What changed in this filing

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Item 9A. Controls and Procedures

2026-03-04 compared with 2025-03-05 · 407 added, 351 removed, 1359 unchanged (36% of the section changed)

1 unchanged sentence

Evaluation of disclosure controls and procedures.

Under the direction of our Chief Executive Officer and Chief Financial Officer, we have established disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms.

The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

Under the direction of our Chief Executive Officer and Interim Chief Financial Officer, we have established disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms.

The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Interim Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

In designing and evaluating the disclosure controls and procedures, management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

As of December 31, 2024, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act.

Based upon our evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that as of December 31, 2024, our disclosure controls and procedures are effective.

As of December 31, 2025, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Interim Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act.

Based upon our evaluation, our Chief Executive Officer and Interim Chief Financial Officer have concluded that as of December 31, 2025, our disclosure controls and procedures are effective.

Changes in internal control over financial reporting.

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and Founders Oil & Gas IV, LLC.

2.4 P urchase and Sale Agreement dated as of February 25, 2025 by and among R ing Energy, Inc., Lime Rock Resources IV-A, L.P., and Lime Rock Resources IV-C, L.P.

2.4 Purchase and Sale Agreement dated as of February 25, 2025 by and among Ring Energy, Inc., Lime Rock Resources IV-A, L.P., and Lime Rock Resources IV-C, L.P.

3.1 Articles of Incorporation (as amended)

59 unchanged sentences

001-36057 10.25 3/7/24

14.1 Code of Ethics

8-K 000-53920 14.1 1/24/13

19.1 I nsider Trading Policy

Incorporated by Reference

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Here-with Furn-ished Here-with

10.19 Registration Rights Agreement dated March 31, 2025, by and among Ring Energy, Inc., Lime Rock Resources IV-A, L.P.

and Lime Rock Resources IV-C, L.P.

10.20 A mendment No.

2 to the Ring Energy, Inc.

2021 Omnibus Incentive Plan.

10.21 Third Amended and Restated Credit Agreement dated June 18, 2025, by and among Ring Energy, Inc., Bank of America, N.A., and the Lenders from time to time party thereto.

General Release Agreement dated October 2, 2025 by Travis T.

Offer Letter between Ring Energy, Inc.

and Sundip S.

Johl dated January 29, 2026.

14.1 Code of Ethics

8-K 000-53920 14.1 1/24/13

19.1 Insider Trading Policy

23.1 Consent of Cawley, Gillespie & Associates, Inc.

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

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

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

32.1 Section 1350 Certification of Chief Executive Officer

32.2 Section 1350 Certification Chief Financial Officer

32.2 Section 1350 Certification of Principal Financial Officer

97.1 Ring Energy, Inc.

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KNOW ALL PERSONS BY THESE PRESENTS, that each individual whose signature appears below constitutes and appoints Paul D.

McKinney, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K filed with the Securities and Exchange Commission, hereby ratifying and confirming his signature as he may be signed by his or her said attorney to any and all amendments to said Annual Report on Form 10-K.

McKinney, his or her true and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K filed with the Securities and Exchange Commission, hereby ratifying and confirming his or her signature as he or she may be signed by his or her said attorney to any and all amendments to said Annual Report on Form 10-K.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on the dates indicated.

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March 4, 2026

/s/ Travis T.

Thomas /s/ Anthony B.

Chief Financial Officer Director

/s/ Anthony B.

Vice President, Chief Accounting Officer

(Principal Financial Officer and Principal Accounting Officer)

1 unchanged sentence

March 4, 2026

/s/ Regina Roesener /s/ John A.

Regina Roesener Mr.

/s/ Carla Tharp

Director Director

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Report of Grant Thornton LLP Independent Registered Public Accounting Firm (PCAOB ID Number 248 )

Balance Sheet s as of December 31, 2024 and 2023

Statement s of Operations for the years ended December 31, 2024, 2023, and 2022

Balance Sheets as of December 31, 2025 and 2024

Statements of Operations for the years ended December 31, 2025, 2024, and 2023

Statement of Stockholders’ Equity for the years ended December 31, 2025, 2024, and 2023

Statement s of Cash Flows for the years ended December 31, 2024, 2023, and 2022

Statements of Cash Flows for the years ended December 31, 2025, 2024, and 2023

Notes to Financial Statements

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We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2025, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated March 4, 2026 expressed an unqualified opinion.

Change in accounting principle

As discussed in Note 15 to the financial statements, the Company has adopted new accounting guidance in 2024 related to the disclosure of segment information in accordance with ASU 2023-07, Segment Reporting (Topic 280) .

The adoption was retrospectively applied to 2023 and 2022.

Basis for opinion

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The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

The development of estimated proved crude oil and natural gas reserves used in the calculation of depletion, depreciation and amortization expense under the full cost method of accounting

As described further in Note 1 to the financial statements, the Company accounts for its oil and gas properties using the full cost method of accounting, which requires management to make estimates of proved crude oil and natural gas reserve volumes and future development costs to calculate and record depletion, depreciation and amortization expense.

To estimate the volume of proved crude oil and natural gas reserves and future development costs, management makes significant estimates and assumptions including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties.

determine if wells are expected, with reasonable certainty, to be economical under the appropriate pricing assumptions required in the estimation of depletion, depreciation and amortization expense.

The development of estimated proved crude oil and natural gas reserves used in the calculation of depletion, depreciation and amortization expense and impairment expense under the full cost method of accounting

To estimate the volume of proved crude oil and natural gas reserves, future development costs, and the related future net cash flows, management makes significant estimates and assumptions including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties.

In addition, the estimation of proved crude oil and natural gas reserves is impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved crude oil and natural gas reserves to determine if wells are expected, with reasonable certainty, to be economical under the appropriate pricing assumptions required in the estimation of depletion, depreciation and amortization expense and the assessment of potential impairment.

We identified the estimation of proved reserves of oil and gas properties as a critical audit matter.

The principal consideration for our determination that the estimation of proved crude oil and natural gas reserves is a critical audit matter is that changes in certain inputs and assumptions, which require a high degree of subjectivity, necessary to estimate the volume and future development costs of the Company’s proved reserves could have a significant impact on the measurement of depletion, depreciation and amortization expense.

The principal consideration for our determination that the estimation of proved crude oil and natural gas reserves is a critical audit matter is that changes in certain inputs and assumptions, which require a high degree of subjectivity, necessary to estimate the volumes, future development costs, and the related net cash flows of the Company’s proved reserves could have a significant impact on the measurement of depletion, depreciation and amortization expense and impairment expense.

In turn, auditing those inputs and assumptions required subjective and complex auditor judgment.

Our audit procedures related to the estimation of proved crude oil and natural gas reserves included the following, among others.

• We tested the design and operating effectiveness of controls relating to management’s estimation of proved crude oil and natural gas reserves for the purpose of estimating depletion, depreciation and amortization expense.

• We tested the design and operating effectiveness of key controls relating to management’s estimation of proved crude oil and natural gas reserves for the purpose of estimating depletion, depreciation and amortization expense and impairment expense.

• We evaluated the independence, objectivity, and professional qualifications of the Company’s reserve engineers, made inquiries of those specialists regarding the process followed and judgments made to estimate the Company’s proved crude oil and natural gas reserve volumes, and read the reserve report prepared by the Company’s reserve engineers.

• To the extent key inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, including, but not limited to:

historical pricing differentials, operating costs, estimated future development costs, and ownership interests, we tested management’s process for determining the assumptions, including examining the underlying support on a sample basis.

Specifically, our audit procedures involved testing management’s assumptions by performing the following:

◦ We compared the estimated pricing differentials used in the reserve report to prices realized by the Company related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials;

◦ We tested models used to estimate the future operating costs in the reserve report and compared amounts to historical operating costs;

◦ We evaluated the method used to determine the estimated future development costs used in the reserve report and compared management’s estimates to amounts expended for recently drilled and completed wells;

◦ We tested, on a sample basis, the working and net revenue interests used in the reserve report by inspecting land, legal and division order records;

◦ We evaluated evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company’s ability to fund and intent to develop the proved undeveloped properties;

◦ We applied analytical procedures to production forecasts in the reserve report by comparing to historical actual results.

• Identified the inputs and assumptions significant to the proved reserve volumes and tested management’s process for determining the significant inputs and assumptions, including examining the underlying support on a sample basis.

Specifically, our audit procedures involved testing management’s inputs and assumptions by performing the following:

◦ Compared the estimated pricing differentials used in the reserve report to prices realized by the Company related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials;

◦ Tested models used to estimate the future operating costs in the reserve report and compared amounts to historical operating costs;

◦ Evaluated the method used to determine the estimated future development costs used in the reserve report and compared management’s estimates to amounts expended for recently drilled and completed wells;

◦ Tested, on a sample basis, the working and net revenue interests used in the reserve report by inspecting land, legal and division order records;

◦ Evaluated evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company’s ability to fund and intent to develop the proved undeveloped properties;

◦ Applied analytical procedures to production forecasts in the reserve report by comparing to historical actual results.

/s/ GRANT THORNTON LLP

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Depreciation, depletion and amortization 96,414,150 98,702,843 88,610,291

Ceiling test impairment 108,825,446 — —

Asset retirement obligation accretion 1,490,255 1,380,298 1,425,686

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Total Costs and Operating Expenses 341,516,500 233,426,714 215,275,510

Income from Operations

132,900,700 145,780,491 191,744,133

Income (Loss) from Operations ( 34,338,428 ) 132,900,700 145,780,491

Other Income (Expense)

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Net Other Income (Expense) ( 7,845,517 ) ( 44,989,432 ) ( 40,790,608 )

Income Before Provision for Income Taxes 87,911,268 104,989,883 147,043,749

Provision for Income Taxes ( 20,440,954 ) ( 125,242 ) ( 8,408,724 )

$ 67,470,314 $ 104,864,641 $ 138,635,025

Basic Earnings per Share

$ 0.34 $ 0.55 $ 1.14

Diluted Earnings per Share

$ 0.34 $ 0.54 $ 0.98

Income (Loss) Before Benefit from (Provision for) Income Taxes ( 42,183,945 ) 87,911,268 104,989,883

Benefit from (Provision for) Income Taxes 7,452,746 ( 20,440,954 ) ( 125,242 )

Net Income (Loss) $ ( 34,731,199 ) $ 67,470,314 $ 104,864,641

Basic Earnings (Loss) per Share $ ( 0.17 ) $ 0.34 $ 0.55

Diluted Earnings (Loss) per Share $ ( 0.17 ) $ 0.34 $ 0.54

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

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Exercise of common warrants issued in offering 4,517,427 4,517 3,609,424 — 3,613,941

Options exercised 100,000 100 ( 100 ) — —

Shares elected to be withheld for options exercised ( 47,506 ) ( 48 ) 48 — —

Induced exercise of common warrants issued in offering 14,512,166 14,512 8,673,143 — 8,687,655

Restricted stock vested 1,680,232 1,680 ( 1,680 ) — —

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Payments to cover tax withholdings for restricted stock vested, net — — ( 520,153 ) — ( 520,153 )

Common stock issuance for Stronghold Acquisition 21,339,986 21,340 69,120,215 — 69,141,555

Conversion of mezzanine preferred shares for Stronghold Acquisition 42,548,892 42,549 137,815,897 — 137,858,446

Performance stock vested 1,170,024 1,170 ( 1,170 ) — —

Shares to cover tax withholdings for performance stock vested ( 284,908 ) ( 285 ) 285 — —

Share-based compensation — — 8,833,425 — 8,833,425

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Balance, December 31, 2023 196,837,001 $ 196,837 $ 795,834,675 $ ( 9,448,612 ) $ 786,582,900

Exercise of common warrants issued in offering 4,517,427 $ 4,517 $ 3,609,424 $ — $ 3,613,941

Induced exercise of common warrants issued in offering 14,512,166 14,512 8,673,143 — 8,687,655

Restricted stock vested 1,688,317 1,688 ( 1,688 ) — —

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— ( 1,189,805 ) — ( 1,189,805 )

Common stock issuance for Lime Rock Acquisition 6,452,879 6,453 7,414,358 — 7,420,811

Performance stock vested

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Share-based compensation — — 6,135,957 — 6,135,957

Net income — — — 67,470,314 67,470,314

Net loss — — — ( 34,731,199 ) ( 34,731,199 )

Balance, December 31, 2025 207,656,929 $ 207,657 $ 812,777,586 $ 23,290,503 $ 836,275,746

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Cash Flows From Operating Activities

$ 67,470,314 $ 104,864,641 $ 138,635,025

Adjustments to reconcile net income to net cash provided by operating activities:

Net income (loss) $ ( 34,731,199 ) $ 67,470,314 $ 104,864,641

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Depreciation, depletion and amortization 96,414,150 98,702,843 88,610,291

Ceiling test impairment 108,825,446 — —

Asset retirement obligation accretion 1,490,255 1,380,298 1,425,686

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Accounts payable 474,744 ( 5,076,738 ) ( 1,451,422 )

Asset retirement obligation ( 1,588,480 ) ( 1,862,385 ) ( 2,741,380 )

Settlement of asset retirement obligation ( 904,493 ) ( 1,588,480 ) ( 1,862,385 )

Net Cash Provided by Operating Activities 150,849,407 194,423,712 198,170,459

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— — ( 62,227,145 )

Payments for the Lime Rock Acquisition ( 81,863,429 ) — —

Payments to purchase oil and natural gas properties ( 2,528,932 ) ( 2,210,826 ) ( 2,162,585 )

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Proceeds from sale of CBP vertical wells — 5,500,000 —

Insurance proceeds received for damage to oil and natural gas properties 260,446 — —

Net Cash Used in Investing Activities

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Cash paid for interest $ 32,363,614 $ 39,196,575 $ 38,009,164

Cash paid for income taxes

72,213 72,213 —

Cash paid (refunded) for income taxes 347,487 72,213 72,213

Noncash Investing and Financing Activities

8 unchanged sentences

1,039,445 ( 3,896,948 ) ( 2,241,192 )

Supplemental Schedule for Lime Rock Acquisition

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 2,576,648 — —

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

Purchase price adjustments paid to third parties 1,427,233 — —

Cash received from Lime Rock for post-close adjustments ( 706,116 ) — —

Payment of deferred cash payment

10,000,000 — —

Payments for the Lime Rock Acquisition $ 81,863,429 $ — $ —

Investing Activities - Noncash

Assumption of suspense liability $ 459,096 $ — $ —

Assumption of ad valorem tax liability 405,549 — —

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 — —

Supplemental Schedule for Founders Acquisition

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Investing Activities - Cash Paid

Cash paid by bank to Stronghold on closing $ — $ — $ 121,392,455

Deposit in escrow — — 46,500,000

Direct transaction costs — — 9,162,143

Cash paid for realized August oil derivative losses — — 1,777,925

Cash paid for inventory and fixed assets acquired — — 4,527,103

Cash received for post-close adjustments, net — — ( 5,535,839 )

Payment of deferred cash payment

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Payments for the Stronghold Acquisition $ — $ — $ 18,511,170

Investing Activities - Noncash

Assumption of suspense liability $ — $ — $ 1,651,596

Assumption of derivative liabilities — — 24,784,406

Assumption of asset retirement obligation — — 14,538,550

Deferred cash payment at fair value — — 14,807,276

Financing Activities - Noncash

Common stock issued for acquisition — — 69,141,555

Convertible preferred stock issued for acquisition — — 137,858,446

(1) Included within the financing lease assets obtained in exchange for new financing lease liability, net, is $ 45,436 of finance lease asset terminations for the year ended December 31, 2024.

(1) Included within the financing lease assets obtained in exchange for new financing lease liability, net, is $ 144,216 and $ 45,436 of finance lease asset terminations for the years ended December 31, 2025 and 2024, respectively.

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

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Note 12 — Employee Stock Options, Restricted Stock Award Plan, and 401(k)

Note 4 — Earnings Per Share Information

Note 4 — Earnings (Loss) Per Share Information

Note 13 — Commitments and Contingencies

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Refer to the " Major Purchasers " section below for detail on purchaser activity for the years ended December 31, 2025, 2024, and 2023.

Production imbalances – The Company accounts for natural gas production imbalances using the sales method, which recognizes revenue on all natural gas sold even though the natural gas volumes sold may be more or less than the Company's ownership entitles it to sell.

Liabilities are recorded for imbalances greater than the Company’s proportionate share of remaining estimated natural gas reserves.

The Company recorded no imbalances as of December 31, 2024 or 2023.

The following table reflects the Company's beginning and ending balances of its accounts receivables from purchasers of its oil and gas for the years ended December 31, 2025, 2024, and 2023.

For the years ended December 31,

2025 2024 2023

Beginning balance of accounts receivable from purchasers of oil and gas

$ 33,774,968 $ 37,879,779 $ 40,143,326

Ending balance of accounts receivable from purchasers of oil and gas

29,591,571 33,774,968 37,879,779

Joint interest billing receivables, net – The Company also has joint interest billing receivables.

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$ 1,623,991 $ 1,083,164

The increase of $ 123,164 in the allowance for credit losses during the year ended December 31, 2024 was primarily due to property sales and owner settlements.

The increase of $ 19,029 in the allowance for credit losses during the year ended December 31, 2025 was primarily for owner settlements considered uncollectible with no offsetting revenues held in suspense.

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.

Liabilities are recorded for imbalances greater than the Company’s proportionate share of remaining estimated natural gas reserves.

The Company recorded no imbalances as of December 31, 2025 or 2024.

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.

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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 year ended December 31, 2025, the Company recorded impairments on oil and natural gas properties as a result of the ceiling test of $ 108.8 million.

No impairments on oil and natural gas properties as a result of the ceiling test were recorded for the years ended December 31, 2024 or 2023.

Land, Buildings, Equipment, Software, Leasehold Improvements, Automobiles, Buildings and Structures – Land, buildings, equipment, software, leasehold improvements, automobiles, buildings and structures are carried at historical cost, adjusted for impairment loss and accumulated depreciation (except for land).

Historical costs include all direct costs associated with the acquisition of land, buildings, equipment, software, leasehold improvements, automobiles, buildings

and structures and placing them in service.

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

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

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Depreciation expense

During the year ended December 31, 2023, the Company sold some of its owned vehicles, driving the loss on disposal of 87,128 .

During the years ended December 31, 2025 2024, and 2023, the Company recorded a gain (loss) on disposal of assets, which was impacted by the sale of owned vehicles, as follows:

For the years ended December 31,

2025 2024 2023

Sale of owned vehicles

$ ( 6,974 ) $ ( 14,239 ) $ ( 132,109 )

Sale of leased vehicles

453,374 103,932 44,981

Gain (loss) on disposal of assets

$ 446,400 $ 89,693 $ ( 87,128 )

Accounts Payable

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$ 20,169,871 $ 20,672,841

Notes Payable – At the end of May 2024, the Company renewed its control of well, general liability, pollution, umbrella, property, workers' compensation, auto, and D&O insurance policies, funding the premiums with a promissory note with a face value after down payments of $ 1,501,507 .

Notes Payable – At the end of May 2025, the Company renewed its control of well, general liability, pollution, umbrella, property, worker's compensation, auto, and D&O (directors and officers) 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 %.

In November 2025, the Company renewed its cybersecurity insurance policy, paying the premium without financing through a note.

At the end of May 2024, the Company renewed its control of well, general liability, pollution, umbrella, property, workers' compensation, auto, and D&O insurance policies, funding the premiums with a promissory note with a face value after down payments of $ 1,501,507 .

In November 2024, the Company renewed its cybersecurity insurance policy, and funded the premium with a promissory note with a face value after down payments of $ 58,773 .

The APR for both notes was 7.98 %.

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

At the end of May 2023, the Company renewed its control of well, general liability, pollution, umbrella, property, workers' compensation, auto, and D&O insurance policies, and funded the premiums with a promissory note with a total face value after down payments of $ 1,565,071 .

In November 2023, the Company renewed its cybersecurity insurance policy, and funded the premium with a promissory note with a total face value after down payments of $ 72,442 .

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$ 59,097 $ 56,261 $ 49,734

Revenue Recognition – In January 2018, the Company adopted Accounting Standards Update (“ASU”) 2014-09 Revenues from Contracts with Customers (Topic 606) (“ASU 2014-09”).

The timing of recognizing revenue from the sale of produced crude oil and natural gas was not changed as a result of adopting ASU 2014-09.

The Company predominantly derives its revenue from the sale of produced crude oil and natural gas.

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.

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The guidance regarding ASU 2014-09 does not require that the transaction price be fixed or stated in the contract.

Estimating the variable consideration does not require significant judgment and Ring engages third party sources to validate the estimates.

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.

1 unchanged sentence

Income Taxes – Provisions for income taxes are based on taxes payable or refundable for the current year and deferred taxes.

Deferred income taxes are provided on differences between the tax basis of assets and liabilities and their carrying

amounts in the financial statements, and tax carryforwards.

Deferred income taxes are provided on differences between the tax basis of assets and liabilities and their carrying amounts in the financial statements, and tax carryforwards.

Deferred tax assets and liabilities are included in the financial statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled.

As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the provision for income taxes.

The Company recorded the following federal and state income tax provisions for the years ended December 31, 2024, 2023, and 2022.

For the Years Ended December 31,

2024 2023 2022

Deferred federal income tax benefit (provision) $ ( 19,096,010 ) $ 901,522 $ ( 6,437,680 )

Current state income tax benefit (provision) ( 401,197 ) ( 72,213 ) —

Deferred state income tax benefit (provision) ( 943,747 ) ( 954,551 ) ( 1,971,044 )

Provision for Income Taxes $ ( 20,440,954 ) $ ( 125,242 ) $ ( 8,408,724 )

The Company’s overall effective tax rates are calculated as Provision for Income Taxes divided by Income Before Provision for Income Taxes.

The effective tax rates for the years ended December 31, 2024, 2023, and 2022 were as follows.

For the Years Ended December 31,

2024 2023 2022

Effective tax rate (1)

23.3 % 0.1 % 5.7 %

(1) The effective tax rate for the year ended December 31, 2023 was impacted by the release of valuation allowance on the Company's federal net deferred tax asset.

A tax benefit of $ 24.2 million was recorded in the year ended December 31, 2023.

On July 4, 2025, the One Big Beautiful Bill Act ("OBBBA") was enacted, which, among other items, allows for 100% bonus depreciation on a permanent basis for property acquired after January 19, 2025.

Further, the OBBBA basis for Code

Section 163(j) 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 have incorporated these changes into our income tax provision for the year ended December 31, 2025.

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.

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therefore, no interest or penalty has been included in our provision for income taxes in the Statements of Operations.

Three-Stream Reporting – Beginning July 1, 2022, the Company began reporting volumes and revenues on a three-stream basis, separately reporting crude oil, natural gas, and NGL sales.

For periods prior to July 1, 2022, sales and reserve volumes, prices, and revenues for NGLs were presented with natural gas.

This represents a change in our accounting and reporting presentation necessitated by a change in the underlying facts and circumstances surrounding the Stronghold Acquisition, as Stronghold has historically reported its revenues on a three-stream basis.

As clarified in the interpretive guidance of Accounting Standards Codification ("ASC") 250, such changes should not be applied on a retrospective basis.

Accordingly, we began reporting on a three-stream basis prospectively, beginning July 1, 2022.

See NOTE 5 — ACQUISITIONS & DIVESTITURES for a discussion of the Stronghold Acquisition.

Leases – The Company accounts for its leases in accordance with ASU 2016-02, Leases (Topic 842), effective January 1, 2019.

The Company made accounting policy elections to not capitalize leases with a lease term of twelve months or less (i.e.

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 within ASU 2016-02 that allows an entity to not reassess prior to the effective date (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases, or (iii) initial direct costs for any existing leases and the practical expedient regarding land easements that exist prior to the adoption of ASU 2016-02.

The Company 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.

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As such, the adoption and implementation of this ASU did not have a material impact on the Company’s financial statements.

In August 2020, the FASB issued ASU No.

2020-06, “ Debt – Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging – Contracts in Entity’s Own Equity (Subtopic 815-40) ” (“ASU 2020-06”).

ASU 2020-06 was issued to reduce the complexity associated with accounting for certain financial instruments with characteristics of liabilities and equity.

ASU 2020-06 became effective for fiscal years beginning after December 15, 2021.

The Company adopted ASU 2020-06 effective January 1, 2022.

The adoption and implementation of this ASU did not have a material impact on the Company’s financial statements.

In October 2021, the FASB issued ASU 2021-08, " Business Combinations (Topic 805) – Accounting for Contract Assets and Contract Liabilities from Contracts with Customers” ("ASU 2021-08").

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The Company adopted ASU 2021-08 effective January 1, 2023.

The adoption and implementation of this ASU did not have a material impact on the Company’s financial statements, as its revenue is recognized when control transfers to the purchaser at the point of delivery, and no contract liabilities or assets are recognized in accordance with ASC 606.

In July 2023, the FASB issued ASU 2023-03, " Presentation of Financial Statements (Topic 205), Income Statement - Reporting Comprehensive Income (Topic 220), Distinguishing Liabilities from Equity (Topic 480), Equity (Topic 505), and Compensation - Stock Compensation (Topic 718):

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Income or Loss Applicable to Common Stock ." The ASU provided updated views from the SEC Staff on employee and non-employee share-based payment accounting, including guidance related to spring-loaded awards.

As the ASU did not provide any new ASC guidance, and there was no transition or effective date provided, the Company adopted this standard upon issuance, and the adoption did not have a material impact on the Company's financial statements.

As the ASU did not provide any new ASC guidance, and there was no

transition or effective date provided, the Company adopted this standard upon issuance, and the adoption did not have a material impact on the Company's financial statements.

In November 2023, the FASB issued ASU 2023-07 " Segment Reporting (Topic 280):

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The Company adopted ASU 2023-07 effective January 1, 2024.

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 December 2023, the FASB issued ASU 2023-09 " Income Taxes (Topic 740):

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Finally, the amendments from this update require that all entities disclose (i) income (or loss) from continuing operations before income tax expense (or benefit) disaggregated between domestic and foreign and (ii) income tax expense (or benefit) from continuing operations disaggregated by federal, state, and foreign.

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

For public business entities, the amendments in this update are effective for annual periods beginning after December 15, 2024.

As such, the Company adopted ASU 2023-09 effective January 1, 2025.

The Company has included the applicable enhanced disclosures prospectively in its annual financial statements for the year ended December 31, 2025.

In March 2024, the FASB issued ASU 2024-02 " Codification Improvements – Amendments to Remove References to the Concepts Statements " ("ASU 2024-02"), which contains amendments to the Codification to remove references to various FASB Concepts Statements.

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ASU 2024-02 is effective for the Company for fiscal years beginning after December 15, 2024.

The Company does not expect this update to have a material impact on its financial statements.

As such, the Company adopted ASU 2024-02 effective January 1, 2025.

The adoption did not have a material impact on the Company's financial statements.

Recent Accounting Pronouncements – In October 2023, the FASB issued ASU 2023-06, " Disclosure Improvements:

The Company is currently assessing the impact of this update on its financial statements and related notes.

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).

The amendments in this update are effective for annual reporting periods beginning after December 15, 2026 and interim reporting periods with annual reporting periods beginning after December 15, 2027, with early adoption permitted, and either prospective or retrospective application permitted.

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 retrospective application permitted.

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

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 will be effective prospectively for annual reporting periods beginning after December 15, 2025, and interim periods within those annual reporting periods.

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 ," which provides clarity on the current interim disclosure requirements.

The update also includes the addition of a disclosure principle which 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

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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 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.

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Natural gas and NGL sales .

Under the Company’s natural gas sales processing contracts for its Central Basin Platform properties and a portion of its Northwest Shelf assets, the Company delivers unprocessed natural gas to a midstream processing entity at the wellhead.

The midstream processing entity obtains control of the natural gas and NGLs at the wellhead.

The midstream processing entity gathers and processes the natural gas and NGLs and remits proceeds to the Company for the resulting sale of natural gas and NGLs.

Under these processing agreements, the Company recognizes revenue when control transfers to the purchaser at the point of delivery and it is probable the Company will collect the consideration it is entitled to receive.

Under the majority of the Company’s natural gas sales processing contracts, the Company delivers unprocessed natural gas 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.

Until April 30, 2022, under the Company's natural gas sales processing contracts for the bulk of our Northwest Shelf assets, the Company delivered unprocessed natural gas to a midstream processing entity at the wellhead.

However, the Company maintained ownership of the gas through processing and received proceeds from the marketing of the resulting products.

Under this processing agreement, the Company recognized the fees associated with the processing as an expense rather than netting these costs against Oil, Natural Gas, and Natural Gas Liquids Revenues in the Statements of Operations.

Beginning May 1, 2022, these contracts were combined into one contract, and it was modified so that the Company no longer maintained ownership of the gas through processing.

Accordingly, the Company from that point on accounts for any such fees and deductions as a reduction of the transaction price.

There remains only one contract with a natural gas processing entity in place where point of control of gas dictates requiring the fees be recorded as an expense.

The Company has only one minor contract 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 gas dictates that the associated fees are recorded as an expense.

Disaggregation of revenue.

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Natural gas liquids 8,922,072 11,621,355 11,676,963

11,621,355 11,676,963 7,493,234

Total oil, natural gas, and natural gas liquids revenues $ 307,178,072 $ 366,327,414 $ 361,056,001

(1) Beginning on July 1, 2022, the Company began reporting volumes and revenues on a three-stream basis, separately reporting crude oil, natural gas, and NGL sales.

For periods prior to July 1, 2022, sales revenues for NGLs were presented with natural gas.

(2) In 2024, the Company experienced a net negative total gas revenue, due to the significant reduction in gross realized sales prices per Mcf, coupled with the growth in the plant fees per Mcf.

(1) In 2024 and 2025, the Company experienced a net negative total gas revenue, due to the significant reduction in gross realized sales prices per Mcf, coupled with the growth in 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 under a five-year lease which began January 1, 2021.

The Midland office lease was amended effective October 1, 2022,

with the revised five-year lease ending September 30, 2027.

Beginning January 15, 2021, the Company entered into a five-and-a-half-year sub-lease for office space in The Woodlands, Texas;

however, effective as of May 31, 2023, The Woodlands office sub-lease was terminated.

On May 9, 2023, the Company entered into a 71-month (five years and 11-month) new lease for a larger amount of office space in The Woodlands, Texas.

At the time of the new lease commencement, the additional office space that was added was under construction and until completed, the rental obligation for this space had not yet commenced, because the Company did not have control of the additional office space in accordance with ASC 842-40-55-5.

On September 27, 2023, the Company provided a certificate of acceptance of premises to the lessor of the additional office space, and accordingly, the future payments for this space are included along with the other operating leases, reflected in the future lease payments schedule below.

The current Midland office is under a five-year lease, effective October 1, 2022 and ending September 30, 2027.

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.

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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 applied to a new vehicle.

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 December 31, 2025 are as follows:

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Operating lease payments $ 636,649 $ 460,497 $ 250,606 $ 149,628 $ — $ — $ 1,497,380

$ 727,460 $ 636,649 $ 460,497 $ 250,606 $ 149,628 $ — $ 2,224,840

Financing lease payments 803,745 465,880 159,374 — — — 1,428,999

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 December 31,

Operating leases

Weighted average remaining lease term (in years)

Weighted average discount rate

4.50 % 4.50 %

(1) The weighted average annual discount rate as of December 31, 2024 for operating leases was 4.50 %.

Based on this rate, the future lease payments above include imputed interest of $ 170,799 .

The weighted average remaining term of operating leases was 3.45 years.

(2) The weighted average annual discount rate as of December 31, 2024 for financing leases was 7.31 %.

Based on this rate, the future lease payments above include imputed interest of $ 114,566 .

The weighted average remaining term of financing leases was 1.85 years.

Finance leases

Weighted average remaining lease term (in years)

Weighted average discount rate

7.50 % 7.31 %

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

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(3) Amount included in Interest (expense)

During the year ended December 31, 2024, the Company sold some of its leased vehicles, driving the gain on disposal of $ 89,693 .

NOTE 4 — EARNINGS PER SHARE INFORMATION

During the years ended December 31, 2025, 2024, and 2023, the Company recorded a gain (loss) on disposal of assets, which was impacted by the sale of leased vehicles, as follows:

For the years ended December 31,

2025 2024 2023

Sale of owned vehicles

$ ( 6,974 ) $ ( 14,239 ) $ ( 132,109 )

Sale of leased vehicles

453,374 103,932 44,981

Gain (loss) on disposal of assets

$ 446,400 $ 89,693 $ ( 87,128 )

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 years ended December 31, 2025, 2024 and 2023.

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For the years ended December 31, 2025 2024 2023

Net Income $ 67,470,314 $ 104,864,641 $ 138,635,025

Net Income (Loss) $ ( 34,731,199 ) $ 67,470,314 $ 104,864,641

Basic Weighted-Average Shares Outstanding 204,984,223 197,937,683 190,589,143

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Diluted Weighted-Average Shares Outstanding 204,984,223 200,277,380 195,364,850

Basic Earnings per Share $ 0.34 $ 0.55 $ 1.14

Diluted Earnings per Share $ 0.34 $ 0.54 $ 0.98

Basic Earnings (Loss) per Share $ ( 0.17 ) $ 0.34 $ 0.55

Diluted Earnings (Loss) per Share $ ( 0.17 ) $ 0.34 $ 0.54

The following table presents the securities which were excluded from the Company's computation of diluted earnings (loss) per share for the years ended December 31, 2025, 2024 and 2023, as their effect would have been anti-dilutive.

2025 2024 2023

Antidilutive securities:

Anti-dilutive securities:

Stock options to purchase common stock 62,433 66,511 264,966

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Stronghold Acquisition

On July 1, 2022, Ring, as buyer, and Stronghold Energy II Operating, LLC, a Delaware limited liability company (“Stronghold OpCo”) and Stronghold Energy II Royalties, LP, a Delaware limited partnership (“Stronghold RoyaltyCo”, together with Stronghold OpCo, collectively, “Stronghold”), as seller, entered into a purchase and sale agreement (the “Purchase Agreement”).

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

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

On August 31, 2022, Ring completed the Stronghold Acquisition.

The fair value of consideration paid to Stronghold was approximately $ 394.0 million, of which $ 165.9 million, net of customary purchase price adjustments, was paid in cash at closing, $ 15.0 million was payable in cash after the six-month anniversary of the closing date of the Stronghold Acquisition.

The fair value of consideration paid to Stronghold was approximately $ 394.0 million, of which $ 165.9 million, net of customary purchase price adjustments, was paid in cash at closing, $ 15.0 million was paid in cash on the sixth-month anniversary of the closing date.

Shortly after closing, approximately $ 4.5 million was paid for inventory and vehicles and approximately $ 1.8 million was paid for August oil derivative settlements for certain novated hedges.

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The borrowing base of the $ 1.0 billion Credit Facility was increased from $ 350 million to $ 600 million at the closing of the Stronghold Acquisition.

The remaining consideration consisted of 21,339,986 shares of Ring common stock and 153,176 shares of newly created Series A Convertible Preferred Stock, par value $ 0.001 (“Preferred Stock”) which was converted into 42,548,892 shares of common stock on October 27, 2022.

Please see "NOTE 11 — STOCKHOLDERS' EQUITY" for further discussion.

The remaining consideration consisted of 21,339,986 shares of common stock and 153,176 shares of newly created Series A Convertible Preferred Stock, par value $ 0.001 (“Preferred Stock”) which was converted into 42,548,892 shares of common stock on October 27, 2022.

In addition, Ring assumed $ 24.8 million of derivative liabilities, $ 1.7 million of items in suspense and $ 14.5 million in asset retirement obligations.

The Stronghold Acquisition was accounted for as an asset acquisition in accordance with ASC Topic 805 – Business Combinations.

The fair value of the consideration paid by Ring and allocation of that amount to the underlying assets acquired, on a relative fair value basis, was recorded on Ring’s books as of the date of the closing of the Stronghold Acquisition.

Additionally, costs directly related to the Stronghold Acquisition were capitalized as a component of the purchase price.

Determining the fair value of the assets and liabilities acquired required judgment and certain assumptions to be made, the most significant of these being related to the valuation of Stronghold’s oil and gas properties.

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

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

Consideration:

Shares of Common Stock issued 21,339,986

Common Stock price as of August 31, 2022 $ 3.24

Common Stock Consideration $ 69,141,555

Shares of Preferred Stock issued 153,176

Aggregate Liquidation Preference $ 153,176,000

Conversion Price $ 3.60

As-Converted Shares of Common Stock 42,548,892

Common Stock Price as of August 31, 2022 $ 3.24

Preferred Stock Consideration $ 137,858,446

Cash consideration:

Closing amount paid to Stronghold $ 121,392,455

Escrow deposit paid 46,500,000

Cash paid for inventory and fixed assets 4,527,103

Cash paid for realized losses on August oil derivatives 1,777,925

Cash received for post-close adjustments, net ( 5,535,839 )

Total cash consideration 168,661,644

Fair value of deferred payment liability 14,807,276

Post-close settlement paid to Stronghold 3,511,170

Fair value of consideration paid to seller 393,980,091

Direct transaction costs 9,162,143

Total consideration $ 403,142,234

Fair value of assets acquired:

Oil and natural gas properties $ 439,589,683

Inventory and fixed assets 4,527,103

Amount attributable to assets acquired $ 444,116,786

Fair value of liabilities assumed:

Suspense liability $ 1,651,596

Derivative liabilities, marked to market 24,784,406

Asset retirement obligations 14,538,550

Amount attributable to liabilities assumed $ 40,974,552

Net assets acquired $ 403,142,234

Approximately $ 40.4 million of revenues and $ 13.6 million of direct operating expenses attributed to the Stronghold Acquisition were included in the Company’s Statements of Operations for the period from September 1, 2022 through December 31, 2022.

Delaware Basin Divestiture

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On July 10, 2023, the Company, as buyer, and Founders Oil & Gas IV, LLC (“Founders”), as seller, entered into an Asset Purchase Agreement (the “Founders Purchase Agreement”).

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

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

The Founders Acquisition was accounted for as an asset acquisition in accordance with ASC 805.

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CBP Vertical Well Sale

On September 30, 2024, the Company completed the sale of certain oil and gas properties, including vertical wells and associated facilities, within Andrews County, Texas and Gaines County, Texas to an unaffiliated party for a sales price of $ 5.5 million.

As part of the sale, the buyer assumed an asset retirement obligation balance of approximately $ 2.7 million.

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The purchase had an effective date of December 1, 2024 with a required down payment of $ 175,000 due at closing and the remainder of $ 1,175,000 due in January 2025.

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.

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

Closing amount paid to Lime Rock 63,599,939

Fair value of deferred payment liability 9,415,066

Post-close adjustments

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

Amount attributable to liabilities assumed $ 3,451,824

Net assets acquired $ 88,733,580

NOTE 6 — OIL AND NATURAL GAS PRODUCING ACTIVITIES

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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.

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.

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Although the counterparties hold the right to offset (i.e.

netting) the settlement amounts with the Company, in accordance with ASC 815-10-50-4B, the Company classifies the fair value of all its derivative positions on a gross basis in its Balance Sheets.

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 Balance Sheets.

The Company’s derivative financial instruments are recorded at fair value and included as either assets or liabilities in the accompanying Balance Sheets.

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Derivative assets, current $ 21,468,134 $ 5,497,057

Discounted deferred premiums — ( 1,553,323 )

Derivatives assets, current, net of premiums $ 5,497,057 $ 6,215,374

Derivative assets, noncurrent $ 9,739,430 $ 5,473,375

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The following tables reflect the details of current derivative contracts as of December 31, 2025 (quantities are in barrels (Bbl) for the oil derivative contracts and in million British thermal units (MMBtu) for the natural gas derivative contracts).

Oil Hedges (WTI)

Q1 2025 Q2 2025 Q3 2025 Q4 2025 Q1 2026 Q2 2026 Q3 2026 Q4 2026

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

Hedged volume (Bbl) 608,350 577,101 171,400 529,000 509,500 492,000 432,000 412,963

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Weighted average call price $ — $ — $ 72.50 $ — $ — $ — $ — $ —

Gas Hedges (Henry Hub)

Q1 2025 Q2 2025 Q3 2025 Q4 2025 Q1 2026 Q2 2026 Q3 2026 Q4 2026

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

Hedged volume (MMBtu) 448,854 1,165,628 600,016 1,072,305 439,678 423,035 1,079,906 1,046,151

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Weighted average call price $ 5.11 $ 5.42 $ 4.24 $ 5.42 $ 5.21 $ 4.32 $ — $ —

Oil Hedges (basis differential)

Q1 2025 Q2 2025 Q3 2025 Q4 2025 Q1 2026 Q2 2026 Q3 2026 Q4 2026

Argus basis swaps:

Hedged volume (Bbl)

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

Hedged volume (MMBtu) 1,012,567 984,322 956,865 931,539 908,117 886,933 866,585 846,134

Weighted average swap price $ 3.77 $ 3.77 $ 3.77 $ 3.77 $ 3.67 $ 3.67 $ 3.67 $ 3.67

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

El Paso Permian Basin basis swaps:

Hedged volume (MMBtu) — — — — 960,307 636,710 615,547 596,306

Weighted average spread price (1)

$ — $ — $ — $ — $ 0.72 $ 0.67 $ 0.67 $ 0.67

Waha basis swaps:

Hedged volume (MMBtu) — — — — 196,372 480,325 464,360 449,846

Weighted average spread price (1)

$ — $ — $ — $ — $ 0.78 $ 0.78 $ 0.78 $ 0.78

Gas Hedges (basis differential) Q1 2028 Q2 2028 Q3 2028 Q4 2028 Q1 2029 Q2 2029 Q3 2029 Q4 2029

El Paso Permian Basin basis swaps:

Hedged volume (MMBtu) 577,163 561,064 545,413 530,977 517,628 505,552 493,953 482,296

Weighted average spread price (1)

$ 0.60 $ 0.60 $ 0.60 $ 0.60 $ 0.57 $ 0.57 $ 0.57 $ 0.57

Waha basis swaps:

Hedged volume (MMBtu) 435,403 423,259 411,453 400,562 390,490 381,381 372,632 363,837

Weighted average spread price (1)

$ 0.68 $ 0.68 $ 0.68 $ 0.68 $ 0.63 $ 0.63 $ 0.63 $ 0.63

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

(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.

NOTE 8 — FAIR VALUE MEASUREMENTS

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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.

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).

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.

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NOTE 9 — REVOLVING LINE OF CREDIT

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

In April 2019, the Company amended and restated the Credit Agreement with the Administrative Agent (as amended and restated, the “Amended Credit Facility”).

On August 31, 2022, the Company modified its Amended Credit Facility through that certain Second Amended and Restated Credit Agreement (the "Second Credit Agreement"), extending the maturity date of the facility to August 2026 and the syndicate was modified to add five lenders, replacing five lenders.

On February 12, 2024, the Company, Truist Bank as the Administrative Agent and Issuing Bank, and the lenders party thereto (the "Lenders") entered into an amendment (the "Amendment") to the Second Credit Agreement.

Among other things, the Amendment amends the definition of Free Cash Flow so amounts used by the Company for acquisitions will no longer be subtracted from the calculation of Free Cash Flow.

The Second Credit Agreement has a borrowing base of $ 600 million, which is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time.

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 (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.

Rather than Eurodollar loans, the reference rate in the Second Credit Agreement is the SOFR.

Also, the Second Credit Agreement permits the Company to declare dividends for its equity owners, subject to certain limitations, including (i) no

default or event of default has occurred or will occur upon such payments, (ii) the pro forma Leverage Ratio (outstanding debt to adjusted earnings before interest, taxes, depreciation and amortization, exploration expenses, and all other non-cash charges acceptable to the Administrative Agent) does not exceed 2.00 to 1.00, (iii) the amount of such payments does not exceed Available Free Cash Flow (as defined in the Second Credit Agreement), and (iv) the Borrowing Base Utilization Percentage (as defined in the Second Credit Agreement) is not greater than 80 %.

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

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

The Second Credit Agreement contains certain covenants, which, among other things, require the maintenance of (i) a total Leverage Ratio of not more than 3.0 to 1.0 and (ii) a minimum ratio of Current Assets to Current Liabilities (as such terms are defined in the Second Credit Agreement) of 1.0 to 1.0.

The Second Credit Agreement also contains other customary affirmative and negative covenants and events of default.

The 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 is the Secured Overnight Financing Rate ("SOFR").

The interest rate on each SOFR Loan will (i) be 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) plus (iii) a 0.10 % SOFR adjustment.

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, which, among other things, require the maintenance of (i) a total Leverage Ratio of not more than 3.0 to 1.0 and (ii) a minimum ratio of Current Assets to Current Liabilities (as such terms are defined in the 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, if the borrowing base utilization is less than 25 % at the hedge testing date and the Leverage Ratio is not greater than 1.25 to 1.00, the required hedging percentage for months 13 through 24 of the rolling 24 month period provided for will be 0 % from such hedge testing date to the next succeeding hedge testing date and if the borrowing base utilization percentage is equal to or greater than 25 %, but less than 50 % and the Leverage Ratio is not greater than 1.25 to 1.00, the required hedging percentage for months 13 through 24 of the rolling 24 month period provided for will be 25 % from such hedge testing date to the next succeeding hedge testing date.

As of December 31, 2024, $ 385 million was outstanding on the Credit Facility and the Company was in compliance with all covenants in the Second Credit Agreement.

Under the Second Credit Agreement, the applicable percentage for the unused commitment fee is 0.5 % per annum for all levels of borrowing base utilization.

As of December 31, 2024, the Company's unused line of credit was $ 215.0 million, which was calculated by subtracting the outstanding Credit Facility balance of $ 385 million and standby letters of credit of $ 35,000 in total ($ 10,000 with state and federal agencies and $ 25,000 with an insurance company for New Mexico state surety bonds) from the $ 600 million borrowing base.

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 December 31, 2025, $ 420 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 December 31, 2025, the Company's unused line of credit was $ 165.0 million, which was calculated by subtracting the outstanding Credit Facility balance of $ 420 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.

NOTE 10 — ASSET RETIREMENT OBLIGATION

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Liabilities incurred 439,528

Liabilities sold

( 5,340,211 )

Liabilities settled ( 647,828 )

Revision of estimate (1)

Accretion expense 1,425,686

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

Liabilities acquired 2,090,777

Liabilities incurred 695,553

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Balance, December 31, 2024 $ 26,382,517

Liabilities acquired 2,780,280

Liabilities incurred 89,923

Liabilities sold

( 3,219,651 )

Liabilities settled ( 208,411 )

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(1) Several factors are considered in the annual review process, including current estimates for removal cost and estimated remaining useful life of the assets.

The revisions recorded during the year ended December 31, 2025 included updated interests for our working interest partners.

The revisions recorded during the years ended December 31, 2024 and 2023 were related to shorter estimated useful lives, with regards to planned dates to plug and abandon such assets.

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

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

December 31, 2025 December 31, 2024

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Gross proceeds totaled $ 16,089,582 .

Concurrently with the underwritten public offering, the Company closed on a registered direct offering of (i) 3,500,000 shares of common stock, (ii) 3,300,000 Pre-Funded Warrants and (iii) 6,800,000 Common Warrants at a combined

purchase price of $ 0.70 per share of common stock and Pre-Funded Warrants.

The Common Warrants have a term of five years ending in October 2025 and an exercise price of $ 0.80 per share.

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No Common Warrants were exercised during 2024, so a total of 78,200 Common Warrants remained outstanding as of December 31, 2024.

Common stock issued for Stronghold acquisition - As part of the Stronghold Acquisition, 21,339,986 shares of common stock were issued to the sellers.

Also as part of the Stronghold Acquisition, 153,176 shares of Preferred Stock were issued to the sellers.

Each share of Preferred Stock was automatically convertible into 277.7778 shares of common stock upon stockholder approval of the conversion.

On October 27, 2022, the Company’s stockholders approved the issuance of, 42,548,892 shares of common stock upon conversion of the 153,176 shares of our Preferred Stock.

The preferred shares were automatically converted into such common shares as of October 27, 2022.

Refer to "NOTE 5 — ACQUISITIONS & DIVESTITURES" for the purchase price consideration allocated to the aforementioned stock issuances.

Common stock issued for option exercises – During the year ended December 31, 2022, the Company issued 52,494 shares of common stock as a result of stock option exercises.

No stock options were exercised in 2023 or 2024.

The following tables present the details of the exercises:

exercised Exercise

price ($) Shares

issued Shares

retained Cash paid at

exercise ($) Stock price

on date of exercise

($) Aggregate value

of shares retained

2022 100,000 $ 2.00 52,494 47,506 $ — $ 4.21 $ 200,000

2022 Totals 100,000 52,494 47,506 $ — 200,000

2022 Weighted Averages $ 2.00 $ 4.21

In October 2025, the remaining 78,200 Common Warrants expired, and as such, no Common Warrants remained outstanding as of December 31, 2025.

NOTE 12 — EMPLOYEE STOCK OPTIONS, RESTRICTED STOCK AWARD PLAN, AND 401(K)

Compensation expense charged against income for share-based awards during the years ended December 31, 2024, 2023, and 2022 is shown in the table below.

Share-based compensation expense charged against income during the years ended December 31, 2025, 2024, and 2023 was as follows.

These amounts are included in General and administrative expense in the Statements of Operations.

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$ 6,135,957 $ 5,506,017 $ 8,833,425

During the year ended December 31, 2025, one former executive officer separated from the Company.

As part of the executive officer's separation agreement, the vesting of the officer’s outstanding performance stock units and restricted stock units were accelerated.

The impact to share-based compensation expense resulting from this modification was $ 133,671 .

During the year ended December 31, 2024, two former executive officers separated from the Company, with both officers forfeiting their performance stock units.

One officer entered into a consulting agreement with the Company which modified his restricted stock unit agreements to continue to vest through March 31, 2025.

The other officer forfeited his restricted stock units.

The total forfeitures related to these executive officers separating from the Company resulted in a reduction to share-based compensation expense of $ 1,448,076 .

In 2011, the Board of Directors (the "Board") of the Company approved and adopted a long-term incentive plan (the “2011 Plan”), which was subsequently approved and amended by the shareholders.

As of December 31, 2024, there were no shares available for future grants under the 2011 Plan.

In 2021, the Board and Company shareholders approved and adopted the Ring Energy, Inc.

As of December 31, 2025, there were no shares eligible for grant, either as stock options or as restricted stock, under the 2011 Plan.

In 2021, the Board and Company stockholders approved and adopted the Ring Energy, Inc.

2021 Omnibus Incentive Plan (the “2021 Plan”).

The 2021 Plan provides that the Company may grant options, stock appreciation rights, restricted shares, restricted stock units, performance-based awards, other share-based awards, other cash-based awards, or any combination of the foregoing.

At the 2023 Annual Meeting, the shareholders approved an amendment to the 2021 Plan to increase the number of shares available under the 2021 Plan by 6.0 million.

At the 2023 Annual Meeting of Stockholders, the stockholders approved an amendment to the 2021 Plan to increase the number of shares available under the 2021 Plan by 6.0 million.

At the 2025 Annual Meeting of Stockholders, the stockholders approved a second amendment to the 2021 Plan to increase the number of shares available under the 2021 Plan by 11.5 million.

As of December 31, 2025, there were 11,785,291 shares available for grant under the 2021 Plan.

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No stock options were exercised during 2025, 2024 or 2023.

Stock options exercised of 100,000 shares in 2022 had an aggregate intrinsic value on the date of exercise of $ 221,000 .

The following table summarizes information related to the Company’s stock options outstanding as of December 31, 2025:

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$ 10.18 51,000 0.77 51,000

11.75 36,000 1.95 36,000

$ 10.70 65,500 1.55 65,500

Restricted Stock Unit Grants – Following is a table reflecting the restricted stock unit grants during 2025, 2024 and 2023:

Grant date # of

restricted stock units

February 9, 2022 1,247,061

April 13, 2022 7,143

May 10, 2022 10,349

June 16, 2022 2,150

July 14, 2022 8,547

August 29, 2022 30,581

September 1, 2022 37,797

September 19, 2022 49,645

Grant date Restricted stock units granted

February 16, 2023 2,270,842

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December 9, 2024 83,000

February 12, 2025 3,691,373

April 29, 2025 76,177

Restricted stock unit grants issued prior to 2020 vest at the rate of 20 % each year over five years beginning one year from the date granted.

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On February 16, 2023, the Company granted a total of 1,162,162 PSUs to the Company's five executive officers (the "2023 PSU Awards").

The performance period for the 2023 PSU Awards began on January 1, 2023, and will end on December 31, 2025.

The performance period for the 2023 PSU Awards began on January 1, 2023, and ended on December 31, 2025.

In July 2024, two of the aforementioned executive officers separated from the Company, forfeiting 270,270 of these PSUs.

In September 2025, one of the aforementioned executive officers separated from the Company, and accelerated the vesting of 135,135 of these PSUs.

Based on the achievement of the performance goals for the 2023 PSU Awards, a total of 680,665 PSUs vested on December 31, 2025.

On April 30, 2024, the Company granted a total of 1,378,378 PSUs to the Company's five executive officers (the "2024 PSU Awards").

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In July 2024, two of the aforementioned executive officers separated from the Company, forfeiting 378,378 of these PSUs.

In September 2025, one of the aforementioned executive officers separated from the Company, and accelerated the vesting of 189,189 of these PSUs.

On April 29, 2025, the Company granted a total of 1,624,756 PSUs to the Company's six executive officers (the "2025 PSU Awards").

The performance period for the 2025 PSU Awards began on January 1, 2025, and will end on December 31, 2027.

In September 2025, one of the aforementioned executive officers separated from the Company, and accelerated the vesting of 225,576 of these PSUs.

A summary of the status of the PSU awards and changes during the years ended December 31, 2025, 2024 and 2023 are as follows:

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NOTE 13 — COMMITMENTS AND CONTINGENCIES

Standby Letters of Credit – A commercial bank previously issued standby letters of credit on behalf of the Company for $ 250,000 to the State of Texas, $ 10,000 to a federal agency and $ 500,438 to an insurance company to secure the surety bonds described below.

On February 23, 2024, the bank reduced the $ 500,438 standby letter of credit to $ 25,000 after approval of the insurance company, reduced the $ 250,000 standby letter of credit to the State of Texas to $ 0 , and retained the standby letter of credit to the federal agency at $ 10,000 .

As of December 31, 2024, the Company had total standby letters of credit outstanding of $ 35,000 .

The standby letters of credit are valid until cancelled or matured and are collateralized by the Credit Facility with the bank.

The terms of the letter of credit to the federal agency is extended for a term of one year at a time.

The Company intends to renew the standby letter of credit to the federal agency for as long as required.

Although the Company no longer operates any wells in the State of New Mexico, that standby letter of credit will need to be renewed until released.

No amounts have been drawn under the standby letters of credit.

Surety Bonds – An insurance company issued surety bonds on behalf of the Company totaling $ 500,438 to various State of New Mexico agencies in order for the Company to do business in the State of New Mexico.

The surety bonds are valid until canceled or matured.

The terms of the surety bonds are extended for a term of one year at a time.

As of December 31,

2024, the Company still had a surety bond in place of $ 25,000 for the State of New Mexico;

however, these bonds are expected to be eliminated once change of ownership is approved by the New Mexico Oil Conservation Division.

On January 10, 2024, two insurance companies issued surety bonds on behalf of the Company, one for $ 250,000 , a Texas Railroad Commission ("RRC") required blanket performance bond to operate 100 wells or more in the State of Texas, and one for $ 2,000,000 , an RRC required blanket plugging extension bond, each with zero collateral requirements.

The term for these two surety bonds ends on July 1, 2025 and they can be renewed at that time.

As of December 31, 2024, the Company had $ 2,275,000 in total surety bonds.

Surety Bonds – As of December 31, 2025 and 2024, 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 December 31, 2025 and 2024;

however, that bond will likely be released as the Company no longer operates wells in New Mexico.

Total expenses related to the RRC surety bonds were $ 38,000 and $ 29,585 for the years ended December 31, 2025 and 2024, respectively.

The New Mexico bond is supported by a $ 25,000 standby letter of credit collateralized by the Credit Facility with the bank.

Standby Letters of Credit – As of December 31, 2025 and 2024, 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 December 31, 2025 and 2024, and no liability has been recorded in the accompanying Balance Sheets related to these arrangements.

NOTE 14 — INCOME TAXES

For the years ended December 31, 2024, 2023, and 2022, components of our provision for income taxes are as follows:

Provision for Income Taxes:

For the years ended December 31, 2025, 2024, and 2023, components of our provision (benefit) for income taxes are as follows.

Provision for (Benefit from) Income Taxes:

2025 2024 2023

3 unchanged sentences

State deferred tax ( 173,339 ) 943,747 954,551

Provision for Income Taxes

Provision for (Benefit from) Income Taxes $ ( 7,452,746 ) $ 20,440,954 $ 125,242

The Company’s overall effective tax rates are 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 years ended December 31, 2025, 2024, and 2023 were as follows.

For the years ended December 31,

2025 2024 2023

The following is a reconciliation of income taxes computed using the U.S.

federal statutory rate to the provision for income taxes:

Effective tax rate (1)

17.7 % 23.3 % 0.1 %

(1) The effective tax rates for the years ended December 31, 2025 and 2024 differ from the U.S.

federal statutory rate of 21% primarily due to share-based and executive compensation and state income taxes.

The effective tax rate for the year ended December 31, 2023 was impacted by the release of valuation allowance on the Company's federal net deferred tax asset.

A tax benefit of $ 24.2 million was recorded in the year ended December 31, 2023.

The following is a reconciliation of the difference between the effective income tax rate and the U.S.

federal statutory rate, for the year ended December 31, 2025.

Rate Reconciliation:

Pre-tax book income (loss) $ ( 42,183,945 )

Tax provision (benefit) computed at the U.S.

federal statutory rate ( 8,858,628 ) 21.0 %

State and local income tax, net of federal income tax effect (1)

174,193 ( 0.4 )

Pre-tax book income (1)

Nontaxable or nondeductible items:

Share-based compensation and executive compensation disallowance 1,209,928 ( 2.9 )

Meals and entertainment 20,147 0.0

Other 1,614 0.0

Provision for (Benefit from) Income Taxes $ ( 7,452,746 ) 17.7 %

(1) State taxes in Texas made up the majority (greater than 50%) of the tax effect in this category.

As previously disclosed for the years ended December 31, 2024, and 2023, prior to the adoption of ASU 2023-09, the following is a reconciliation of the difference between the effective income tax rate and the U.S.

federal statutory rate.

Rate Reconciliation:

Pre-tax book income (loss) (2)

$ 87,911,268 $ 104,917,670

5 unchanged sentences

Non-deductible expenses and other 797,494 1,149,037

Provision for Income Taxes $ 20,440,954 $ 125,242 $ 8,408,724

Provision for (Benefit from) Income Taxes $ 20,440,954 $ 125,242

(2) Amount in the year ended December 31, 2023 represented pre-tax book income, net of income taxes paid.

1 unchanged sentence

The net deferred taxes consisted of the following as of December 31, 2025 and 2024.

Total 12/31/2023

Deferred Tax Assets

2 unchanged sentences

Asset retirement obligation 6,627,813 5,755,174

Fair value of derivative instruments — 224,209

§163(j) business interest expense carryforward 19,675,692 18,838,600

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Net Deferred Tax Liability $ ( 20,764,119 ) $ ( 28,591,802 )

The following table summarizes income taxes paid (net of refunds received) for the year ended December 31, 2025.

All jurisdictions in which income taxes paid (net of refunds received) were equal to or greater than five percent of total income taxes paid (net of refunds received) are included below (if the noted jurisdiction did not meet the five percent threshold for a particular year, the amount for that year is not included below).

Income taxes paid (net of refunds received) 2025

Federal income taxes $ —

State and local income taxes:

Texas $ 337,787

Total state and local income taxes, net of refunds $ 347,487

Total income taxes paid, net of refunds received $ 347,487

As of December 31, 2025, the Company had net operating loss carryforwards for federal income tax reporting purposes of approximately $ 96.9 million which, if unused, will begin to expire in 2033 and fully expire in 2037 and an additional $ 248.2 million that can be carried forward indefinitely.

The shares issued for the Stronghold Acquisition (further discussed in NOTE 5 — ACQUISITIONS & DIVESTITURES) resulted in the Company having an ownership change under Section 382 of the Internal Revenue Code of 1986, as amended.

Section 382 limits the availability of certain tax attributes, including net operating losses and disallowed interest carryforwards, to offset future taxable income of the Company.

Section 382 of the Internal Revenue Code of 1986, as amended, limits the availability of certain tax attributes, including net operating losses and disallowed interest carryforwards, to offset future taxable income of the Company.

In evaluating its need for a valuation allowance against its deferred tax assets, the Company has estimated the amount of tax attributes related to the pre-ownership change period to be available under Section 382 in periods in which it expects deferred tax liabilities to be realized based on currently available information.

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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.

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 Texas RRC.

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 of Engineering and Corporate Strategy;

Executive Vice President of Exploration and Geosciences;

and Vice President of Operations.

Executive Vice President and Chief Operations Officer;

Executive Vice President and Chief Exploration Officer;

Senior Vice President of Operations;

and Vice President and Interim Chief Financial 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.

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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 table below.

Refer to the table below.

For the years ended December 31,

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Total lease operating expenses $ 79,353,806 $ 78,310,949 $ 70,158,227

The following tables include a reconciliation of the total reportable segments' measures of profit or loss to the Company's consolidated income before income taxes.

Additionally included is a reconciliation between the reportable segments' assets to the Company's consolidated assets.

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.

For the year ended December 31, 2025

7 unchanged sentences

— ( 96,414,150 ) ( 96,414,150 )

Ceiling test impairment (3)

— ( 108,825,446 ) ( 108,825,446 )

Asset retirement obligation accretion — ( 1,490,255 ) ( 1,490,255 )

11 unchanged sentences

(3) All of the Company's assets are located within the United States.

As the CODM does not view depreciation, depletion and amortization as a significant Exploration and Production segment expense, the Company has included this expense within the Corporate column of the reconciliation table.

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 this expense within the Corporate column of the reconciliation table.

For the year ended December 31, 2024

7 unchanged sentences

— ( 98,702,843 ) ( 98,702,843 )

Ceiling test impairment (3)

Asset retirement obligation accretion — ( 1,380,298 ) ( 1,380,298 )

10 unchanged sentences

Capital expenditures $ 151,946,171 $ — $ 151,946,171

(3) All of the Company's assets are located within the United States.

For the year ended December 31, 2023

7 unchanged sentences

— ( 88,610,291 ) ( 88,610,291 )

Ceiling test impairment (3)

Asset retirement obligation accretion — ( 1,425,686 ) ( 1,425,686 )

4 unchanged sentences

Gain (loss) on derivative contracts — 2,767,162 2,767,162

Gain (loss) on disposal of assets — ( 87,128 ) ( 87,128 )

Other income — 198,935 198,935

Income (Loss) Before Benefit from (Provision for) Income Taxes $ 265,547,024 $ ( 160,557,141 ) $ 104,989,883

2 unchanged sentences

Capital expenditures $ 151,969,735 $ — $ 151,969,735

(3) All of the Company's assets are located within the United States.

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

8 unchanged sentences

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

* Represents less than 10%

NOTE 16 — LEGAL MATTERS

6 unchanged sentences

The Company has filed an answer and a counterclaim denying the allegations and asserting affirmative defenses that would bar or substantially limit the plaintiff’s claims, asserting breach of contract and requesting a declaratory judgment and attorneys’ fees and costs.

The parties have concluded discovery in the matter and are currently set for trial in the first quarter of 2025.

The parties have concluded discovery in the matter and are currently set for trial in the second quarter of 2026.

NOTE 17 — SUBSEQUENT EVENTS

Lime Rock Purchase and Sale Agreement 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").

The Purchase Agreement provides that the Company will acquire (the "Lime Rock Acquisition") interests in oil and gas leases and related property of Lime Rock located in the Central Basin Platform of Texas for a purchase price (the "Purchase Price") of approximately $ 90 million in cash with $ 80 million due at closing and $ 10 million due on the nine months anniversary of closing, and 7,388,799 shares of our common stock.

The Purchase Price is subject to customary purchase price adjustments with an effective date of October 1, 2024.

On February 26, 2025, in connection with the Purchase Agreement, the Company deposited $ 5.0 million in cash into a third party escrow account as a deposit pursuant to the Purchase Agreement, which will be credited against the Purchase Price upon the closing of the Lime Rock Acquisition.

In accordance with ASC Topic 855, Subsequent Events, the Company has evaluated all events subsequent to the balance sheet date of December 31, 2025, through the date these condensed financial statements were issued, March 4, 2026.

The Company did not have any material subsequent events to report.

RING ENERGY, INC.

10 unchanged sentences

(96,414,150) (98,702,843) (88,610,291)

Ceiling test impairment (108,825,446) — —

General and administrative (exclusive of corporate overhead) (4,162,391) (3,360,370) (2,839,401)

Income tax expense

(37,493,250) (208,917) (12,502,187)

Income tax benefit (expense) 774,233 (37,493,250) (208,917)

Results of Oil and Natural Gas Producing Operations

2 unchanged sentences

For the years ended December 31,

2025 2024 2023

Payments to acquire oil and natural gas properties

24 unchanged sentences

There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the Company’s control, such as commodity pricing.

Reserve engineering is a subjective process of estimating underground accumulations of oil and natural

gas that cannot be measured in an exact manner.

Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner.

The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment.

4 unchanged sentences

Except to the extent the Company acquires additional properties containing proved reserves or conducts successful exploration and development activities or both, the Company’s proved reserves will decline as reserves are produced.

The oil prices as of December 31, 2024, 2023 and 2022 are based on the respective 12-month unweighted average of the first of the month prices of the WTI spot prices which equates to $71.96 per barrel, $74.70 per barrel and $90.15 per barrel, respectively.

The oil prices as of December 31, 2025, 2024 and 2023 are based on the respective 12-month unweighted average of the first of the month prices of the WTI posted prices which equates to $61.82 per barrel, $71.96 per barrel and $74.70 per barrel, respectively.

The natural gas prices as of December 31, 2025, 2024 and 2023 are based on the respective 12-month unweighted average of the first of month prices of the Henry Hub spot price which equates to $3.387 per MMBtu, $2.130 per MMBtu and $2.637 per MMBtu, respectively.

3 unchanged sentences

For the year ended December 31,

Natural Gas (1)

Natural Gas Liquids (1)

Oil (Bbl) Gas (Mcf) Natural Gas Liquids (Bbl) Boe (1)

Proved Developed and Undeveloped Reserves

5 unchanged sentences

Revisions of previous quantity estimates (2)

(2,939,895) 12,652,046 2,171,955 1,340,734

End of year 90,320,048 176,180,576 33,594,344 153,277,821

3 unchanged sentences

Proved Undeveloped at end of year 30,211,919 54,756,570 10,140,860 49,478,875

(1) Six Mcf is deemed the equivalent of one Boe.

(2) Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history, a rule that undeveloped reserves must be drilled within five years of originally being booked, and/or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.

Notable changes in proved reserves for the year ended December 31, 2025 included the following:

• Extensions.

In 2025, extensions of 11.2 MMBoe were primarily the result of 41 newly added PUDs in addition to an active leasing program.

Also impacting extensions were three successfully drilled wells in the Northwest Shelf and Central Basin Platform.

• Purchase of minerals in place.

In 2025, the Company completed the acquisition of Lime Rock oil and gas leases and related property within Andrews County, as well as a few other minor acquisitions, that resulted in 14.0 MMBoe of additional reserves.

• Sales of minerals in place.

In 2025, the Company did not sell any reserves.

• Revision of previous quantity estimates.

In 2025, the positive revisions of prior reserves of 1.3 MMBoe consisted of a positive 7.2 MMBoe related to changes in performance and other economic factors, offset by a negative 5.9 MMBoe related to changes in price (including differentials and gathering related contract change that effects differentials).

For the year ended December 31,

Natural Gas (1)

Natural Gas Liquids (1)

Oil (Bbl) Gas (Mcf) Natural Gas Liquids (Bbl) Boe (1)

Proved Developed and Undeveloped Reserves

5 unchanged sentences

Revisions of previous quantity estimates (2)

(6,730,246) (730,235) 3,621,245 (3,230,707)

End of year 80,904,071 149,817,162 28,303,085 134,176,684

3 unchanged sentences

Proved Undeveloped at end of year 24,797,357 47,279,051 8,876,698 41,553,897

(1) Oil reserves are stated in barrels;

natural gas reserves are stated in thousand cubic feet;

NGL reserves are stated in

Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.

(1) Six Mcf is deemed the equivalent of one Boe.

Notable changes in proved reserves for the year ended December 31, 2024 included the following:

5 unchanged sentences

In 2024, the Company sold 1.2 MMBoe from the divestiture of certain oil and gas properties, including vertical wells and associated facilities, within the Central Basin Platform in Andrews and Gaines Counties.

• Revision of previous estimates.

• Revision of previous quantity estimates.

In 2024, the negative revisions of prior reserves of 3.2 MMBoe consisted of a positive 0.2 MMBoe related to changes in price (including differentials and gathering related contract change that effects differentials), offset by a negative 3.4 MMBoe related to changes in performance and other economic factors.

For the year ended December 31,

Oil (Bbl) Gas (Mcf) Natural Gas Liquids (Bbl) Boe (1)

Proved Developed and Undeveloped Reserves

Beginning of year 88,704,743 157,870,449 23,105,658 138,122,143

Purchase of minerals in place 6,543,640 3,372,965 1,089,382 8,195,183

Extensions, discoveries and improved recovery 3,098,845 4,113,480 1,014,343 4,798,768

Sales of minerals in place (4,897,921) (2,674,955) (392,953) (5,736,700)

Production (4,579,942) (6,339,158) (976,852) (6,613,320)

Revisions of previous quantity estimates (2)

(6,728,088) (9,946,459) (621,014) (9,006,845)

End of year 82,141,277 146,396,322 23,218,564 129,759,229

Proved Developed at beginning of year 57,012,137 106,399,050 15,332,804 90,078,116

Proved Undeveloped at beginning of year 31,692,606 51,471,399 7,772,854 48,044,027

Proved Developed at end of year 56,029,039 99,896,022 15,449,907 88,128,284

Proved Undeveloped at end of year 26,112,238 46,500,300 7,768,657 41,630,945

(1) Six Mcf is deemed the equivalent of one Boe.

Notable changes in proved reserves for the year ended December 31, 2023 included the following:

• Extensions.

In 2023, extensions of 4.8 MMBoe were primarily the result of the successful operated drilling program and non-operated activity in the Northwest Shelf and Central Basin Platform.

• Purchase of minerals in place.

In 2023, the Company completed the acquisition of Founders oil and gas leases and related property within Ector County that resulted in 8.2 MMBoe in additional reserves.

• Sales of minerals in place.

In 2023, the Company sold 5.7 MMBoe from the divestiture of the Delaware Basin assets (30%), the New Mexico operated assets (57%), and part of the Company's assets in Gaines County (13%).

• Revision of previous quantity estimates.

In 2023, the negative revisions of prior reserves of 9.0 MMBoe consisted of 5.3 MMBoe (59%) related to changes in price and 3.7 MMBoe (41%) related to changes in performance and other economic factors.

Standardized Measure of Discounted Future Net Cash Flows – The standardized measure of discounted future net cash flows is computed by applying the price according to the SEC guidelines for oil and natural gas to the estimated future production of proved oil and natural gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on year-end statutory tax rates) to be incurred on pretax net cash flows less tax basis of the properties and available credits, and assuming continuation of existing economic conditions.

28 unchanged sentences

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 9A. Controls and Procedures