreased by $0.31 to $7.52 for the six months ended June 30, 2026 compared to $7.83 for the six months ended June 30, 2025, due to lower prices. Specifically, the gross realized price per NGL barrel was $19.95 and the average fees per barrel was $(12.43), resulting in a net realized price of $7.52 for the six months ended June 30, 2026, while the gross realized price per barrel was $20.74 and the average fees per barrel was $(12.91), resulting in a net realized price of $7.83 for the same period in 2025.

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Production Costs for the Three Months Ended June 30, 2026 and 2025


	For the Three Months Ended
	June 30, 2026			June 30, 2025			Change			% Change

Lease operating expenses ("LOE")	$	18,409,462		$	20,245,981		$	(1,836,519)		(9)	%
Average LOE per Boe	$	10.12		$	10.45		$	(0.33)		(3)	%

Gathering, transportation and processing costs ("GTP")	$	101,902		$	133,809		$	(31,907)		(24)	%
Average GTP per Boe	$	0.06		$	0.07		$	(0.01)		(14)	%

Ad valorem taxes	$	2,202,160		$	1,648,647		$	553,513		34	%
Average Ad valorem taxes per Boe	$	1.21		$	0.85		$	0.36		42	%

Oil and natural gas production taxes	$	5,047,619		$	3,832,607		$	1,215,012		32	%
Average Production taxes per Boe	$	2.77		$	1.98		$	0.79		40	%
Production taxes as a percentage of total sales	4.82		%	4.64		%	0.18		%	4	%

Lease operating expenses. Our total lease operating expenses (“LOE”) decreased from $20.2 million to $18.4 million and decreased on a per Boe basis from $10.45 to $10.12. These per Boe amounts are calculated by dividing our total lease operating expenses by our total volume sold, in Boe. Total LOE decreased primarily due to a 6% decrease in production of 118,774 Boe as well as targeted cost reductions. The primary cost drivers for the period were decreases of $0.9 million in electricity costs, $0.6 million in chemicals, $0.5 million in equipment rentals, and $0.3 million in pressure, vacuum, and hot oil truck costs, offset by increases of $0.3 million in workovers and $0.2 million in contract and lease services.

Gathering, transportation and processing costs. Our total gathering, transportation and processing costs (“GTP”) decreased from $133,809 to $101,902 and decreased slightly on a per Boe basis from $0.07 to $0.06. The decrease in GTP costs was due to a reduction of $40,353 in gas processing costs offset by an increase of $8,446 in NGL processing costs.

Ad valorem taxes. Our total ad valorem taxes increased from $1.6 million to $2.2 million and increased on a per Boe basis from $0.85 to $1.21. Of the $0.6 million increase in ad valorem taxes, $0.3 million was for Yoakum County tax estimates, $0.1 million was for Andrews County tax estimates, $0.1 million was for Crane County tax estimates, and $0.1 million was for Ector 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 4.64% for the three months ended June 30, 2025 and increased to 4.82% for the three months ended June 30, 2026. Both percentages are in line with historical rates.

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Production Costs for the Six Months Ended June 30, 2026 and 2025


	For the Six Months Ended
	June 30, 2026			June 30, 2025			Change			% Change

Lease operating expenses ("LOE")	$	36,531,806		$	39,923,533		$	(3,391,727)		(8)	%
Average LOE per Boe	$	10.26		$	11.11		$	(0.85)		(8)	%

Gathering, transportation and processing costs ("GTP")	$	218,951		$	337,421		$	(118,470)		(35)	%
Average GTP per Boe	$	0.06		$	0.09		$	(0.03)		(33)	%

Ad valorem taxes	$	4,404,697		$	3,180,755		$	1,223,942		38	%
Average Ad valorem taxes per Boe	$	1.24		$	0.89		$	0.35		39	%

Oil and natural gas production taxes	$	8,601,510		$	7,417,062		$	1,184,448		16	%
Average Production taxes per Boe	$	2.42		$	2.06		$	0.36		17	%
Production taxes as a percentage of total sales	4.82		%	4.59		%	0.23		%	5	%

Lease operating expenses. Our total LOE decreased from $39.9 million to $36.5 million and LOE per Boe decreased from $11.11 to $10.26. Total LOE decreased from targeted reductions in costs as well as a 1% decrease in production of 32,452 Boe. The primary cost drivers for the period were decreases in chemicals of $1.5 million, equipment rentals of $1.0 million, electricity costs of $0.9 million, contract and lease services of $0.8 million, pressure, vacuum, and hot oil truck costs of $0.5 million, non-operated costs of $0.4 million, and location repairs and environmental sustainability of $0.3 million. This was offset by increases in LOE costs from workovers of $0.7 million, salt water disposal of $0.7 million, salaries of $0.5 million, and compressor rentals of $0.1 million.

Gathering, transportation and processing costs. Our total GTP decreased $118,470 from $337,421 to $218,951 and decreased on a per Boe basis from $0.09 to $0.06. The decrease in GTP costs was primarily a result of a reduction in gas processing costs.

Ad valorem taxes. Our total ad valorem taxes increased $1.2 million from $3.2 million to $4.4 million and increased on a per Boe basis from $0.89 to $1.24. An increase in ad valorem taxes of $0.5 million was from the reversal made in the first quarter of 2025 for the 2024 methane tax accrual for the waste emissions charge ("WEC"), which was repealed by Congress on March 14, 2025, with no similar reversal made in 2026. There was also an increase of $0.6 million in Andrews County due primarily to the Lime Rock acquisition as well as a $0.1 million increase from Crane County tax estimates. Offsetting these increases was a decrease in the Yoakum County tax estimates of approximately $0.1 million.

Oil and natural gas production taxes. Oil and natural gas production taxes as a percentage of oil and natural gas sales were 4.59% for the six months ended June 30, 2025 and increased to 4.82% for the six months ended June 30, 2026. The overall average percentage of production taxes to oil and gas sales was consistent period over period.

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Other Costs and Operating Expenses for the Three Months Ended June 30, 2026 and 2025


	For the Three Months Ended
	June 30, 2026		June 30, 2025		Change		% Change

Depreciation, depletion and amortization (DD&A):
Depletion	$	19,846,120	$	25,224,638	$	(5,378,518)	(21)	%
Depreciation	55,298		106,658		(51,360)		(48)	%
Amortization of financing lease assets	213,472		238,618		(25,146)		(11)	%
Total depreciation, depletion and amortization	$	20,114,890	$	25,569,914	$	(5,455,024)	(21)	%

Depletion per Boe	$	10.91	$	13.02	$	(2.11)	(16)	%
Depreciation, depletion and amortization per Boe	$	11.06	$	13.19	$	(2.13)	(16)	%

Ceiling test impairment	—		—		—		—	%

Asset retirement obligation ("ARO") accretion	$	401,944	$	382,251	$	19,693	5	%

Operating lease expense	$	175,090	$	175,090	$	—	—	%

General and administrative expense ("G&A"):
G&A excluding share-based compensation	$	5,804,634	$	5,786,680	$	17,954	—	%
Share-based compensation	2,149,596		1,351,839		797,757		59	%
Total general and administrative expense	$	7,954,230	$	7,138,519	$	815,711	11	%

G&A per Boe	$	4.37	$	3.68	$	0.69	19	%
G&A excluding Share-based compensation, per Boe	$	3.19	$	2.99	$	0.20	7	%

Depreciation, depletion and amortization. Our depreciation, depletion and amortization decreased from $25.6 million to $20.1 million, with $5.4 million of the reduction from lower depletion. The decrease in depletion was the result of a price variance of $(3.8) million, due to a lower depletion rate per Boe, driven by a decrease in the total estimated costs of property from the impairment recognized in the last two quarters of 2025 and the first quarter of 2026, coupled with an increase in the amortization base (total Boe). Also impacting the lower depletion was a volume variance of $(1.6) million from a decrease of 118,774 in Boe produced. Our average depreciation, depletion and amortization per Boe decreased from $13.19 per Boe to $11.06 per Boe.

Ceiling test impairment. As a result of the higher oil prices impacting the present value of estimated future net revenues, the Company did not incur a ceiling test impairment on its oil and natural gas properties during each of the three month periods presented.

Asset retirement obligation accretion. Our asset retirement obligation (“ARO”) accretion increased from $382,251 to $401,944 as a result of result of newly acquired and drilled wells, offset by those plugged and abandoned and sold.

Operating lease expense. Our operating lease expense costs were the same period over period.

General and administrative expense. General and administrative ("G&A") expense increased from $7.1 million to approximately $8.0 million. The approximate $0.8 million cost increase was primarily driven by an increase of $0.8

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million in stock compensation, $0.2 million in other professional fees, and $0.1 million in meals and entertainment. These costs were offset by reductions of $0.3 million in salaries and bonuses.

Other Costs and Operating Expenses for the Six Months Ended June 30, 2026 and 2025


	For the Six Months Ended
	June 30, 2026		June 30, 2025		Change		% Change

Depreciation, depletion and amortization (DD&A):
Depletion	$	40,971,496	$	47,479,214	$	(6,507,718)	(14)	%
Depreciation	142,433		203,278		(60,845)		(30)	%
Amortization of financing lease assets	406,909		503,405		(96,496)		(19)	%
Total depreciation, depletion and amortization	$	41,520,838	$	48,185,897	$	(6,665,059)	(14)	%

Depletion per Boe	$	11.51	$	13.21	$	(1.70)	(13)	%
Depreciation, depletion and amortization per Boe	$	11.66	$	13.41	$	(1.75)	(13)	%

Ceiling test impairment	$	162,086,257	$	—	$	162,086,257	100	%

Asset retirement obligation ("ARO") accretion	$	797,440	$	708,800	$	88,640	13	%

Operating lease expense	$	350,181	$	350,181	$	—	—	%

General and administrative expense ("G&A"):
G&A excluding share-based compensation	$	11,718,604	$	12,715,698	$	(997,094)	(8)	%
Share-based compensation	3,674,404		3,042,797		631,607		21	%
Total general and administrative expense	$	15,393,008	$	15,758,495	$	(365,487)	(2)	%

G&A per Boe	$	4.32	$	4.39	$	(0.07)	(2)	%
G&A excluding Share-based compensation, per Boe	$	3.29	$	3.54	$	(0.25)	(7)	%

Depreciation, depletion and amortization. Our depreciation, depletion and amortization decreased approximately $6.7 million from $48.2 million to $41.5 million, with substantially all of the reduction from lower depletion. The decrease in depletion was primarily due to a price variance of $(6.1) million, from a lower depletion expense per Boe, due to reduction in the total estimated costs of property from the impairment recognized in the last two quarters of 2025 and the first quarter of 2026, coupled with an increase in the amortization base (total Boe). Adding to this was a volume variance of approximately $(0.4) million from a decrease of 32,452 in Boe produced. Our average depreciation, depletion and amortization per Boe decreased from $13.41 per Boe to $11.66 per Boe.

Ceiling test impairment. As a result of the lower oil prices impacting the present value of estimated future net revenues, the Company incurred a ceiling test impairment on its oil and natural gas properties of $162.1 million during the six months ended June 30, 2026.

Asset retirement obligation accretion. Our ARO accretion increased by $88,640 from $708,800 to $797,440 primarily due to additional ARO accretion associated with properties acquired in the Lime Rock Acquisition, as well as newly drilled wells, offset by those plugged and abandoned and sold.

Operating lease expense. Our operating lease expense costs were the same period over period.

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General and administrative expense. G&A expense decreased approximately $0.4 million from $15.8 million to $15.4 million, with the $0.4 million cost decrease primarily due to a decrease of $0.9 million in salaries and bonuses, $0.5 million in additional costs capitalized, offset by an increase of $0.6 million in stock compensation, $0.3 million in other professional fees, and $0.1 million in allowance for credit losses.

Other Income (Expense) for the Three Months Ended June 30, 2026 and 2025


	For the Three Months Ended
	June 30, 2026		June 30, 2025		Change		% Change

Interest income	$	148,540	$	69,658	$	78,882	113	%

Interest expense:
Interest on revolving line of credit	$	7,438,315	$	9,482,817	$	(2,044,502)	(22)	%
Fees associated with revolving line of credit	215,134		210,459		4,675		2	%
Amortization of deferred financing costs	690,842		1,836,174		(1,145,332)		(62)	%
Interest on financing lease liabilities	25,661		27,638		(1,977)		(7)	%
Interest paid for notes payable	9,600		10,645		(1,045)		(10)	%
Deferred cash payment accretion	—		189,671		(189,671)		(100)	%

Total interest expense	$	8,379,552	$	11,757,404	$	(3,377,852)	(29)	%

Gain (loss) on derivative contracts:
Realized gain (loss):
Crude oil	$	(19,617,172)	$	433,301	$	(20,050,473)	NM (1)
Natural gas	1,158,092		244,542		913,550		374	%
Total realized gain (loss)	$	(18,459,080)	$	677,843	$	(19,136,923)	NM (1)
Unrealized gain (loss):
Crude oil	$	39,356,764	$	12,145,940	$	27,210,824	224	%
Natural gas	2,826,742		1,824,271		1,002,471		55	%
Total unrealized gain (loss)	$	42,183,506	$	13,970,211	$	28,213,295	202	%
Total gain (loss) on derivative contracts:	$	23,724,426	$	14,648,054	$	9,076,372	62	%

Gain (loss) on disposal of assets	$	104,150	$	155,293	$	(51,143)	(33)	%
Other income	$	9,600	$	150,770	$	(141,170)	(94)	%

(1) Not meaningful.

Interest income. Interest income increased from $69,658 to $148,540 as a result of $78,882 in higher earnings on excess cash balances in bank sweep accounts.

Interest expense. Interest expense decreased from $11.8 million to $8.4 million primarily due to lower amounts outstanding on the Credit Facility, with a weighted average daily debt of approximately $415.0 million during the second quarter of 2026 compared to approximately $456.3 million during the second quarter of 2025, coupled with a reduction in interest rates, with a weighted average annual interest rate of 7.4% in the second quarter of 2026 compared to 8.5% in the second quarter of 2025. Also impacting the decrease in interest expense was a reduction in deferred financing costs recognized from the credit agreement modification which was completed in June 2025.

Gain (loss) on derivative contracts. We recorded a gain on derivative contracts of $23.7 million for the three months ended June 30, 2026 compared to a gain on derivative contracts of $14.6 million for the three months ended June 30, 2025. For the derivative contract settlements, we recorded a realized loss of $18.5 million for the three months ended June 30, 2026 and a realized gain of $0.7 million for the three months ended June 30, 2025. The change of $19.1 million in the realized

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gain (loss) was primarily a result of less favorable settlements of crude oil derivative contracts during the current year. For the marked-to-market contracts, we recorded an unrealized gain of $42.2 million for the three months ended June 30, 2026 and an unrealized gain of $14.0 million for the three months ended June 30, 2025. The change in position was primarily due to the changes in crude oil futures prices.

Gain (loss) on disposal of assets. The Company's gain on disposal of assets decreased by $51,143 from $155,293 during the three months ended June 30, 2025 to $104,150 during the three months ended June 30, 2026, with a reduction of $74,285 from the sale of leased vehicles, offset by an increase of $23,142 from selling owned vehicles.

Other income. The Company's other income decreased by $141,170, due to a reduction of $150,770 from a pipeline easement lease, offset by an increase of $9,600 from a ranching lease.

Other Income (Expense) for the Six Months Ended June 30, 2026 and 2025


	For the Six Months Ended
	June 30, 2026		June 30, 2025		Change		% Change

Interest income	$	219,069	$	159,716	$	59,353	37	%

Interest expense:
Interest on revolving line of credit	$	15,119,866	$	17,430,459	$	(2,310,593)	(13)	%
Fees associated with revolving line of credit	408,611		487,848		(79,237)		(16)	%
Amortization of deferred financing costs	1,384,990		3,074,667		(1,689,677)		(55)	%
Interest on financing lease liabilities	49,547		56,379		(6,832)		(12)	%
Interest paid for notes payable	16,147		17,166		(1,019)		(6)	%
Deferred cash payment accretion	—		189,671		(189,671)		(100)	%

Total interest expense	$	16,979,161	$	21,256,190	$	(4,277,029)	(20)	%

Gain (loss) on derivative contracts:
Realized gain (loss):
Crude oil	$	(25,675,828)	$	(206,966)	$	(25,468,862)	NM (1)
Natural gas	1,940,737		331,215		1,609,522		486	%
Total realized gain (loss)	$	(23,735,091)	$	124,249	$	(23,859,340)	NM (1)
Unrealized gain (loss):
Crude oil	$	(40,436,306)	$	14,487,365	$	(54,923,671)	(379)	%
Natural gas	5,664,898		(892,350)		6,557,248		735	%
Total unrealized gain (loss)	$	(34,771,408)	$	13,595,015	$	(48,366,423)	(356)	%
Total gain (loss) on derivative contracts:	$	(58,506,499)	$	13,719,264	$	(72,225,763)	(526)	%

Gain (loss) on disposal of assets	$	104,150	$	279,903	$	(175,753)	(63)	%
Other income	$	15,437	$	159,712	$	(144,275)	(90)	%

(1) Not meaningful.

Interest income. Interest income increased $59,353 from $159,716 to $219,069, as a result of $37,135 in higher earnings on excess cash balances in bank sweep accounts, as well as an increase of $22,218 in severance tax interest receipts.

Interest expense. Interest expense decreased by approximately $4.3 million from $21.3 million to $17.0 million, primarily due to lower interest rates, with a weighted average annual interest rate of 7.3% during the six months ended June 30, 2026 compared to 8.4% during the six months ended June 30, 2025, as well as lower amounts outstanding on our Credit Facility, with a weighted average daily debt of approximately $422.7 million during the six months ended June 30, 2026 compared

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to approximately $425.0 million during the six months ended June 30, 2025. Also impacting the reduction in interest expense was a decrease in the amortization of deferred financing costs as a result of the amendment and restatement of the credit agreement in the second quarter of 2025.

Gain (loss) on derivative contracts. We recorded a loss on derivative contracts of $58.5 million for the six months ended June 30, 2026 and a gain on derivative contracts of $13.7 million for the six months ended June 30, 2025. For the derivative contract settlements, we recorded a realized loss of $23.7 million for the six months ended June 30, 2026 compared with a realized gain of $0.1 million for the six months ended June 30, 2025. The change of $23.9 million in the realized derivative gain (loss) was primarily a result of less favorable settlements of crude oil derivative contracts during the current year. For the marked-to-market contracts, we recorded an unrealized loss of $34.8 million for the six months ended June 30, 2026 and an unrealized gain of $13.6 million for the six months ended June 30, 2025. This negative change in unrealized derivatives primarily reflects changes in the crude oil forward pricing curve during the quarter.

Gain (loss) on disposal of assets. The Company's gain on disposal of assets decreased by $175,753 from $279,903 to $104,150 with $205,869 of the decrease from the sale of leased vehicles offset by a positive $30,116 from selling owned vehicles.

Other income. Other income decreased $144,275 from $159,712 to $15,437 due to a reduction of $150,770 from a pipeline easement lease and a reduction of $3,105 in income from the Company's charge card rebate program, offset by an increase of $9,600 in income from a ranching lease.

Benefit from (Provision for) Income Taxes: for the Three Months Ended June 30, 2026 and 2025


	For the Three Months Ended
	June 30, 2026		June 30, 2025		Change		% Change

Benefit from (Provision for) Income Taxes:
Deferred federal income tax benefit (provision)	$	(542,196)	$	(5,776,325)	$	5,234,129	91	%
Current state income tax (provision)	(59,649)		(147,461)		87,812		60	%
Deferred state income tax benefit (provision)	(486,201)		(183,639)		(302,562)		(165)	%
Benefit from (Provision for) Income Taxes	$	(1,088,046)	$	(6,107,425)	$	5,019,379	82	%

Provision for income taxes. The provision for income taxes changed from a provision of $6.1 million for the three months ended June 30, 2025 to a provision of $1.1 million for the three months ended June 30, 2026, due to the decrease in pre-tax book income for the three months ended June 30, 2026, netted against the recording of the valuation allowance. The 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 2026, taking into account all applicable tax rates and laws.

Benefit from (Provision for) Income Taxes: for the Six Months Ended June 30, 2026 and 2025


	For the Six Months Ended
	June 30, 2026		June 30, 2025		Change		% Change

Benefit from (Provision for) Income Taxes:
Deferred federal income tax benefit (provision)	$	10,160,342	$	(8,592,403)	$	18,752,745	218	%
Current state income tax (provision)	(155,236)		(283,854)		128,618		45	%
Deferred state income tax benefit (provision)	895,261		(272,345)		1,167,606		429	%
Benefit from (Provision for) Income Taxes	$	10,900,367	$	(9,148,602)	$	20,048,969	219	%

Provision for income taxes. The provision for income taxes changed from a provision of $9.1 million for the six months ended June 30, 2025 to a benefit of $10.9 million for the six months ended June 30, 2026 due to a year-to-date pre-tax loss for the six months ended June 30, 2026. The 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 2026, taking into account all applicable tax rates and laws.

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Liquidity and Capital Resources

Cash Flows

As of June 30, 2026, we had cash on hand of $1.1 million, compared to $0.9 million as of December 31, 2025. We actively manage our cash to optimize liquidity and minimize outstanding debt and associated interest costs. 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 six months ended June 30, 2026 of $66.7 million, compared to net cash provided by operating activities of $61.7 million for the same period in 2025, which was primarily due to higher year to date revenues, which resulted in more cash received from purchasers, offset by higher realized derivative losses. We had net cash used in investing activities of $71.9 million for the six months ended June 30, 2026, compared to net cash used in investing activities of $121.0 million for the same period in 2025, driven by the payments made for the Lime Rock acquisition in 2025, with no comparable acquisition made to date in 2026. Capital expenditures for the development of oil and natural gas properties grew meaningfully and the Company sold non-operated working interests in 2026, as reflected in proceeds from divestiture of oil and natural gas properties. Net cash provided by financing activities was $5.4 million for the six months ended June 30, 2026 and net cash provided by financing activities was $57.4 million for the six months ended June 30, 2025, during which time $60.0 million was the net paydown and $63.0 million was the net borrowing of principal on our Credit Facility, respectively.

We will continue to focus on maximizing cash flow in 2026 through a combination of cost monitoring and prudent capital allocation, which will include 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, ultimately pushing to reduce our debt level and maximize our liquidity.

Availability of Capital Resources under Credit Facility

As of June 30, 2026, $360 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 June 2029. The borrowing base under our Credit Facility is $585 million. The borrowing base is redetermined semi-annually 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.

Equity Offering

In May 2026, the Company completed an underwritten public offering of 44,444,445 shares of common stock at a public offering price of $1.35 per share and gross proceeds of $60.0 million. In June 2026, the underwriters exercised an option to purchase an additional 6,666,666 shares of common stock at a public offering price of $1.35 per share and gross proceeds of $9.0 million. The sale of common stock resulted in total gross proceeds of $69.0 million and net proceeds of $64.5 million, after deducting underwriting fees and offering expenses.

Derivative Financial Instruments

The following table reflects the contracts outstanding as of June 30, 2026 (quantities are in barrels (Bbl) for the oil derivative contracts and in million British thermal units (MMBtu) for the natural gas derivative contracts):


Oil Hedges (WTI)	Q3 2026		Q4 2026		Q1 2027		Q2 2027		Q3 2027		Q4 2027		Q1 2028		Q2 2028

Swaps:
Hedged volume (Bbl)	263,400		529,000		509,500		492,000		432,000		412,963		—		—
Weighted average swap price	$	61.77	$	65.34	$	62.82	$	60.45	$	61.80	$	57.59	$	—	$	—






Two-way collars:
Hedged volume (Bbl)	563,685		368,000		2,935		—		32,910		33,435		430,080		415,580
Weighted average put price	$	60.82	$	65.00	$	62.50	$	—	$	60.00	$	60.00	$	55.59	$	57.50
Weighted average call price	$	76.19	$	80.00	$	73.65	$	—	$	72.30	$	72.30	$	66.02	$	73.02

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Gas Hedges (Henry Hub)	Q3 2026		Q4 2026		Q1 2027		Q2 2027		Q3 2027		Q4 2027		Q1 2028		Q2 2028

NYMEX Swaps:
Hedged volume (MMBtu)	600,016		1,072,305		439,678		423,035		1,079,906		1,046,151		1,012,567		984,322
Weighted average swap price	$	4.19	$	3.99	$	4.02	$	4.02	$	3.86	$	4.02	$	3.77	$	3.77

Two-way collars:
Hedged volume (MMBtu)	648,728		128,000		717,000		694,000		—		—		—		—
Weighted average put price	$	3.10	$	3.50	$	3.99	$	3.00	$	—	$	—	$	—	$	—
Weighted average call price	$	4.24	$	5.42	$	5.21	$	4.32	$	—	$	—	$	—	$	—


Gas Hedges (Henry Hub)	Q3 2028		Q4 2028		Q1 2029		Q2 2029		Q3 2029		Q4 2029		Q1 2030

NYMEX Swaps:
Hedged volume (MMBtu)	956,865		931,539		908,117		886,933		866,585		846,134		—
Weighted average swap price	$	3.77	$	3.77	$	3.67	$	3.67	$	3.67	$	3.67	$	—


Gas Hedges (basis differential)	Q3 2026		Q4 2026		Q1 2027		Q2 2027		Q3 2027		Q4 2027		Q1 2028		Q2 2028

Waha basis swaps:
Hedged volume (MMBtu)	374,623		411,451		196,372		480,325		464,360		449,846		435,403		—
Weighted average spread price (1)	$	2.15	$	1.81	$	0.78	$	0.78	$	0.78	$	0.78	$	0.68	$	—

El Paso Permian Basin basis swaps:
Hedged volume (MMBtu)	874,121		788,851		960,307		636,710		615,547		596,306		577,163		—
Weighted average spread price (1)	$	2.16	$	1.92	$	0.72	$	0.67	$	0.67	$	0.67	$	0.60	$	—

(1) The gas basis swap hedges are calculated as the Henry Hub natural gas price less the fixed amount specified as the weighted average spread price above.

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 June 30, 2026, we had no off-balance sheet financing arrangements.

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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-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.

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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 $41.9 million as of June 30, 2026). We are subject to credit risk due to the concentration of our oil and natural gas receivables with our most significant customers, or purchasers. We do not require our purchasers to post collateral, and the inability of our significant purchasers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. Refer to the following table for detail on the top three purchasers of our oil, natural gas, and NGL revenues for the six months ended June 30, 2026. We believe that the loss of any of these purchasers would not materially impact our business as we could readily find other purchasers for our oil and natural gas.

For the Six Months Ended

As of

June 30, 2026

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

72%

Energy Transfer Crude Marketing

13%

Concord Energy LLC

11%

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility, which bears variable interest based upon a prime rate and is therefore susceptible to interest rate fluctuations. Changes in interest rates affect the interest earned on the Company’s cash and cash equivalents and the interest rate paid on borrowings under the Credit Facility.

As of June 30, 2026, we had $360 million outstanding on our Credit Facility with a weighted average annual interest rate for the six months ended June 30, 2026 of 7.3%. A 1% change in the interest rate on our Credit Facility would result in an estimated $3.6 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.

Currency Exchange Rate Risk

The Company had no Foreign sales and 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.

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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 Sundip S. Johl, 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 Johl 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 June 30, 2026 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 June 30, 2026 in the legal proceeding described in our Annual Report on Form 10-K for the year ended December 31, 2025.

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, 2025 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.

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

None.

Item 3: Defaults Upon Senior Securities

None.

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Item 4: Mine Safety Disclosures

None.

Item 5: Other Information

During the quarter ended June 30, 2026, 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 Principal Executive Officer

31.2

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

32.1

Section 1350 Certification of Principal Executive Officer

32.2

Section 1350 Certification Principal Financial Officer

101.SCH

Inline XBRL Taxonomy Extension Schema Document

101.CAL

Inline XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF

Inline XBRL Taxonomy Extension Definition Linkbase Document

101.LAB

Inline XBRL Taxonomy Extension Label Linkbase Document

101.PRE

Inline XBRL Taxonomy Extension Presentation Linkbase Document

104

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

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	Ring Energy, Inc.

Date: August 5, 2026	By:	/s/ Paul D. McKinney
		Paul D. McKinney
		Chief Executive Officer
		(Principal Executive Officer)

Date: August 5, 2026	By:	/s/ Sundip S. Johl
		Sundip S. Johl
		Chief Financial Officer
		(Principal Financial Officer)