Ring Energy (NYSE: REI) books $220.6M Q1 loss on $162M impairment
Filing Impact
Filing Sentiment
Form Type
10-Q
Ring Energy, Inc. reported a first-quarter 2026 net loss of $220.6 million, driven mainly by a non-cash full cost ceiling test impairment of $162.1 million on oil and gas properties and a $82.2 million loss on derivative contracts. Oil, natural gas and NGL revenues were $73.7 million, down from $79.1 million a year earlier, as lower natural gas realizations produced net negative gas revenue.
Despite the accounting loss, net cash provided by operating activities was $25.9 million. The company invested $34.5 million in oil and gas properties, including development spending and a Yoakum County working interest acquisition, partly offset by proceeds of about $4.3 million from a non-operated interest sale. Total assets declined to $1.25 billion from $1.41 billion, and stockholders’ equity fell to $622.0 million as of March 31 2026.
Ring carried $426.0 million outstanding on its revolving credit facility against a $585.0 million borrowing base and remained in covenant compliance, leaving roughly $159.0 million of availability including letters of credit. Management also recorded a $25 million valuation allowance against federal deferred tax assets, lowering the effective tax benefit rate to 5.15%. The quarter included a correction of an immaterial prior-period error related to suspense revenues and ownership assignments, which increased retained earnings and reduced accounts payable and deferred income taxes.
Positive
- None.
Negative
- Significant non-cash ceiling test impairment: Ring recorded a $162.1 million full cost ceiling impairment in Q1 2026 due to lower oil-price impacts on the present value of reserves, materially reducing property values and contributing to a large net loss.
- Large loss on derivative contracts and higher hedge liabilities: The company reported a $82.2 million loss on derivative contracts and saw commodity derivative liabilities rise to $60.3 million, indicating unfavorable hedge mark-to-market movements.
- Equity and asset base reduced sharply: Total assets declined to $1.25 billion from $1.41 billion, and stockholders’ equity fell to $622.0 million, reflecting the impairment and net loss.
- Valuation allowance on deferred tax assets: Management recorded a new $25 million valuation allowance against federal deferred tax assets, citing a three-year cumulative loss position, which limits expected future tax benefits.
Insights
Large non-cash impairment and hedge losses drive a deep quarterly loss despite positive operating cash flow.
Ring Energy posted a first-quarter 2026 loss before taxes of $232.6 million, reversing a profit in 2025. The key driver was a full cost ceiling test impairment of $162.1 million tied to lower oil-price assumptions, which sharply reduced the net book value of its oil and gas properties.
Commodity risk management also moved against the company: it recorded a $82.2 million loss on derivative contracts, including sizable unrealized losses as hedge positions were marked to market. At the same time, derivative liabilities swelled to $60.3 million from $3.4 million, while derivative assets fell to $11.2 million. This combination heavily weighed on reported earnings but is partly non-cash.
Operationally, the core business still generated $25.9 million of operating cash flow, funding most of $34.5 million in capital expenditures. Net borrowings on the revolving credit facility increased modestly to an outstanding balance of $426.0 million, with about $159.0 million of borrowing base availability remaining. Management also booked a new $25 million valuation allowance against federal deferred tax assets, which dampened the income tax benefit and signals more cautious expectations about utilizing net operating losses.
Key Figures
Oil, natural gas and NGL revenues: $73,671,664
Net income (loss): $(220,591,482)
Ceiling test impairment: $162,086,257
+5 more
8 metrics
Oil, natural gas and NGL revenues
$73,671,664
For the three months ended March 31, 2026
Net income (loss)
$(220,591,482)
For the three months ended March 31, 2026
Ceiling test impairment
$162,086,257
Impairment of oil and natural gas properties in Q1 2026
Loss on derivative contracts
$(82,230,925)
For the three months ended March 31, 2026
Net cash provided by operating activities
$25,894,701
For the three months ended March 31, 2026
Revolving line of credit outstanding
$426,000,000
Balance as of March 31, 2026
Stockholders’ equity
$621,977,948
As of March 31, 2026
Valuation allowance recorded
$25,000,000
Federal deferred tax assets in the three months ended March 31, 2026
Key Terms
ceiling test impairment, full cost method, asset retirement obligation, costless collars, +2 more
6 terms
ceiling test impairment financial
"the Company recorded impairments on oil and natural gas properties as a result of the ceiling test of $162,086,257."
A ceiling test impairment is an accounting check that compares the recorded value of an asset to the maximum amount that can realistically be recovered from it; if the recorded value is higher than that recoverable amount (the “ceiling”), the company must write the asset down to that lower number. For investors this matters because such write-downs lower reported profits and net asset values, and they signal that future cash flows tied to the asset may be weaker than previously expected — think of marking a car’s book value down to what you could actually sell it for today.
full cost method financial
"Oil and natural gas properties, full cost method | 1,761,765,033 | 1,891,510,431"
The full cost method is an accounting approach that treats nearly all exploration and development spending as an asset on the balance sheet rather than as immediate expense, then spreads that cost over the life of the discovered resource. For investors, it can make profits look steadier and assets larger in the short term, but it can also mask failed projects and trigger big write-downs later if expected reserves or prices fall—similar to counting every shopping trip as a long-term pantry investment instead of a current expense.
asset retirement obligation financial
"The Company’s ARO relates to future plugging and abandonment expenses of its oil and natural gas properties and related facilities disposal."
A liability recorded for the future cost to retire, dismantle or clean up a long-lived asset — for example removing an oil rig, closing a mine, or decommissioning a plant. Investors care because it reduces reported profit and ties up capital: companies must estimate and set aside money now for a known future expense, and changes to that estimate can swing earnings, debt ratios and the company’s cash needs much like setting aside savings to repair or return a rented property later.
costless collars financial
"The Company has historically used costless collars, deferred premium puts, or swaps for this purpose."
A costless collar is a hedging strategy where an investor buys a protective option that limits losses and simultaneously sells an option that caps gains so the two premiums roughly cancel out. Think of it like buying insurance on a car while agreeing to share any big windfall from its sale with the insurer — it protects your downside without an upfront payment, but it also limits how much you can profit. Investors use it to reduce risk on a position while preserving capital and avoiding immediate cash outlay.
valuation allowance financial
"the Company recorded $25 million of valuation allowance as part of the estimated annual effective tax rate"
A valuation allowance is a reserve set aside to reduce the value of certain assets on a company's financial records when there is uncertainty about whether they will generate the expected benefits. It acts like a caution sign, indicating that some assets might not be fully recoverable or worth their recorded amount. This matters to investors because it provides a more realistic picture of a company's financial health and potential risks.
borrowing base financial
"The Credit Agreement has a borrowing base of $585 million, which is subject to periodic redeterminations"
A borrowing base is the amount a lender will allow a company to borrow based on the value of assets the company offers as security, typically things like accounts receivable and inventory. It matters to investors because it sets a practical ceiling on short-term financing and influences a company’s liquidity and risk: if the borrowing base falls, the company may lose access to cash or be forced to sell assets, which can affect operations and share value.
Earnings Snapshot
Oil, natural gas and NGL revenues: $73,671,664
Q1 2026
Oil, natural gas and NGL revenues
$73,671,664
Net income (loss)
$(220,591,482)
Net cash from operating activities
$25,894,701
Table of Contents
United States
Securities and Exchange Commission
Washington, D.C. 20549
Form 10-Q
For the quarterly period ended March 31, 2026
For the transition period from ______ to ______
Commission file number 001-36057
(Exact name of registrant as specified in its charter)
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | ||||
| (Address of principal executive offices) | (Zip Code) | ||||
( | |||||
| (Registrant’s telephone number, including area code) | |||||
Securities registered under Section 12(b) of the Exchange Act:
| Title of Each Class | Trading Symbol | Name of Each Exchange on Which Registered | ||||||
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
| Large accelerated filer | o | x | ||||||||||||
| Non-accelerated filer | o | (Do not check if a smaller reporting company) | Smaller reporting company | |||||||||||
| Emerging growth company | ||||||||||||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is shell company (as defined in Rule 12b-2 of the Act). Yes o No x
As of May 6, 2026, the registrant had outstanding 209,409,180 shares of common stock ($0.001 par value).
Table of Contents
TABLE OF CONTENTS
PART I — FINANCIAL INFORMATION | |||||||||||
Item 1: | Condensed Financial Statements | 5 | |||||||||
Notes to the Condensed Financial Statements | 12 | ||||||||||
Item 2: | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 37 | |||||||||
Item 3: | Quantitative and Qualitative Disclosures About Market Risk | 48 | |||||||||
Item 4: | Controls and Procedures | 49 | |||||||||
PART II — OTHER INFORMATION | |||||||||||
Item 1: | Legal Proceedings | 49 | |||||||||
Item 1A: | Risk Factors | 49 | |||||||||
Item 2: | Unregistered Sales of Equity Securities and Use of Proceeds | 49 | |||||||||
Item 3: | Defaults Upon Senior Securities | 49 | |||||||||
Item 4: | Mine Safety Disclosures | 50 | |||||||||
Item 5: | Other Information | 50 | |||||||||
Item 6: | Exhibits | 50 | |||||||||
SIGNATURES | 51 | ||||||||||
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Forward Looking Statements
This Quarterly Report on Form 10-Q (herein, “Quarterly Report”) contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Quarterly Report regarding our strategy, future operations, financial position, estimated revenues and expenses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report, the words “may,” “will,” “could,” “would,” “should,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “plan,” “pursue,” “target,” “continue,” “potential,” “guidance,” “project” or other similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. All forward-looking statements speak only as of the date of this Quarterly Report. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Quarterly Report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We are making investors aware that such forward-looking statements, because they relate to future events, are by their very nature subject to many important factors that could cause actual results to differ materially from those contemplated. Such factors include:
•declines or volatility in the prices we receive for our oil and natural gas;
•our ability to raise additional capital to fund future capital expenditures;
•our ability to generate sufficient net cash provided by operating activities, borrowings or other sources to enable us to fully develop and produce our oil and natural gas properties;
•general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business;
•risks associated with drilling of wells, including completion risks, cost overruns, mechanical failures and the drilling of non-economic wells or dry holes;
•uncertainties associated with estimates of proved oil and natural gas reserves;
•the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;
•the effects of inflation on our cost structure;
•substantial declines in the estimated values of our proved oil and natural gas reserves and potential full-cost ceiling impairment;
•our ability to replace our oil and natural gas reserves;
•the effects of rising interest rates on our cost of capital and the actions that central banks around the world undertake to control inflation, including the impacts such actions have on general economic conditions;
•unanticipated reductions in the borrowing base under our credit agreement;
•the potential for production decline rates and associated production costs for our wells to be greater than we forecast;
•risks and liabilities associated with the acquisition and integration of companies and properties;
•cost and availability of drilling rigs, and related equipment, supplies, personnel, and oilfield services;
•geological concentration of our oil and natural gas reserves;
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•the timing and extent of our success in acquiring, discovering, developing, and producing oil and natural gas reserves;
•our dependence on the availability, use and disposal of water in our drilling, completion and production operations;
•significant competition for oil and natural gas acreage and acquisitions;
•environmental or other governmental regulations, including legislation related to hydraulic fracture stimulation and climate change measures;
•our ability to secure reliable transportation for oil and natural gas we produce and to sell the oil and natural gas at market prices;
•future environmental, social and governance ("ESG") compliance developments and increased attention to such matters which could adversely affect our ability to raise equity and debt capital;
•management’s ability to execute our plans to meet our optimal goals;
•the occurrence of cybersecurity incidents, attacks or other breaches to our information technology systems or on systems and infrastructure used by the oil and gas industry;
•our ability to find and retain highly skilled personnel and our ability to retain key members of our management team on commercially reasonable terms;
•adverse weather conditions;
•costs and liabilities associated with environmental, health, and safety laws;
•the effect of our oil and natural gas derivative activities;
•social unrest, political instability, or armed conflict in major oil and natural gas producing regions outside the United States, including evolving geopolitical and military hostilities in the Middle East (including the recent conflict between the United States and Iran), Russia, and Ukraine and acts of terrorism or sabotage;
•the short and long-term potential impact to us of worsening trade relations and related economic disruptions including, but not limited to, inflation, energy price volatility, tariffs, trade wars, and supply chain disruptions;
•our insurance coverage may not adequately cover all losses that may be sustained in connection with our business activities;
•possible adverse results from litigation and the use of financial resources to defend ourselves; and
•the other factors discussed in Part I, Item 1A-- “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2025, as well as in our condensed financial statements, related notes, and the other financial information appearing elsewhere in this Quarterly Report and our other reports filed from time to time with the Securities and Exchange Commission (the “SEC”).
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date that such statements are made. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.
Unless the context otherwise requires, references in this Quarterly Report to “Ring,” “Ring Energy,” the “Company,” “we,” “us,” “our” or “ours” refer to Ring Energy, Inc.
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PART I — FINANCIAL INFORMATION
Item 1. Condensed Financial Statements
The following (a) condensed balance sheet as of December 31, 2025 which has been derived from our audited financial statements, and (b) the unaudited condensed financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission ("SEC"). Accordingly, certain disclosures by accounting principles generally accepted in the United States ("GAAP") and normally included in Annual Reports on Form 10-K have been omitted. Although management believes that our disclosures are adequate to make the information presented not misleading, these unaudited interim condensed financial statements should be read in conjunction with the Company's audited financial statements and related notes included in its most recent Annual Report on Form 10-K.
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RING ENERGY, INC.
CONDENSED BALANCE SHEETS
(Unaudited)
| March 31, 2026 | December 31, 2025 | |||||||||||||
| ASSETS | ||||||||||||||
| Current Assets | ||||||||||||||
| Cash and cash equivalents | $ | $ | ||||||||||||
| Accounts receivable | ||||||||||||||
| Joint interest billing receivables, net | ||||||||||||||
| Derivative assets | ||||||||||||||
| Inventory | ||||||||||||||
| Prepaid expenses and other assets | ||||||||||||||
| Total Current Assets | ||||||||||||||
| Properties and Equipment | ||||||||||||||
| Oil and natural gas properties, full cost method | ||||||||||||||
| Financing lease asset subject to depreciation | ||||||||||||||
| Fixed assets subject to depreciation | ||||||||||||||
| Total Properties and Equipment | ||||||||||||||
| Accumulated depreciation, depletion and amortization | ( | ( | ||||||||||||
| Net Properties and Equipment | ||||||||||||||
| Operating lease asset | ||||||||||||||
| Derivative assets | ||||||||||||||
| Deferred financing costs | ||||||||||||||
| Total Assets | $ | $ | ||||||||||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||||||||
| Current Liabilities | ||||||||||||||
| Accounts payable | $ | $ | ||||||||||||
| Income tax liability | ||||||||||||||
| Financing lease liability | ||||||||||||||
| Operating lease liability | ||||||||||||||
| Derivative liabilities | ||||||||||||||
| Notes payable | ||||||||||||||
| Asset retirement obligations | ||||||||||||||
| Total Current Liabilities | ||||||||||||||
| Non-current Liabilities | ||||||||||||||
| Deferred income taxes | ||||||||||||||
| Revolving line of credit | ||||||||||||||
| Financing lease liability, less current portion | ||||||||||||||
| Operating lease liability, less current portion | ||||||||||||||
| Derivative liabilities | ||||||||||||||
| Asset retirement obligations | ||||||||||||||
| Total Liabilities | ||||||||||||||
Commitments and contingencies (See Note 12) | ||||||||||||||
| Stockholders' Equity | ||||||||||||||
Preferred stock - $ | ||||||||||||||
Common stock - $ | ||||||||||||||
| Additional paid-in capital | ||||||||||||||
| Retained earnings (Accumulated deficit) | ( | |||||||||||||
| Total Stockholders’ Equity | ||||||||||||||
| Total Liabilities and Stockholders' Equity | $ | $ | ||||||||||||
The accompanying notes are an integral part of these unaudited condensed financial statements.
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RING ENERGY, INC.
CONDENSED STATEMENTS OF OPERATIONS
(Unaudited)
For the Three Months Ended | ||||||||||||||||||||||||||
| March 31, 2026 | March 31, 2025 | |||||||||||||||||||||||||
| Oil, Natural Gas, and Natural Gas Liquids Revenues | $ | $ | ||||||||||||||||||||||||
| Costs and Operating Expenses | ||||||||||||||||||||||||||
| Lease operating expenses | ||||||||||||||||||||||||||
| Gathering, transportation and processing costs | ||||||||||||||||||||||||||
| Ad valorem taxes | ||||||||||||||||||||||||||
| Oil and natural gas production taxes | ||||||||||||||||||||||||||
| Depreciation, depletion and amortization | ||||||||||||||||||||||||||
| Ceiling test impairment | ||||||||||||||||||||||||||
| Asset retirement obligation accretion | ||||||||||||||||||||||||||
| Operating lease expense | ||||||||||||||||||||||||||
| General and administrative expense | ||||||||||||||||||||||||||
| Total Costs and Operating Expenses | ||||||||||||||||||||||||||
| Income (Loss) from Operations | ( | |||||||||||||||||||||||||
| Other Income (Expense) | ||||||||||||||||||||||||||
| Interest income | ||||||||||||||||||||||||||
| Interest (expense) | ( | ( | ||||||||||||||||||||||||
| Gain (loss) on derivative contracts | ( | ( | ||||||||||||||||||||||||
| Gain (loss) on disposal of assets | ||||||||||||||||||||||||||
| Other income | ||||||||||||||||||||||||||
| Net Other Income (Expense) | ( | ( | ||||||||||||||||||||||||
| Income (Loss) Before Benefit from (Provision for) Income Taxes | ( | |||||||||||||||||||||||||
| Benefit from (Provision for) Income Taxes | ( | |||||||||||||||||||||||||
| Net Income (Loss) | $ | ( | $ | |||||||||||||||||||||||
| Basic Earnings (Loss) per Share | $ | ( | $ | |||||||||||||||||||||||
| Diluted Earnings (Loss) per Share | $ | ( | $ | |||||||||||||||||||||||
The accompanying notes are an integral part of these unaudited condensed financial statements.
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RING ENERGY, INC.
CONDENSED STATEMENT OF STOCKHOLDERS’ EQUITY
(Unaudited)
| Common Stock | Additional Paid-in Capital | Retained Earnings (Accumulated Deficit) | Total Stockholders' Equity | |||||||||||||||||||||||||||||
For the Three Months Ended March 31, 2026 | Shares | Amount | ||||||||||||||||||||||||||||||
| Balance, December 31, 2025 | $ | $ | $ | $ | ||||||||||||||||||||||||||||
| Restricted stock vested | ( | — | ||||||||||||||||||||||||||||||
| Shares to cover tax withholdings for restricted stock vested | ( | ( | — | |||||||||||||||||||||||||||||
| Payments to cover tax withholdings for restricted stock vested, net | — | — | ( | — | ( | |||||||||||||||||||||||||||
| Share-based compensation | — | — | — | |||||||||||||||||||||||||||||
| Net loss | — | — | — | ( | ( | |||||||||||||||||||||||||||
| Balance, March 31, 2026 | $ | $ | $ | ( | $ | |||||||||||||||||||||||||||
For the Three Months Ended March 31, 2025 | ||||||||||||||||||||||||||||||||
| Balance, December 31, 2024 | $ | $ | $ | $ | ||||||||||||||||||||||||||||
| Restricted stock vested | ( | — | ||||||||||||||||||||||||||||||
| Shares to cover tax withholdings for restricted stock vested | ( | ( | — | |||||||||||||||||||||||||||||
| Payments to cover tax withholdings for restricted stock vested, net | — | — | ( | — | ( | |||||||||||||||||||||||||||
| Common stock issuance for Lime Rock Acquisition | — | |||||||||||||||||||||||||||||||
| Share-based compensation | — | — | — | |||||||||||||||||||||||||||||
| Net income | — | — | — | |||||||||||||||||||||||||||||
| Balance, March 31, 2025 | $ | $ | $ | $ | ||||||||||||||||||||||||||||
The accompanying notes are an integral part of these unaudited condensed financial statements.
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RING ENERGY, INC.
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
For the Three Months Ended | ||||||||||||||
| March 31, 2026 | March 31, 2025 | |||||||||||||
| Cash Flows From Operating Activities | ||||||||||||||
| Net income (loss) | $ | ( | $ | |||||||||||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities | ||||||||||||||
| Depreciation, depletion and amortization | ||||||||||||||
| Ceiling test impairment | ||||||||||||||
| Asset retirement obligation accretion | ||||||||||||||
| Amortization of deferred financing costs | ||||||||||||||
| Share-based compensation | ||||||||||||||
| Credit loss expense | ||||||||||||||
| (Gain) loss on disposal of assets | ( | |||||||||||||
| Deferred income tax expense (benefit) | ( | |||||||||||||
| Excess tax expense (benefit) related to share-based compensation | ||||||||||||||
| (Gain) loss on derivative contracts | ||||||||||||||
| Cash received (paid) for derivative settlements, net | ( | ( | ||||||||||||
| Changes in operating assets and liabilities: | ||||||||||||||
| Accounts receivable | ( | ( | ||||||||||||
| Inventory | ( | |||||||||||||
| Prepaid expenses and other assets | ||||||||||||||
| Accounts payable | ( | |||||||||||||
| Settlement of asset retirement obligation | ( | ( | ||||||||||||
| Net Cash Provided by Operating Activities | ||||||||||||||
| Cash Flows From Investing Activities | ||||||||||||||
| Payments for the Lime Rock Acquisition | ( | |||||||||||||
| Payments to purchase oil and natural gas properties | ( | ( | ||||||||||||
| Payments to develop oil and natural gas properties | ( | ( | ||||||||||||
| Payments to acquire or improve fixed assets subject to depreciation | ( | |||||||||||||
| Proceeds from sale of fixed assets subject to depreciation | ||||||||||||||
| Proceeds from divestiture of oil and natural gas properties | ||||||||||||||
| Net Cash Used in Investing Activities | ( | ( | ||||||||||||
| Cash Flows From Financing Activities | ||||||||||||||
| Proceeds from revolving line of credit | ||||||||||||||
| Payments on revolving line of credit | ( | ( | ||||||||||||
| Payments for taxes withheld on vested restricted shares, net | ( | ( | ||||||||||||
| Payments on notes payable | ( | ( | ||||||||||||
| Payment of deferred financing costs | ( | |||||||||||||
| Reduction of financing lease liabilities | ( | ( | ||||||||||||
| Net Cash Provided by (Used in) Financing Activities | ||||||||||||||
| Net Increase (Decrease) in Cash | ( | |||||||||||||
| Cash at Beginning of Period | ||||||||||||||
| Cash at End of Period | $ | $ | ||||||||||||
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RING ENERGY, INC.
CONDENSED STATEMENTS OF CASH FLOWS (CONTINUED)
(Unaudited)
For the Three Months Ended | ||||||||||||||
| March 31, 2026 | March 31, 2025 | |||||||||||||
| Supplemental Cash Flow Information | ||||||||||||||
| Cash paid for interest | $ | $ | ||||||||||||
| Cash paid (refunded) for income taxes | ( | ( | ||||||||||||
| Noncash Investing and Financing Activities | ||||||||||||||
| Asset retirement obligation incurred during development | $ | $ | ||||||||||||
| Asset retirement obligation acquired | ||||||||||||||
| Asset retirement obligation revision of estimate | ||||||||||||||
| Asset retirement obligation sold | ( | |||||||||||||
Financing lease assets obtained in exchange for new financing lease liability, net (1) | ||||||||||||||
| Change in capitalized expenditures attributable to drilling projects financed through current liabilities | ||||||||||||||
| Lime Rock Acquisition Supplemental Schedule | ||||||||||||||
| Investing Activities - Cash Paid | ||||||||||||||
| Cash paid to Lime Rock on closing | $ | $ | ||||||||||||
| Escrow deposit released at closing | ||||||||||||||
| Direct transaction costs | ||||||||||||||
| Cash paid for fixed assets acquired | ( | |||||||||||||
| Payments for the Lime Rock Acquisition | $ | $ | ||||||||||||
| Investing Activities - Noncash | ||||||||||||||
| Assumption of suspense liability | $ | $ | ||||||||||||
| Assumption of asset retirement obligation | ||||||||||||||
| Deferred cash payment at fair value | ||||||||||||||
| Financing Activities - Noncash | ||||||||||||||
| Common stock issued for acquisition | $ | $ | ||||||||||||
(1) Included within the financing lease assets obtained in exchange for new financing lease liability, net is $— of finance lease asset terminations for the three months ended March 31, 2026. For the three months ended March 31, 2025, the Company had $37,381 in finance lease asset terminations.
The accompanying notes are an integral part of these unaudited condensed financial statements.
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RING ENERGY, INC.
NOTES TO CONDENSED FINANCIAL STATEMENTS
(UNAUDITED)
Index to the Notes to the Condensed Financial Statements
Note 1 — Basis of Presentation & Significant Accounting Policies | Note 8 — Revolving Line of Credit | ||||
Note 2 — Revenue Recognition | Note 9 — Asset Retirement Obligation | ||||
Note 3 — Leases | Note 10 — Common Warrants | ||||
Note 4 — Earnings (Loss) Per Share Information | Note 11 — Share-Based Compensation | ||||
Note 5 — Acquisitions and Divestitures | Note 12 — Commitments and Contingencies | ||||
Note 6 — Derivative Financial Instruments | Note 13 — Segment Reporting | ||||
Note 7 — Fair Value Measurements | Note 14 — Subsequent Events | ||||
NOTE 1 — BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES
Condensed Financial Statements – The accompanying condensed financial statements prepared by Ring Energy, Inc., a Nevada corporation (the “Company,” "Ring Energy," “Ring,” "we," "us," or "our"), have not been audited by an independent registered public accounting firm. In the opinion of the Company’s management, the accompanying unaudited condensed financial statements contain all adjustments necessary for fair presentation of the results of operations for the periods presented, which adjustments were of a normal recurring nature, except as disclosed herein. The condensed results of operations for the three months ended March 31, 2026 are not necessarily indicative of the results to be expected for the full year ending December 31, 2026, for various reasons, including the impact of fluctuations in prices received for oil and natural gas, natural production declines, the uncertainty of exploration and development drilling results, fluctuations in the fair value of derivative instruments, and other factors.
These unaudited condensed financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) applicable to interim financial information, and, accordingly, do not include all of the information and notes required by GAAP for complete financial statements. Therefore, these condensed financial statements should be read in conjunction with the financial statements and notes included in the Company’s annual report on Form 10-K for the year ended December 31, 2025.
Organization and Nature of Operations – Ring Energy is a growth oriented independent oil and natural gas exploration and production company based in The Woodlands, Texas engaged in oil and natural gas development, production, acquisition, and exploration activities currently focused in the Permian Basin of Texas. Our drilling operations target the oil and liquids rich producing formations in the Northwest Shelf and the Central Basin Platform, in the Permian Basin in Texas.
Correction of an Immaterial Error – In connection with the preparation of our condensed financial statements for the three months ended March 31, 2026, we identified an immaterial error that existed in our previously issued financial statements. We determined that certain revenues held in suspense deriving from operations during the annual and interim periods for fiscal years 2017 through 2025 were done so in error, and as such the Company made corrections to the prior period financial statements resulting in a decrease to Accounts payable of $7.3 million as of December 31, 2025, an increase to Retained earnings (Accumulated deficit) of $5.7 1.5 million as of December 31, 2025. This error is a result of the incorrect initial assignment of ownership interests for other interest owners without consideration of recovery of capital and normal operating costs by Ring. We evaluated the materiality of this error and quantified the effect of prior period misstatements on financial statements and have determined that the impact of this error on our prior period financial statements is immaterial. We have revised the prior period amounts to correct this immaterial error.
Liquidity and Capital Considerations – The Company strives to maintain an adequate liquidity level to address volatility and risk. Sources of liquidity include the Company’s net cash provided by operating activities, cash on hand, available borrowing capacity under its revolving credit facility, and proceeds from sales of non-strategic assets.
While changes in oil and natural gas prices affect the Company’s liquidity, the Company has put in place hedges in seeking to protect a substantial portion of its cash flows from price declines; however, if oil or natural gas prices rapidly deteriorate due to unanticipated economic conditions, this could still have a material adverse effect on the Company’s cash flows.
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The Company expects ongoing oil price volatility over an indeterminate term. Extended depressed oil prices have historically had and could have a material adverse impact on the Company’s oil revenue, which is mitigated to some extent by the Company’s hedge contracts.
The Company believes that it has the ability to continue to fund its operations and service its debt by using cash flows from operations.
Use of Estimates – The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities, and the reported amounts of revenues and expenses during the reporting period. The Company’s unaudited condensed financial statements are based on a number of significant estimates, including estimates of oil and natural gas reserve quantities, which are the basis for the calculation of depletion and impairment of oil and gas properties. Reserve estimates, by their nature, are inherently imprecise. Actual results could differ from those estimates. Changes in the future estimated oil and natural gas reserves or the estimated future cash flows attributable to the reserves that are utilized for impairment analysis could have a significant impact on the Company’s future results of operations.
Fair Value Measurements – Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Financial Accounting Standards Board (“FASB”) has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 are unobservable inputs for an asset or liability.
Fair Values of Financial Instruments – The carrying amounts reported for our revolving line of credit approximate their fair value because the underlying instruments are at interest rates which approximate current market rates. The carrying amounts of accounts receivable and accounts payable and other current assets and liabilities approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities.
Fair Value of Non-financial Assets and Liabilities – The Company also applies fair value accounting guidance to initially, or as events dictate, measure non-financial assets and liabilities such as those obtained through business acquisitions, property and equipment, and asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two as considered appropriate based on the circumstances. Under the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and natural gas production or other applicable sales estimates, operational costs, and a risk-adjusted discount rate. The Company may use the present value of estimated future cash inflows and/or outflows or third-party offers or prices of comparable assets with consideration of current market conditions to value its non-financial assets and liabilities when circumstances dictate determining fair value is necessary. Given the significance of the unobservable nature of a number of the inputs, these are considered Level 3 on the fair value hierarchy.
Concentration of Credit Risk and Receivables – Financial instruments that potentially subject the Company to a concentration of credit risk consist principally of cash and receivables.
Cash and cash equivalents – The Company had cash in excess of federally insured limits of $790,636 and $652,913 as of March 31, 2026 and December 31, 2025, respectively. The Company places its cash with a high credit quality financial institution. The Company has not experienced any losses in such accounts and believes it is not exposed to significant credit risk in this area.
Accounts receivable – Substantially all of the Company’s accounts receivable is from purchasers of oil and natural gas. Oil and natural gas sales are generally unsecured. Accounts receivable from purchasers outstanding longer than the contractual payment terms are considered past due. The Company has not had any significant credit losses in the past and believes its accounts receivable are fully collectable. During the three months ended March 31, 2026, sales to three purchasers represented 69 %, 14 % and 12 %, respectively, of total oil, natural gas, and natural gas liquids sales. As of March 31, 2026, receivables outstanding from these three purchasers represented 68 %, 14 % and 9 %, respectively, of accounts receivable.
The following table reflects the Company's beginning and ending balances of its accounts receivables from purchasers of its oil and gas for the three months ended March 31, 2026 and March 31, 2025.
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For the Three Months Ended | |||||||||||
| March 31, 2026 | March 31, 2025 | ||||||||||
| Beginning balance of accounts receivable from purchasers of oil and gas | $ | $ | |||||||||
| Ending balance of accounts receivable from purchasers of oil and gas | |||||||||||
For the Three Months Ended | |||||||||||||||||||||||
| March 31, 2026 | March 31, 2025 | ||||||||||||||||||||||
| Credit loss expense | $ | $ | |||||||||||||||||||||
The following table reflects the Company's joint interest billing receivables and allowance for credit losses as of March 31, 2026 and December 31, 2025.
| March 31, 2026 | December 31, 2025 | ||||||||||
| Joint interest billing receivables | $ | $ | |||||||||
| Allowance for credit losses | ( | ( | |||||||||
| Joint interest billing receivables, net | $ | $ | |||||||||
For receivables, the Company's estimated credit loss allowance is estimated using historical loss information, current industry conditions and payment practices, as well as reasonable and supportable forecasts of future economic conditions. Credit risk is assessed based on days outstanding and other available information. The Company has elected the practical expedient to assume that the current conditions as of the balance sheet date do not change for the remaining life of the receivables.
Production imbalances – The Company accounts for natural gas production imbalances using the sales method, which recognizes revenue on all natural gas sold even though the natural gas volumes sold may be more or less than the Company's ownership entitles it to sell. Liabilities are recorded for imbalances greater than the Company’s proportionate share of remaining estimated natural gas reserves. The Company recorded no imbalances as of March 31, 2026 or December 31, 2025.
Cash and Cash Equivalents – The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. At March 31, 2026 and December 31, 2025, the Company had no such investments.
Inventory – The full balance of the Company's inventory consists of materials and supplies for its operations, with no work in process or finished goods inventory balances. Inventory is added to the books upon the purchase of supplies (inclusive of freight and sales tax costs) to use on well sites, and inventory is reduced by material transfers for inventory usage based on the initial invoiced value. The Company reports the balance of its inventory at the lower of cost or net realizable value. Inventory balances are excluded from the Company's calculation of depletion.
Oil and Natural Gas Properties – The Company uses the full cost method of accounting for oil and natural gas properties. Under this method, all costs (direct and indirect) associated with acquisition, exploration, and development of oil and natural gas properties are capitalized. Costs capitalized include acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties and costs of drilling and equipping productive and non-productive wells. Drilling costs include directly related overhead costs. Capitalized costs are categorized either as being subject to amortization or not subject to amortization. All of the Company’s capitalized costs, excluding inventory, are subject to amortization.
The Company records a liability in the period in which an asset retirement obligation (“ARO”) is incurred, in an amount equal to the discounted estimated fair value of the obligation that is capitalized. Thereafter this liability is accreted up to the final retirement cost. An ARO is a future expenditure related to the disposal or other retirement of certain assets. The
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Company’s ARO relates to future plugging and abandonment expenses of its oil and natural gas properties and related facilities disposal. Dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs.
All capitalized costs of oil and natural gas properties, including the estimated future costs to develop proved reserves and estimated future costs to plug and abandon wells and costs of site restoration, less the estimated salvage value of equipment associated with the oil and natural gas properties, are amortized on the unit-of-production method using estimates of proved reserves as determined by independent petroleum engineers. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is offset to the capitalized costs to be amortized. The following table shows total depletion and the depletion per barrel-of-oil-equivalent rate, for the three months ended March 31, 2026 and 2025.
For the Three Months Ended | |||||||||||||||||||||||
| March 31, 2026 | March 31, 2025 | ||||||||||||||||||||||
| Depletion | $ | $ | |||||||||||||||||||||
| Depletion rate, per barrel-of-oil-equivalent (Boe) | $ | $ | |||||||||||||||||||||
In addition, capitalized costs less accumulated depletion and related deferred income taxes are not allowed to exceed an amount (the full cost ceiling) equal to the sum of:
1)the present value of estimated future net revenues discounted at ten percent computed in compliance with SEC guidelines;
2)plus the cost of properties not being amortized;
3)plus the lower of cost or estimated fair value of unproven properties included in the costs being amortized;
4)less income tax effects related to differences between the book and tax basis of the properties.
Land, Buildings and Structures, Equipment, Software, Leasehold Improvements, Automobiles, and UAV – Land, buildings and structures, equipment, software, leasehold improvements, automobiles, and unmanned aerial vehicles ("UAV") are carried at historical cost, adjusted for impairment loss and accumulated depreciation (except for land). Historical costs include all direct costs associated with the acquisition of land, buildings and structures, equipment, software, leasehold improvements, automobiles, and UAV and placing them in service. Upon sale or abandonment, the cost of the fixed asset(s) and related accumulated depreciation are removed from the accounts and any gain or loss is recognized.
Depreciation of buildings and structures, equipment, software, leasehold improvements, automobiles, and UAV is calculated using the straight-line method based upon the following estimated useful lives:
| Leasehold improvements | ||||||||
| Office equipment and software | ||||||||
| Equipment | ||||||||
| Automobiles | ||||||||
| Buildings and structures | ||||||||
| UAV | ||||||||
The following table provides information on the Company's depreciation expense for the three months ended March 31, 2026 and 2025.
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For the Three Months Ended | |||||||||||||||||||||||
| March 31, 2026 | March 31, 2025 | ||||||||||||||||||||||
| Depreciation | $ | $ | |||||||||||||||||||||
During the three months ended March 31, 2026 and 2025, the Company recorded a gain (loss) on disposal of assets, which was impacted by the sale of owned vehicles, as follows:
For the Three Months Ended | |||||||||||||||||||||||
| March 31, 2026 | March 31, 2025 | ||||||||||||||||||||||
| Sale of owned vehicles | $ | $ | ( | ||||||||||||||||||||
| Sale of leased vehicles | |||||||||||||||||||||||
| Gain (loss) on disposal of assets | $ | $ | |||||||||||||||||||||
Notes Payable – In May 2025, the Company renewed its control of well, general liability, pollution, umbrella, property, workers' compensation, auto, and D&O insurance policies, funding the premiums with a promissory note with a face value after down payments of $1,648,539 . The APR for this note was 7.75 %.
As of March 31, 2026 and December 31, 2025, the notes payable balances included in current liabilities on the Condensed Balance Sheets were $0 and $505,752 , respectively.
The following table reflects the weighted average notes payable balances and the weighted average interest rate on the weighted average notes payable outstanding during the period as of and for the three months ended March 31, 2026 and 2025.
| Three Months Ended | ||||||||||||||||||||||||||
| March 31, 2026 | March 31, 2025 | |||||||||||||||||||||||||
Weighted average notes payable balance | $ | $ | ||||||||||||||||||||||||
| Weighted average interest rate on weighted average notes payable | % | % | ||||||||||||||||||||||||
The following table shows interest paid related to notes payable for the three months ended March 31, 2026 and 2025. This interest is included within "Interest (expense)" in the Condensed Statements of Operations.
Three Months Ended | ||||||||||||||||||||||||||
| March 31, 2026 | March 31, 2025 | |||||||||||||||||||||||||
| Interest paid for notes payable | $ | $ | ||||||||||||||||||||||||
Revenue Recognition – The Company predominantly derives its revenue from the sale of produced crude oil and natural gas. The contractual performance obligation is satisfied when the product is delivered to the purchaser. Revenue is recorded in the month the product is delivered to the purchaser. The Company receives payment from one to three months after delivery. The transaction price includes variable consideration as product pricing is based on published market prices and reduced for contract specified differentials (quality, transportation and other variables from benchmark prices). The guidance regarding ASU 2014-09 does not require that the transaction price be fixed or stated in the contract. Estimating the variable consideration does not require significant judgment and the Company engages third party sources to validate the estimates. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration the Company expects to receive in exchange for those products. See "NOTE 2 — REVENUE RECOGNITION" for additional information.
Income Taxes – Provisions for income taxes are based on taxes payable or refundable for the current year and deferred taxes. Deferred income taxes are provided on differences between the tax basis of assets and liabilities and their carrying amounts in the condensed financial statements, and tax carryforwards. Deferred tax assets and liabilities are included in the condensed financial statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the provision for income taxes.
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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 certain property acquired after January 19, 2025. Further, the OBBBA basis for Section 163(j) of the Internal Revenue Code of 1986, as amended (the "Code"), net interest expense deduction is based on EBITDA (earnings before interest, taxes, depreciation and amortization) rather than EBIT (earnings before interest and taxes) for taxable years beginning after December 31, 2024, and any disallowed interest expense can be carried forward indefinitely. We have incorporated these changes into our income tax provision for the three and nine months ended September 30, 2025.
The Company recorded the following federal and state income tax benefits (provisions) for the three months ended March 31, 2026 and 2025.
For the Three Months Ended | |||||||||||||||||||||||
| March 31, 2026 | March 31, 2025 | ||||||||||||||||||||||
| Deferred federal income tax benefit (provision) | $ | $ | ( | ||||||||||||||||||||
| Current state income tax provision | ( | ( | |||||||||||||||||||||
| Deferred state income tax benefit (provision) | ( | ||||||||||||||||||||||
| Benefit from (Provision for) Income Taxes | $ | $ | ( | ||||||||||||||||||||
Effective tax rate (1) | |||||||||||||||||||||||
(1) The Company’s overall effective tax rate is calculated as Benefit from (Provision for) Income Taxes divided by Income (Loss) Before Benefit from (Provision for) Income Taxes. The effective tax rate for the three months ended March 31, 2026 was lower than the federal statutory corporate tax rate, primarily impacted by the recording of a valuation allowance on its federal net deferred tax assets. A tax expense of $25
Accounting for Uncertainty in Income Taxes – In accordance with GAAP, the Company has analyzed its filing positions in all jurisdictions where it is required to file income tax returns for the open tax years. The Company has identified its federal income tax return and its franchise tax return in Texas in which it operates as a “major” tax jurisdiction. The Company’s federal income tax returns for the years ended December 31, 2022 and after remain subject to examination. The Company’s federal income tax returns for the years ended December 31, 2007 and after remain subject to examination to the extent of the net operating loss (NOL) carryforwards. The Company’s franchise tax returns in Texas remain subject to examination for 2021 and after. The Company currently believes that all significant filing positions are highly certain and that all of its significant income tax filing positions and deductions would be sustained upon audit. Therefore, the Company has no significant reserves for uncertain tax positions and no adjustments to such reserves were required by GAAP. No interest or penalties have been levied against the Company and none are anticipated; therefore, no interest or penalty has been included in our provision for income taxes in the Condensed Statements of Operations.
Leases – Upon adoption of ASU 2016-02, the Company made accounting policy elections to not capitalize leases with a lease term of twelve months or less (i.e. short-term leases) and to not separate lease and non-lease components for all asset classes. The Company also elected to adopt the package of practical expedients that allows an entity to not reassess prior to the effective date (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases, or (iii) initial direct costs for any existing leases, and the practical expedient regarding land
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easements that exist prior to adoption. The Company did not elect the practical expedient of hindsight when determining the lease term of existing contracts at the effective date.
Earnings (Loss) Per Share – Basic earnings (loss) per share is computed by dividing net income (loss) by the weighted-average number of common shares outstanding during the applicable period. Diluted earnings per share is calculated to give effect to potentially issuable dilutive common shares.
Share-Based Compensation to Non-Employees – The Company accounts for share-based compensation issued to non-employees as either the fair value of the consideration received or the fair value of the equity instruments issued, whichever is more reliably measurable. The measurement date for these issuances is the earlier of (i) the date at which a commitment for performance by the recipient to earn the equity instruments is reached or (ii) the date at which the recipient’s performance is complete.
Share-Based Compensation – The following table summarizes the Company's share-based compensation, included with General and administrative expense within our Condensed Statements of Operations, incurred for the three months ended March 31, 2026 and 2025.
Three Months Ended | |||||||||||||||||||||||
| March 31, 2026 | March 31, 2025 | ||||||||||||||||||||||
| Share-based compensation | $ | $ | |||||||||||||||||||||
Derivative Instruments and Hedging Activities – The Company periodically enters into derivative contracts to manage its exposure to commodity price risk. These derivative contracts, which are generally placed with major financial institutions, may take the form of forward contracts, futures contracts, swaps or options. The oil and gas reference prices upon which the commodity derivative contracts are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company for its oil and natural gas production.
As the Company has not designated its derivative instruments as hedges for accounting purposes, any gains or losses resulting from changes in fair value of outstanding derivative financial instruments and from the settlement of derivative financial instruments are recognized in earnings and included as a component of Other Income (Expense) in the Condensed Statements of Operations.
When applicable, the Company records all derivative instruments, other than those that meet the normal purchases and sales exception, on the balance sheet as either an asset or liability measured at fair value. Changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. Refer to "NOTE 6 — DERIVATIVE FINANCIAL INSTRUMENTS" for additional information.
The Company uses the indirect method of reporting operating cash flows within the Condensed Statements of Cash Flows. Accordingly, the non-cash, unrealized gains and losses from derivative contracts are reflected as an adjustment to arrive at net cash provided by operating activities. The total gain (loss) on derivative contracts less the cash received (paid) for derivative settlements, net represents the unrealized (mark to market) gain or loss on derivative contracts.
Recently Adopted Accounting Pronouncements – In July 2023, the FASB issued ASU 2023-03, Presentation of Financial Statements (Topic 205), Income Statement - Reporting Comprehensive Income (Topic 220), Distinguishing Liabilities from Equity (Topic 480), Equity (Topic 505), and Compensation - Stock Compensation (Topic 718): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 120, SEC Staff Announcement at the March 24, 2022 EITF Meeting, and Staff Accounting Bulletin Topic 6.B, Accounting Series Release 280 - General Revision of Regulation S-X: Income or Loss Applicable to Common Stock. The ASU provided updated views from the SEC Staff on employee and non-employee share-based payment accounting, including guidance related to spring-loaded awards. As the ASU did not
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provide any new ASC guidance, and there was no transition or effective date provided, the Company adopted this standard upon issuance, and the adoption did not have a material impact on the Company's condensed financial statements.
In July 2025, the FASB issued ASU 2025-05, "Financial Instruments - Credit Losses (Topic 326) - Measurement of Credit Losses for Accounts Receivable and Contract Assets," that provides for a practical expedient for estimating expected credit losses which assumes that current conditions as of the balance sheet date do not change for the remaining life of the asset. The amendments are effective prospectively for annual reporting periods beginning after December 15, 2025, and interim periods within those annual reporting periods. The Company adopted ASU 2025-05 effective January 1, 2026, electing the practical expedient for its accounts receivable to assume that the current conditions as of the balance sheet date do not change for the remaining life of the asset.
Recent Accounting Pronouncements – In October 2023, the FASB issued ASU 2023-06, "Disclosure Improvements: Codification Amendments in Response to the SEC's Disclosure Update and Simplification Initiative." This update modifies the disclosure or presentation requirements of a variety of Topics in the Codification, which should be applied prospectively. For instance, within ASC 230-10 Statement of Cash Flows – Overall, the amendment requires an accounting policy disclosure in annual periods of where cash flows associated with their derivative instruments and their related gains and losses are presented in the statement of cash flows. Additionally, within ASC 260-10 Earnings Per Share – Overall, the amendment requires disclosure of the methods used in the diluted earnings-per-share computation for each dilutive security and clarifies that certain disclosures should be made during interim periods. The Company is currently assessing the impact of this update on its financial statements and related notes. If by June 30, 2027, the SEC has not removed the applicable requirement from Regulation S-X or Regulation S-K, the pending content of the related amendment will be removed from the Codification and will not become effective for any entity.
In November 2024, the FASB issued ASU 2024-03, "Income Statement – Reporting Comprehensive Income – Expenses Disaggregation Disclosures (Subtopic 220-40) – Disaggregation of Income Statement Expenses" ("ASU 2024-03"). The purpose of this update is to improve the disclosures about a public business entity's expenses and address requests from investors for more detailed information about the types of expenses (including purchases of inventory, employee compensation, depreciation, amortization, and depletion) in commonly presented expense captions (such as cost of sales, SG&A, and research and development). As clarified in ASU 2025-01, "Income Statement – Reporting Comprehensive Income – Expenses Disaggregation Disclosures (Subtopic 220-40) – Clarifying the Effective Date," the amendments in this update are effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods within annual reporting periods beginning after December 15, 2027, with early adoption permitted, and either prospective or retrospective application permitted. The Company is currently assessing the impact of adopting this new guidance on its financial disclosures.
In December 2025, the FASB issued ASU 2025-11, "Interim Reporting (Topic 270) - Narrow-Scope Improvements," 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.
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NOTE 2 — REVENUE RECOGNITION
The Company predominantly derives its revenue from the sale of produced crude oil, natural gas, and natural gas liquids ("NGLs"). The contractual performance obligation is satisfied when the product is delivered to the purchaser. Revenue is recorded in the month the product is delivered to the purchaser. The Company receives payment from one to three months after delivery. The Company has utilized the practical expedient in ASC 606-10-50-14A, which states an entity is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company’s sales contracts, each unit of production delivered to a purchaser represents a separate performance obligation, therefore, future volumes to be delivered are wholly unsatisfied and disclosure of transaction price allocated to remaining performance obligation is not required. The transaction price includes variable consideration, as product pricing is based on published market prices and adjusted for contract specified differentials such as quality, energy content, and transportation. The guidance does not require that the transaction price be fixed or stated in the contract. Estimating the variable consideration does not require significant judgment and the Company engages third party sources to validate the estimates. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration the Company expects to receive in exchange for those products. Once consideration is received from the purchaser, the Company records any variances between the estimates and actual amounts, which has historically not been significant.
Oil sales – Under the Company’s oil sales contracts, the Company sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue at the net price received when control transfers to the purchaser at the point of delivery and it is probable the Company will collect the consideration it is entitled to receive.
Natural gas and NGL sales – Under the majority of the Company’s natural gas sales processing contracts, the Company delivers unprocessed natural gas to midstream processing entities at the wellhead, and the midstream processing entities obtain control of the natural gas and NGLs at the wellhead. The midstream processing entities gather and process the natural gas and NGLs and remit proceeds to the Company for the resulting sale of natural gas and NGLs. Under these processing agreements, the Company recognizes revenue when control transfers to the purchasers at the point of delivery and it is probable the Company will collect the consideration it is entitled to receive. As such, the Company accounts for any fees and deductions as a reduction of the transaction price.
The Company has only one immaterial agreement with a natural gas processing entity in place where the point of control does not pass at the wellhead. Under this agreement, the point of control of the gas dictates that the associated fees are recorded as an expense.
Disaggregation of revenue – The following table presents revenues disaggregated by product for the three months ended March 31, 2026 and 2025.
For the Three Months Ended | |||||||||||||||||||||||
| March 31, 2026 | March 31, 2025 | ||||||||||||||||||||||
| Oil, Natural Gas, and Natural Gas Liquids Revenues | |||||||||||||||||||||||
| Oil | $ | $ | |||||||||||||||||||||
Natural gas (1) | ( | ( | |||||||||||||||||||||
| Natural gas liquids | |||||||||||||||||||||||
| Total oil, natural gas, and natural gas liquids revenues | $ | $ | |||||||||||||||||||||
(1) In the three months ended March 31, 2026 and 2025, the Company experienced a net negative total gas revenue, due to a lower gross realized sales prices per Mcf compared with the plant fees per Mcf.
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NOTE 3 — LEASES
The Company has operating leases for its offices in Midland, Texas and The Woodlands, Texas. The Midland office is currently under a five-year lease, effective October 1, 2022. The Woodlands office is currently under a 71-month (five years and 11-month) lease, effective May 9, 2023. The future payments for these office spaces are reflected in the future lease payments schedule below.
The Company has month to month leases for office equipment and compressors used in its operations on which the Company has elected to apply ASU 2016-02 (i.e. to not capitalize). The office equipment and compressors are not subject to ASU 2016-02 based on the agreement and nature of use. These leases are for terms that are less than 12 months and the Company does not intend to continue to lease this equipment for more than 12 months. The lease costs associated with these leases are reflected in the short-term lease costs within Lease operating expenses, shown below.
The Company has financing leases for vehicles. These leases have an initial term of 36 months at the end of which the Company owns the vehicles. These vehicles are generally sold at the end of their term, and the proceeds are settled in cash or applied to a new vehicle.
Future lease payments associated with these operating and financing leases as of March 31, 2026 are as follows:
| 2026 | 2027 | 2028 | 2029 | 2030 | Other Future Years | Total | |||||||||||||||||||||||||||||||||||
| Operating lease payments | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||
| Financing lease payments | |||||||||||||||||||||||||||||||||||||||||
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 | |||||||||||
| March 31, 2026 | December 31, 2025 | ||||||||||
Operating leases | |||||||||||
Weighted average remaining lease term (in years) | |||||||||||
Weighted average discount rate | |||||||||||
Finance leases | |||||||||||
Weighted average remaining lease term (in years) | |||||||||||
Weighted average discount rate | |||||||||||
The following table represents a reconciliation between the undiscounted future cash flows in the table above and the operating and financing lease liabilities disclosed in the Condensed Balance Sheets:
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| As of | |||||||||||
| March 31, 2026 | December 31, 2025 | ||||||||||
| Operating lease liability, current portion | $ | $ | |||||||||
| Operating lease liability, non-current portion | |||||||||||
| Operating lease liability, total | $ | $ | |||||||||
| Total undiscounted future cash flows (sum of future operating lease payments) | |||||||||||
| Imputed interest | |||||||||||
| Undiscounted future cash flows less imputed interest | $ | $ | |||||||||
| Financing lease liability, current portion | $ | $ | |||||||||
| Financing lease liability, non-current portion | |||||||||||
| Financing lease liability, total | $ | $ | |||||||||
| Total undiscounted future cash flows (sum of future financing lease payments) | |||||||||||
| Imputed interest | |||||||||||
| Undiscounted future cash flows less imputed interest | $ | $ | |||||||||
The following table provides supplemental information regarding lease costs in the Condensed Statements of Operations:
For the Three Months Ended | |||||||||||||||||||||||
| March 31, 2026 | March 31, 2025 | ||||||||||||||||||||||
| Operating lease costs | $ | $ | |||||||||||||||||||||
Short-term lease costs (1) | |||||||||||||||||||||||
| Financing lease costs: | |||||||||||||||||||||||
Amortization of financing lease assets (2) | |||||||||||||||||||||||
Interest on financing lease liabilities (3) | |||||||||||||||||||||||
(1)Amount included in Lease operating expenses
(2)Amount included in Depreciation, depletion and amortization
(3)Amount included in Interest (expense)
During the three months ended March 31, 2026 and 2025, the Company recorded a gain (loss) on disposal of assets, which was impacted by the sale of leased vehicles, as follows:
| For the Three Months Ended | |||||||||||||||||||||||
| March 31, 2026 | March 31, 2025 | ||||||||||||||||||||||
| Sale of owned vehicles | $ | $ | ( | ||||||||||||||||||||
| Sale of leased vehicles | |||||||||||||||||||||||
| Gain (loss) on disposal of assets | $ | $ | |||||||||||||||||||||
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NOTE 4 — EARNINGS (LOSS) PER SHARE INFORMATION
The following table presents the calculation of the Company's basic and diluted earnings (loss) per share for the three months ended March 31, 2026 and 2025. For all dilutive securities, the treasury stock method of calculating the incremental shares was applied.
For the Three Months Ended | ||||||||||||||||||||||||||
| March 31, 2026 | March 31, 2025 | |||||||||||||||||||||||||
| Net Income (Loss) | $ | ( | $ | |||||||||||||||||||||||
| Basic Weighted-Average Shares Outstanding | ||||||||||||||||||||||||||
| Effect of dilutive securities: | ||||||||||||||||||||||||||
| Stock options | ||||||||||||||||||||||||||
| Restricted stock units | ||||||||||||||||||||||||||
| Performance stock units | ||||||||||||||||||||||||||
| Common warrants | ||||||||||||||||||||||||||
| Diluted Weighted-Average Shares Outstanding | ||||||||||||||||||||||||||
| Basic Earnings (Loss) per Share | $ | ( | $ | |||||||||||||||||||||||
| Diluted Earnings (Loss) per Share | $ | ( | $ | |||||||||||||||||||||||
The following table presents the securities which were excluded from the Company's computation of diluted earnings (loss) per share for the three months ended March 31, 2026 and 2025, as their effect would have been anti-dilutive.
For the Three Months Ended | ||||||||||||||||||||||||||
| March 31, 2026 | March 31, 2025 | |||||||||||||||||||||||||
| Anti-dilutive securities: | ||||||||||||||||||||||||||
| Stock options to purchase common stock | ||||||||||||||||||||||||||
| Unvested restricted stock units | ||||||||||||||||||||||||||
| Unvested performance stock units | ||||||||||||||||||||||||||
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NOTE 5 — ACQUISITIONS AND DIVESTITURES
Lime Rock Acquisition
On February 25, 2025, the Company, as buyer, and Lime Rock Resources IV-A, L.P. (“LRRA”) and Lime Rock Resources IV-C, L.P. ("LRRC" and with LRRA, "Lime Rock"), as seller, entered into a purchase and sale agreement (the “Purchase Agreement”), which provided that the Company would acquire (the “Lime Rock Acquisition”) interests in oil and gas leases and related property of Lime Rock located in the Central Basin Platform of the Texas Permian Basin in Andrews County, Texas the "Lime Rock Assets"). On March 31, 2025, the Company and Lime Rock consummated the transactions contemplated in the Lime Rock Acquisition whereby the Company acquired the Lime Rock Assets for aggregate consideration consisting of: (i) approximately $69.3 million in cash, net of customary purchase price adjustments, paid at the closing of the Lime Rock Acquisition, (ii) $10.0 million paid on December 31, 2025, and (iii) 6,452,879 shares of common stock.
The Lime Rock Acquisition was accounted for as an asset acquisition in accordance with ASC 805. The fair value of the consideration paid by Ring and allocation to the underlying assets acquired, on a relative fair value basis, was recorded as of the date of the closing of the Lime Rock Acquisition. Additionally, costs directly related to the Lime Rock Acquisition were capitalized as a component of the purchase price. Determining the fair value of the assets and liabilities acquired required judgment and certain assumptions to be made, the most significant of these being related to the valuation of Lime Rock's oil and gas properties. The inputs and assumptions related to the oil and gas properties were categorized as level 3 in the fair value hierarchy.
The following table represents the final allocation of the total cost of the Lime Rock Acquisition to the assets acquired and liabilities assumed as of the closing date of the Lime Rock Acquisition:
| Consideration: | ||||||||
| Common stock consideration | ||||||||
| Shares of common stock issued | ||||||||
| Common stock price as of March 31, 2025 | $ | |||||||
| Total common stock consideration | $ | |||||||
| Cash consideration | ||||||||
Escrow deposit released at closing | $ | |||||||
| Closing amount paid to Lime Rock | ||||||||
| Fair value of deferred payment liability | ||||||||
Post-close adjustments | ||||||||
| Total cash consideration | $ | |||||||
| Direct transaction costs | ||||||||
| Total consideration | $ | |||||||
| Fair value of assets acquired: | ||||||||
| Oil and natural gas properties | $ | |||||||
| Fixed assets | ||||||||
| Joint interest billing receivable | ||||||||
| Amount attributable to assets acquired | $ | |||||||
| Fair value of liabilities assumed: | ||||||||
| Suspense liability | $ | |||||||
| Asset retirement obligations | ||||||||
Ad valorem tax liability | ||||||||
| Amount attributable to liabilities assumed | $ | |||||||
| Net assets acquired | $ | |||||||
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Non-Operated Interest Sale
On January 30, 2026, the Company completed the sale of certain non-operated interests in Yoakum County, Texas and Lea County, New Mexico. The purchase price was $4.5 million, and cash consideration received was approximately $4.3 million. The sale had an effective date of January 1, 2026.
Yoakum County Acquisition
On February 11, 2026, the Company completed the acquisition of a working interest partner's interest in existing horizontal wells in Yoakum County, Texas. The acquisition also included interest attributable to five one-mile horizontal wells drilled and completed in the Northwest Shelf in the first quarter of 2026. Cash consideration paid was approximately $2.0 million. The acquisition had an effective date of January 1, 2026.
NOTE 6 — DERIVATIVE FINANCIAL INSTRUMENTS
The Company is exposed to fluctuations in crude oil and natural gas prices on its production. It utilizes derivative strategies that consist of either a single derivative instrument or a combination of instruments to manage the variability in cash flows associated with the forecasted sale of our future domestic oil and natural gas production. While the use of derivative instruments may limit or partially reduce the downside risk of adverse commodity price movements, their use also may limit future income from favorable commodity price movements.
From time to time, the Company enters into derivative contracts to protect the Company’s cash flow from price fluctuation and maintain its capital programs. The Company has historically used costless collars, deferred premium puts, or swaps for this purpose. Oil derivative contracts are based on West Texas Intermediate ("WTI") crude oil prices and natural gas contracts are based on the Henry Hub. A “costless collar” is the combination of two options, a put option (floor) and call option (ceiling) with the options structured so that the premium paid for the put option will be offset by the premium received from selling the call option. Similar to costless collars, there is no cost to enter into the swap contracts. A deferred premium put contract has the premium established upon entering the contract, and due upon settlement of the contract.
The use of derivative transactions involves the risk that the counterparties, which generally are financial institutions, will be unable to meet the financial terms of such transactions. All of our derivative contracts are with lenders under our Credit Facility. Non-performance risk is incorporated in the discount rate by adding the quoted bank (counterparty) credit default swap (CDS) rates to the risk free rate. Although the counterparties hold the right to offset (i.e. netting) the settlement amounts with the Company, in accordance with ASC 815-10-50-4B, the Company classifies the fair value of all its derivative positions on a gross basis in the Company's Condensed Balance Sheets.
The Company’s derivative financial instruments are recorded at fair value and included as either assets or liabilities in the accompanying Condensed Balance Sheets. The Company has not designated its derivative instruments as hedges for accounting purposes, and, as a result, any gains or losses resulting from changes in fair value of outstanding derivative financial instruments and from the settlement of derivative financial instruments are recognized in earnings and included as a component of "Other Income (Expense)" under the heading "Gain (loss) on derivative contracts" in the accompanying Condensed Statements of Operations.
The following presents the impact of the Company’s contracts on its Condensed Balance Sheets for the periods indicated.
| As of | |||||||||||
| March 31, 2026 | December 31, 2025 | ||||||||||
| Commodity derivative instruments, marked to market: | |||||||||||
| Derivatives assets, current | $ | $ | |||||||||
| Derivative assets, noncurrent | $ | $ | |||||||||
| Derivative liabilities, current | $ | $ | |||||||||
| Derivative liabilities, noncurrent | $ | $ | |||||||||
The components of “Gain (loss) on derivative contracts” from the Condensed Statements of Operations are as follows for the respective periods:
For the Three Months Ended | |||||||||||||||||||||||
| March 31, 2026 | March 31, 2025 | ||||||||||||||||||||||
| Oil derivatives: | |||||||||||||||||||||||
| Realized gain (loss) on oil derivatives | $ | ( | $ | ( | |||||||||||||||||||
| Unrealized gain (loss) on oil derivatives | ( | ||||||||||||||||||||||
| Gain (loss) on oil derivatives | $ | ( | $ | ||||||||||||||||||||
| Natural gas derivatives: | |||||||||||||||||||||||
| Realized gain (loss) on natural gas derivatives | $ | $ | |||||||||||||||||||||
| Unrealized gain (loss) on natural gas derivatives | ( | ||||||||||||||||||||||
| Gain (loss) on natural gas derivatives | $ | $ | ( | ||||||||||||||||||||
| Gain (loss) on derivative contracts | $ | ( | $ | ( | |||||||||||||||||||
The components of “Cash received (paid) for derivative settlements, net” within the Condensed Statements of Cash Flows are as follows for the respective periods:
For the Three Months Ended | |||||||||||||||||||||||
| March 31, 2026 | March 31, 2025 | ||||||||||||||||||||||
| Cash flows from operating activities | |||||||||||||||||||||||
| Cash received (paid) for oil derivatives | $ | ( | $ | ( | |||||||||||||||||||
| Cash received (paid) for natural gas derivatives | |||||||||||||||||||||||
| Cash received (paid) for derivative settlements, net | $ | ( | $ | ( | |||||||||||||||||||
The following tables reflect the details of current derivative contracts as of March 31, 2026 (quantities are in barrels (Bbl) for the oil derivative contracts and in million British thermal units (MMBtu) for the natural gas derivative contracts).
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| Oil Hedges (WTI) | Q2 2026 | Q3 2026 | Q4 2026 | Q1 2027 | Q2 2027 | Q3 2027 | Q4 2027 | Q1 2028 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Swaps: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (Bbl) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Weighted average swap price | $ | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Two-way collars: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (Bbl) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Weighted average put price | $ | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Weighted average call price | $ | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Swaps: WTI NYMEX Rolls | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (BBL) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Weighted average swap price | $ | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Gas Hedges (Henry Hub) | Q2 2026 | Q3 2026 | Q4 2026 | Q1 2027 | Q2 2027 | Q3 2027 | Q4 2027 | Q1 2028 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| NYMEX Swaps: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (MMBtu) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Weighted average swap price | $ | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Two-way collars: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (MMBtu) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Weighted average put price | $ | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Weighted average call price | $ | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Gas Hedges (Henry Hub) | Q2 2028 | Q3 2028 | Q4 2028 | Q1 2029 | Q2 2029 | Q3 2029 | Q4 2029 | ||||||||||||||||||||||||||||||||||
| NYMEX Swaps: | |||||||||||||||||||||||||||||||||||||||||
| Hedged volume (MMBtu) | |||||||||||||||||||||||||||||||||||||||||
| Weighted average swap price | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||
| Gas Hedges (basis differential) | Q2 2026 | Q3 2026 | Q4 2026 | Q1 2027 | Q2 2027 | Q3 2027 | Q4 2027 | Q1 2028 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Waha basis swaps: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (MMBtu) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Weighted average spread price (1) | $ | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| El Paso Permian Basin basis swaps: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (MMBtu) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Weighted average spread price (1) | $ | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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NOTE 7 — FAIR VALUE MEASUREMENTS
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The authoritative guidance requires disclosure of the framework for measuring fair value and requires that fair value measurements be classified and disclosed in one of the following categories:
| Level 1: | Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis. | ||||
| Level 2: | Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that we value using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. | ||||
| Level 3: | Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity). | ||||
Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy. We continue to evaluate our inputs to ensure the fair value level classification is appropriate. When transfers between levels occur, it is our policy to assume that the transfer occurred at the date of the event or change in circumstances that caused the transfer.
The fair values of the Company’s derivatives are not actively quoted in the open market. The Company uses a market approach to estimate the fair values of its derivative instruments on a recurring basis, utilizing commodity futures pricing for the underlying commodities provided by a reputable third party, a Level 2 fair value measurement.
The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments if events or changes in certain circumstances indicate that adjustments may be necessary.
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The following table summarizes the valuation of our assets and liabilities that are measured at fair value on a recurring basis (further detail in "NOTE 6 — DERIVATIVE FINANCIAL INSTRUMENTS").
| Fair Value Measurement Classification | |||||||||||||||||||||||
| Quoted prices in Active Markets for Identical Assets or (Liabilities) (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Total | ||||||||||||||||||||
| As of December 31, 2025 | |||||||||||||||||||||||
| Commodity Derivatives - Assets | $ | $ | $ | $ | |||||||||||||||||||
| Commodity Derivatives - Liabilities | $ | $ | ( | $ | $ | ( | |||||||||||||||||
| Total | $ | $ | $ | $ | |||||||||||||||||||
| As of March 31, 2026 | |||||||||||||||||||||||
| Commodity Derivatives - Assets | $ | $ | $ | $ | |||||||||||||||||||
| Commodity Derivatives - Liabilities | $ | $ | ( | $ | $ | ( | |||||||||||||||||
| Total | $ | $ | ( | $ | $ | ( | |||||||||||||||||
The carrying amounts reported for the revolving line of credit approximates fair value because the underlying instruments are at interest rates which approximate current market rates. The carrying amounts of receivables and accounts payable and other current assets and liabilities approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities.
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NOTE 8 — REVOLVING LINE OF CREDIT
On June 18, 2025, the Company, as borrower, Bank of America, N.A. as the Administrative Agent and Issuing Bank, and the lenders party thereto (the "Lenders") entered into that certain Third Amended and Restated Credit Agreement (the "Credit Agreement"), with a maximum borrowing base of $1 billion secured by substantially all of the assets of the Company and a maturity date of June 2029.
The Credit Agreement has a borrowing base of $585 million, which is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time. The borrowing base is redetermined semi-annually each May and November. The borrowing base is subject to reduction in certain circumstances such as the sale or disposition of certain oil and gas properties of the Company and cancellation of certain hedging positions.
The Credit Agreement permits the Company to declare restricted payments (including dividends) for its equity owners, subject to certain limitations, including (a) (i) no default or event of default has occurred or will occur upon such payments, (ii) the pro forma Leverage Ratio (outstanding debt to adjusted earnings before interest, income tax expense, depreciation, depletion and amortization, exploration expenses, and all other non-cash charges acceptable to the Administrative Agent) does not exceed 2.00 to 1.00, (iii) the amount of such payments does not exceed Available Free Cash Flow (as defined in the Credit Agreement), and (iv) the Borrowing Base Utilization Percentage (as defined in the Credit Agreement) is not greater than 80 %; or (b) (i) no default or event of default has occurred or will occur upon such payments, (ii) the pro forma Leverage Ratio does not exceed 1.50 to 1.00, and (iii) the Borrowing Base Utilization Percentage is not greater than 75 %.
The reference rate in the Credit Agreement with respect to determination of the interest rate is the Secured Overnight Financing Rate ("SOFR"). The interest rate on each SOFR Loan will be (i) the adjusted term SOFR for the applicable interest period plus (ii) a margin between 2.75 % and 3.75 % (depending on the then-current level of borrowing base usage) 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, 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 March 31, 2026, $426 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 March 31, 2026, the Company's unused line of credit was approximately $159.0 million, which was calculated by subtracting the outstanding Credit Facility balance of $426 million and standby letters of credit of $35,000 in total ($10,000 with a federal agency and $25,000 with an insurance company for New Mexico state surety bonds) from the $585 million borrowing base.
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NOTE 9 — ASSET RETIREMENT OBLIGATION
The Company records the obligation to plug and abandon oil and gas wells at the dates properties are either acquired or the wells are drilled. The asset retirement obligation is adjusted each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the costs or timing estimates. The asset retirement obligation is incurred using an annual credit-adjusted risk-free discount rate at the applicable dates. A reconciliation for the asset retirement obligation during the three months ended March 31, 2026 is as follows:
| Balance, December 31, 2025 | $ | ||||
| Liabilities acquired | |||||
| Liabilities incurred | |||||
| Liabilities sold | ( | ||||
| Liabilities settled | ( | ||||
Revision of estimate (1) | |||||
| Accretion expense | |||||
Balance, March 31, 2026 | $ | ||||
(1) The revisions recorded during the three months ended March 31, 2026 consisted of additional acquired working interests in three gross wells.
The following table presents the Company's current and non-current asset retirement obligation balances as of the periods specified.
| March 31, 2026 | December 31, 2025 | ||||||||||
| Asset retirement obligations, current | $ | $ | |||||||||
| Asset retirement obligations, non-current | |||||||||||
| Asset retirement obligations | $ | $ | |||||||||
NOTE 10 — COMMON WARRANTS
During the year ended December 31, 2024 and through October 2025, the Company had 78,200 0.80 no common warrants were exercised.
| Common Warrants | Exercise Price | Proceeds Received | ||||||||||||||||||
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NOTE 11 — SHARE-BASED COMPENSATION
Share-based compensation expense charged against income for share-based awards during the three months ended March 31, 2026 and 2025 was as follows. These amounts are included in General and administrative expense in the Condensed Statements of Operations.
Three Months Ended | ||||||||||||||||||||||||||
| March 31, 2026 | March 31, 2025 | |||||||||||||||||||||||||
Share-based compensation expense from: | ||||||||||||||||||||||||||
Employee stock options | $ | $ | ||||||||||||||||||||||||
Restricted stock unit grants | ||||||||||||||||||||||||||
Performance stock unit awards | ||||||||||||||||||||||||||
| Total share-based compensation | $ | $ | ||||||||||||||||||||||||
In 2011, the Board of Directors (the "Board") of the Company approved and adopted a long-term incentive plan (the “2011 Plan”), which was subsequently approved and amended by the stockholders. As of March 31, 2026, there were no shares available for grant under the 2011 Plan.
In 2021, the Board and Company stockholders approved and adopted the Ring Energy, Inc. 2021 Omnibus Incentive Plan (as amended, the “2021 Plan”). The 2021 Plan provides that the Company may grant options, stock appreciation rights, restricted shares, restricted stock units, performance-based awards, other share-based awards, other cash-based awards, or any combination of the foregoing. As of March 31, 2026, there were 6,425,661 shares available for grant under the 2021 Plan.
In connection with the hiring of the Company’s Executive Vice President and Chief Financial Officer in February 2026, the Board approved inducement awards to the executive officer which are comprised of 317,460 (the “Inducement RSUs”) restricted stock units (“RSUs”) and 476,190 performance stock units (“PSUs”) (for which up to 952,380 shares may be earned) (the “Inducement PSUs”). The Inducement RSUs will vest in three equal annual installments beginning on March 5, 2027, subject to continued service through the applicable vesting date. The Inducement PSUs will have a performance period of January 1, 2026 to December 31, 2028, subject to performance goals and continued service through December 31, 2028. The Inducement PSUs will vest as to fifty percent of the Inducement PSUs by the Company’s total shareholder return in relation to its peer group and fifty percent will vest based on the Company’s annual cash return on capital employed meeting certain hurdles. These inducement awards were granted outside of the 2021 Plan; however, they have terms and conditions consistent with those set forth under the 2021 Plan and generally vest under the same respective vesting schedules as RSU and PSU awards granted under the 2021 Plan. The Inducement RSUs are included in the RSU award table below. The Inducement PSUs are expected to be formally granted in April 2026.
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Employee Stock Options
A summary of the status of the stock options as of March 31, 2026 and 2025 and changes during the respective three month periods then ended are as follows:
| Options | Weighted- Average Exercise Price | Weighted-Average Remaining Contractual Term | Aggregate Intrinsic Value | ||||||||||||||||||||
| Outstanding, December 31, 2024 | $ | ||||||||||||||||||||||
| Granted | |||||||||||||||||||||||
| Forfeited | |||||||||||||||||||||||
| Expired | |||||||||||||||||||||||
| Exercised | |||||||||||||||||||||||
| Outstanding, March 31, 2025 | $ | $ | |||||||||||||||||||||
| Exercisable, March 31, 2025 | $ | ||||||||||||||||||||||
| Outstanding, December 31, 2025 | $ | ||||||||||||||||||||||
| Granted | |||||||||||||||||||||||
| Forfeited | |||||||||||||||||||||||
| Expired | |||||||||||||||||||||||
| Exercised | |||||||||||||||||||||||
| Outstanding, March 31, 2026 | $ | $ | |||||||||||||||||||||
| Exercisable, March 31, 2026 | $ | ||||||||||||||||||||||
The intrinsic values were calculated using the closing price on March 31, 2026 of $1.53 and the closing price on March 31, 2025 of $1.15 . As of March 31, 2026, the Company had $0 of unrecognized compensation cost related to stock options.
Restricted Stock Units
A summary of the RSUs outstanding as of March 31, 2026 and 2025, respectively, and changes during the respective three month periods then ended are as follows:
| Restricted Stock Units | Weighted- Average Grant Date Fair Value | ||||||||||
| Outstanding, December 31, 2024 | $ | ||||||||||
| Granted | |||||||||||
| Forfeited or rescinded | |||||||||||
| Vested | ( | ||||||||||
| Outstanding, March 31, 2025 | $ | ||||||||||
| Outstanding, December 31, 2025 | $ | ||||||||||
| Granted | |||||||||||
| Forfeited or rescinded | ( | ||||||||||
| Vested | ( | ||||||||||
| Outstanding, March 31, 2026 | $ | ||||||||||
As of March 31, 2026, the Company had $8,421,909 of unrecognized compensation cost related to RSU grants that will be recognized over a weighted average period of 2.47 years. Grant activity for the three months ended March 31, 2026 was primarily RSU grants for the annual long-term incentive plan awards for employees.
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Performance Stock Units
A summary of the PSUs outstanding as of March 31, 2026 and 2025, respectively, along with changes during the respective three month periods then ended are as follows:
| Performance Stock Units | Weighted- Average Grant Date Fair Value | ||||||||||
| Outstanding, December 31, 2024 | $ | ||||||||||
| Granted | |||||||||||
| Forfeited or rescinded | |||||||||||
| Vested | |||||||||||
| Outstanding, March 31, 2025 | $ | ||||||||||
| Outstanding, December 31, 2025 | $ | ||||||||||
| Granted | |||||||||||
| Forfeited or rescinded | |||||||||||
| Vested | |||||||||||
| Outstanding, March 31, 2026 | $ | ||||||||||
NOTE 12 — COMMITMENTS AND CONTINGENCIES
Surety Bonds – As of March 31, 2026, the Company had $2,374,740 in total surety bonds. As of December 31, 2025, the Company had $2,275,000 in total surety bonds. A Texas Railroad Commission ("RRC") required blanket performance bond to operate 100 or more wells or more in the State of Texas in the amount of $250,000 2,000,000 25,000 99,740 covering a produced water recycling pit. Total expenses related to the surety bonds were $11,250 and $7,500 for the three months ended March 31, 2026 and 2025, respectively. The New Mexico bond is supported by a $25,000
Standby Letters of Credit – As of March 31, 2026 and December 31, 2025, the Company had total standby letters of credit outstanding of $35,000 10,000 25,000 No
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NOTE 13 — SEGMENT REPORTING
In accordance with ASU 2023-07 "Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures," the Company has performed an assessment of its reporting to comply with the new requirements for the fiscal year beginning January 1, 2024 and for interim periods beginning January 1, 2025. The Company's operations consist of the exploration, production, and sale of oil, natural gas, and NGLs, primarily within the Permian Basin of Texas, and is regulated by the RRC. The Company operates different areas within the Permian Basin, including the Northwest Shelf and Central Basin Platform.
The Company's operations and financials are managed by one cohesive group of individuals, identified as the chief operating decision maker ("CODM"), consisting of the Chairman of the Board and Chief Executive Officer; Executive Vice President and Chief Financial Officer; Executive Vice President and Chief Operations Officer; Executive Vice President and Chief Exploration Officer; Senior Vice President of Operations; and Vice President and Chief Accounting Officer. The CODM group reviews the Company's operating results, including condensed financial statements on a monthly basis for evaluating performance and determining resource allocation. The significant expense categories provided to the CODM include lease operating expenses; gathering, transportation and processing costs; ad valorem taxes; and oil and natural gas production taxes. Each of these costs are deducted from oil, natural gas, and natural gas liquids revenues by operating segment to arrive at operating segment profit, used to assess performance.
The Company assessed whether its operating segments exhibited similar economic characteristics and whether its operating segments had a similar nature of products, services, production processes, purchaser types/classes, product distribution, and regulatory environment. Each operating segment has similar products (oil, natural gas, and NGLs), similar production processes, similar types of purchasers (midstream companies, or companies with midstream components), similar methods of product delivery, and is governed by the same regulations. After a thorough analysis of each of these factors with regards to the Company's operating segments, it has been determined that it is appropriate to aggregate its operating segments into a single reportable segment, Exploration and Production, which includes all of its revenues, lease operating expenses, gathering, transportation and processing costs, ad valorem taxes, and oil and natural gas production taxes. Refer to the table below.
| For the Three Months Ended March 31, | |||||||||||||||||||||||
| 2026 | 2025 | ||||||||||||||||||||||
| Exploration and Production | |||||||||||||||||||||||
Oil, natural gas, and natural gas liquids revenues (1) | $ | $ | |||||||||||||||||||||
Lease operating expenses (2) | ( | ( | |||||||||||||||||||||
| Gathering, transportation and processing costs | ( | ( | |||||||||||||||||||||
| Ad valorem taxes | ( | ( | |||||||||||||||||||||
| Oil and natural gas production taxes | ( | ( | |||||||||||||||||||||
| Exploration and Production segment profit | $ | $ | |||||||||||||||||||||
(1) All of the Company's revenues are generated within the Permian Basin within the United States.
(2) The CODM also reviews the following cost categories within lease operating expenses. Refer to the following table.
| For the Three Months Ended March 31, | |||||||||||||||||||||||
| 2026 | 2025 | ||||||||||||||||||||||
| Lease operating expenses: | |||||||||||||||||||||||
| Workovers | $ | $ | |||||||||||||||||||||
| Other lease operating expenses | $ | $ | |||||||||||||||||||||
| Total lease operating expenses | $ | $ | |||||||||||||||||||||
The following tables include a reconciliation of the total reportable segments' measures of profit or loss to the Company's total income (loss) before income taxes. Additionally included is a reconciliation between the reportable segments' assets to the Company's total assets.
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| For the Three Months Ended March 31, 2026 | |||||||||||||||||
| Exploration and Production | Corporate | Total Company | |||||||||||||||
| Oil, Natural Gas, and Natural Gas Liquids Revenues | $ | $ | $ | ||||||||||||||
| Lease operating expenses | ( | ( | |||||||||||||||
| Gathering, transportation and processing costs | ( | ( | |||||||||||||||
| Ad valorem taxes | ( | ( | |||||||||||||||
| Oil and natural gas production taxes | ( | ( | |||||||||||||||
Depreciation, depletion and amortization (3) | ( | ( | |||||||||||||||
Ceiling test impairment (3) | ( | ( | |||||||||||||||
| Asset retirement obligation accretion | ( | ( | |||||||||||||||
| Operating lease expense | ( | ( | |||||||||||||||
| General and administrative expense | ( | ( | |||||||||||||||
| Interest income | |||||||||||||||||
| Interest (expense) | ( | ( | |||||||||||||||
| Gain (loss) on derivative contracts | ( | ( | |||||||||||||||
| Other income | |||||||||||||||||
| Income (Loss) Before Benefit from (Provision for) Income Taxes | $ | $ | ( | $ | ( | ||||||||||||
Total Assets (3) | $ | $ | $ | ||||||||||||||
| Capital expenditures | $ | $ | $ | ||||||||||||||
(3) All of the Company's assets are located within the United States. As the CODM does not view depreciation, depletion and amortization or ceiling test impairment as a significant Exploration and Production segment expense, the Company has included these amounts within the Corporate column of the reconciliation table.
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| For the Three Months Ended March 31, 2025 | |||||||||||||||||
| Exploration and Production | Corporate | Total Company | |||||||||||||||
| Oil, Natural Gas, and Natural Gas Liquids Revenues | $ | $ | $ | ||||||||||||||
| Lease operating expenses | ( | ( | |||||||||||||||
| Gathering, transportation and processing costs | ( | ( | |||||||||||||||
| Ad valorem taxes | ( | ( | |||||||||||||||
| Oil and natural gas production taxes | ( | ( | |||||||||||||||
Depreciation, depletion and amortization (3) | ( | ( | |||||||||||||||
Ceiling test impairment (3) | |||||||||||||||||
| Asset retirement obligation accretion | ( | ( | |||||||||||||||
| Operating lease expense | ( | ( | |||||||||||||||
| General and administrative expense | ( | ( | |||||||||||||||
| Interest income | |||||||||||||||||
| Interest (expense) | ( | ( | |||||||||||||||
| Gain (loss) on derivative contracts | ( | ( | |||||||||||||||
| Gain (loss) on disposal of assets | |||||||||||||||||
| Other income | |||||||||||||||||
| Income (Loss) Before Benefit from (Provision for) Income Taxes | $ | $ | ( | $ | |||||||||||||
Total Assets (3) | $ | $ | $ | ||||||||||||||
| Capital expenditures | $ | $ | $ | ||||||||||||||
(3) All of the Company's assets are located within the United States. As the CODM does not view depreciation, depletion and amortization or ceiling test impairment as a significant Exploration and Production segment expense, the Company has included these amounts within the Corporate column of the reconciliation table.
The following table discloses the purchasers from which 10% or more of revenues were derived in the periods noted.
| For the Three Months Ended March 31, | |||||||||||||||||||||||
| 2026 | 2025 | ||||||||||||||||||||||
Purchasers with 10% or more percentage of total revenue (4) | |||||||||||||||||||||||
| Phillips 66 Company | |||||||||||||||||||||||
| Concord Energy LLC | |||||||||||||||||||||||
| NGL Crude Partners | * | ||||||||||||||||||||||
| Energy Transfer Crude Marketing | * | ||||||||||||||||||||||
(4) All the Company's purchasers are within the Exploration and Production operating segment.
NOTE 14 — SUBSEQUENT EVENTS
Performance Stock Units – On April 28, 2026, the Company formally granted 3,547,617 performance stock units (“PSUs”) to the Company's officers. Refer to NOTE 11 — SHARE-BASED COMPENSATION for more details.
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Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our accompanying condensed financial statements and the notes to those condensed financial statements included elsewhere in this Quarterly Report. The following discussion includes forward-looking statements that reflect our plans, estimates and beliefs and our actual results could differ materially from those discussed in these forward-looking statements as a result of many factors, including those discussed under “Risk Factors,” “Forward Looking Statements” and elsewhere in this Quarterly Report.
Overview
Ring Energy, Inc. (the “Company,” “Ring,” “we,” “us,” “our” and similar terms) is an independent, growth-oriented oil and natural gas exploration and production company headquartered in The Woodlands, Texas and focused on the Permian Basin. Our operations are concentrated in the Northwest Shelf and Central Basin Platform, where we pursue disciplined development of oil weighted, long life production assets while maintaining a strong focus on capital efficiency, cost control, and balance sheet strength.
Business Description and Plan of Operation
The Company is focused on balancing the reduction of long-term debt with the continued development of our oil and gas properties in order to maintain or grow annual production. We intend to achieve these objectives through disciplined allocation of cash flow generated from operations and, where appropriate, through the sale of non-core assets. In addition, we continue to evaluate potential acquisitions of strategic producing assets with attractive acreage positions that we believe can generate competitive returns for our stockholders.
Our operating strategy is centered on the following priorities:
•Growing production and reserves through disciplined development. Ring seeks to develop its oil-rich resource base through a combination of conventional and horizontal drilling across the Northwest Shelf and Central Basin Platform, with an emphasis on operating within cash flow and generating competitive returns.
•Reducing long-term debt and strengthening the balance sheet. The Company intends to reduce leverage primarily through the use of excess cash flow and, where appropriate, selective non-core asset sales. The Company's field-level margins and asset quality position it to continue deleveraging over time while preserving financial flexibility.
•Employing industry-leading drilling and completion techniques. Ring’s executive team leverages technological advancements in completion design, geological evaluation, and reservoir engineering to optimize well performance and capital efficiency, contributing to a competitive cost structure and generating new organic development opportunities across the Company's asset base.
•Pursuing strategic, accretive acquisitions. The Company has a history of acquiring accretive assets with additional development potential that complement its existing property portfolio. Management intends to continue evaluating acquisition opportunities that improve balance sheet metrics, enhance inventory depth, and are accretive to stockholders. Many of these opportunities are often sourced through the executive team's longstanding operating and transactional relationships in the Permian Basin.
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2026 Developments and Operational Highlights
During the first quarter of 2026, the Company continued execution of its development program across its core operated positions. In the Northwest Shelf (Yoakum County), Ring drilled and completed five one-mile horizontal wells, each with a working interest of approximately 91%. In addition, the Company in the Central Basin Platform (Crane County), completed one previously drilled one-mile horizontal DUC well, and drilled and completed one vertical well, with a 100% working interest.
| Quarter | Area | Wells Drilled | Wells Completed | |||||||||||||||||||||||
| 1Q 2026 | Northwest Shelf (Horizontal) | 5 | 5 | |||||||||||||||||||||||
Central Basin Platform (Horizontal) (1) | — | 1 | ||||||||||||||||||||||||
| Central Basin Platform (Vertical) | 1 | 1 | ||||||||||||||||||||||||
| Total | 6 | 7 | ||||||||||||||||||||||||
(1) The horizontal well completed in the Central Basin Platform in the first quarter of 2026 is the completion of a previously drilled but uncompleted (“DUC”) well.(1) Total does not include the SWD well(s) drilled and completed in the [ ].
As a result of the Company's drilling and operational activities, total production for the three months ended March 31, 2026 increased 5%year over year to 1.74 million Boe. The increase in production was driven by contributions from the Lime Rock acquisition and new operated development, partially offset by natural production declines in legacy assets.
Operationally, the Company delivered solid field level performance during the quarter. For the three months ended March 31, 2026, Ring generated Exploration and Production segment profit of $49.7 million, despite a challenging commodity price environment, particularly for natural gas. These results reflect continued cost discipline, efficient execution of the development program, and the benefits of the Company’s oil weighted asset base.
At the Total Company level, reported results were materially impacted by certain non-cash items. The Company recorded a net loss of $220.6 million for the quarter, driven primarily by a $162.1 million full cost ceiling test impairment and $77.0 million unrealized derivative mark to market adjustments resulting from changes in forward commodity prices.
The Company's underlying operating performance and liquidity remained solid during the quarter, and the non-cash charges we incurred did not affect compliance with the financial covenants under the Company’s Credit Facility. Core operating results remain resilient, supported by disciplined capital allocation, ongoing cost improvements, and a hedge position designed to provide cash flow stability in a volatile pricing environment.
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Market Conditions and Commodity Prices
The Company’s financial results are highly sensitive to changes in commodity prices, and during the first quarter of 2026, oil and natural gas markets experienced significant volatility driven by different factors. In the Permian Basin, natural gas prices remained under severe pressure due to regional takeaway constraints and elevated processing and transportation costs, while crude oil prices were influenced by broader global events late in the quarter.
As a result of the sustained weakness in Permian natural gas markets, the Company realized negative net natural gas prices during the quarter, as processing and transportation fees exceeded gross realized sales prices, which adversely impacted reported revenues. In response, management continues to pursue commercially reasonable mitigations, including basis hedging, marketing optimization, and disciplined capital allocation, while maintaining a strong focus on preserving liquidity and long term value.
Separately, late first quarter 2026 geopolitical developments affected global crude oil markets, resulting in a sharp increase in crude oil prices. These late quarter price movements adversely impacted the fair value of the Company’s outstanding crude oil derivative positions and contributed to the unrealized derivative losses recorded during the quarter. By contrast, the SEC full cost ceiling test is based on an unweighted arithmetic average of first day of the month prices for the preceding twelve months, and accordingly, these late quarter oil price movements had limited impact on the twelve month average prices used in the Company’s March 31, 2026 ceiling test calculation.
Ceiling Test
We perform a ceiling test at the end of each reporting period to evaluate for potential non-cash impairments. Under the full cost method of accounting, the net book value of properties, less related deferred income taxes, may not exceed a calculated “ceiling,” which is defined as the estimated after-tax future net revenues from proved oil and natural gas properties, discounted at an annual rate of 10%. The discounted future net revenues are estimated using spot prices for oil and natural gas, based on the average price during the preceding twelve months. This average is calculated as an unweighted arithmetic mean of the first-day-of-the-month prices for each month within that period, except when changes are fixed and determinable by existing contracts.
Accordingly, because the ceiling test is based on historical twelve month average pricing, it does not fully reflect significant changes in commodity prices that occur late in a reporting period.
As a result of the ceiling test, driven by a decrease in the twelve month average commodity price over the past few months, the Company recognized a non-cash impairment charge of $162.1 million for the three months ended March 31, 2026. Depending on market conditions, the Company's discounted future net revenues could continue to decline, which may trigger additional non-cash impairments recognized in future periods. Estimating potential future non-cash impairments is complex due to numerous factors affecting the ceiling test calculation, including but not limited to future prices, operating costs, upward or downward reserve revisions, reserve additions, and tax attributes. The amount of any additional non-cash impairment, if any, is not estimable at this time given the uncertainty of these factors.
Natural Gas Takeaway Capacity
The Permian Basin has been experiencing a lack of sufficient pipeline transportation that is connected to markets that are purchasing the natural gas produced. This has resulted in negative natural gas prices for us in 2025 and continuing through 2026 to date, whereby we actually pay the purchaser to take our natural gas. These negative realized gas prices at times and conditions are continuing. If these depressed or inverted natural gas prices continue in the region, our natural gas revenues will continue to be negatively impacted.
Inflation
Inflation has increased costs associated with our capital program and production operations. We have experienced increases in the costs of many of the materials, supplies, equipment and services used in our operations and we expect inflation to continue based on current economic circumstances, including tariffs, trade wars, and supply chain disruptions. We continue to closely monitor costs and take all reasonable steps to mitigate the inflationary effect on our cost structure and also work to enhance our efficiency to minimize additional cost increases where possible.
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Results of Operations
Oil, Natural Gas, and Natural Gas Liquids Revenues for the Three Months Ended March 31, 2026 and 2025
| For the Three Months Ended | ||||||||||||||||||||||||||
| March 31, 2026 | March 31, 2025 | Change | % Change | |||||||||||||||||||||||
| Net sales: | ||||||||||||||||||||||||||
| Oil | $ | 76,205,014 | $ | 76,505,050 | $ | (300,036) | — | % | ||||||||||||||||||
| Natural gas | (4,296,088) | (302,727) | (3,993,361) | (1319) | % | |||||||||||||||||||||
| Natural gas liquids | 1,762,738 | 2,888,884 | (1,126,146) | (39) | % | |||||||||||||||||||||
| Total sales | $ | 73,671,664 | $ | 79,091,207 | $ | (5,419,543) | (7) | % | ||||||||||||||||||
| Net production: | ||||||||||||||||||||||||||
| Oil (Bbls) | 1,104,823 | 1,086,694 | 18,129 | 2 | % | |||||||||||||||||||||
| Natural gas (Mcf) | 1,689,512 | 1,615,196 | 74,316 | 5 | % | |||||||||||||||||||||
| Natural gas liquids (Bbls) | 355,173 | 299,366 | 55,807 | 19 | % | |||||||||||||||||||||
Total production (Boe)(1) | 1,741,581 | 1,655,259 | 86,322 | 5 | % | |||||||||||||||||||||
| Average sales price: | ||||||||||||||||||||||||||
| Oil (per Bbl) | $ | 68.97 | $ | 70.40 | $ | (1.43) | (2) | % | ||||||||||||||||||
| Natural gas (per Mcf) | (2.54) | (0.19) | (2.35) | (1237) | % | |||||||||||||||||||||
| Natural gas liquids (Bbl) | 4.96 | 9.65 | (4.69) | (49) | % | |||||||||||||||||||||
| Total per Boe | $ | 42.30 | $ | 47.78 | $ | (5.48) | (11) | % | ||||||||||||||||||
(1) Boe is calculated using six Mcf of natural gas as the equivalent of one barrel of oil.
Oil sales. Oil sales decreased approximately $0.3 million from $76.5 million to $76.2 million, with a price variance of $(1.6) million from a decrease in the average realized price per barrel from $70.40 to $68.97 offset by a volume variance of $1.3 million due to an increase in sales volume from 1,086,694 barrels to 1,104,823 barrels. The increase in volume of 18,129 barrels consisted of two components: an increase in volumes of 143,132 was due to the Lime Rock acquisition, and a decrease of 125,003 was attributed to natural production declines in the legacy assets. The Company's drilling and completion spend was 43% lower in the months that affected production for the first three months of 2026 compared to the same months that affected production in the first three months of 2025. This resulted in less offsets to declining production in the legacy assets. The decreased average realized price per barrel was primarily the result of lower oil prices.
Natural gas sales. Natural gas sales decreased approximately $4.0 million from a negative $0.3 million to a negative $4.3 million. The natural gas sales volume increased from 1,615,196 Mcf to 1,689,512 Mcf, and the average realized price per Mcf decreased from $(0.19) to $(2.54). Of the increase in volume of 74,316 Mcf, an increase of 146,522 was due to the Lime Rock acquisition, offset by a decrease of 72,206 for our legacy assets. The price decrease was driven by lower market conditions. The realized revenue pricing includes the impact of gas plant processing fees that were netted from revenue. For the three months ended March 31, 2026, gross revenues were $(0.48) per Mcf and fees were $(2.06) per Mcf, compared to gross revenues of $1.86 per Mcf and fees of $(2.05) per Mcf for the three months ended March 31, 2025. This resulted in a net realized price of $(2.54) for the three months ended March 31, 2026 compared to $(0.19) per Mcf for the three months ended March 31, 2025.
Natural gas liquids sales. NGL sales decreased approximately $1.1 million from $2.9 million to $1.8 million. NGL sales volumes for the three months ended March 31, 2026 were 355,173 barrels compared to 299,366 barrels for the comparable period in 2025. Of the increase in volume of 55,807 barrels, an increase of 40,450 was due to the Lime Rock acquisition, and an increase of 15,357 was from legacy assets. The average realized price per barrel decreased by $4.69 to $4.96 for the three months ended March 31, 2026 compared to $9.65 for the three months ended March 31, 2025, due to lower prices. Specifically, the gross realized price per NGL barrel was $17.42 and the average fees per barrel was $(12.46), resulting in a net realized price of $4.96 for the three months ended March 31, 2026, while the gross realized price per barrel was $22.64 and the average fees per barrel was $(12.99), resulting in a net realized price of $9.65 for the same period in 2025.
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Production Costs for the Three Months Ended March 31, 2026 and 2025
| For the Three Months Ended | ||||||||||||||||||||||||||
| March 31, 2026 | March 31, 2025 | Change | % Change | |||||||||||||||||||||||
| Lease operating expenses ("LOE") | $ | 18,122,344 | $ | 19,677,552 | $ | (1,555,208) | (8) | % | ||||||||||||||||||
| Average LOE per Boe | $ | 10.41 | $ | 11.89 | $ | (1.48) | (12) | % | ||||||||||||||||||
| Gathering, transportation and processing costs ("GTP") | $ | 117,049 | $ | 203,612 | $ | (86,563) | (43) | % | ||||||||||||||||||
| Average GTP per Boe | $ | 0.07 | $ | 0.12 | $ | (0.05) | (42) | % | ||||||||||||||||||
| Ad valorem taxes | $ | 2,202,537 | $ | 1,532,108 | $ | 670,429 | 44 | % | ||||||||||||||||||
| Average Ad valorem taxes per Boe | $ | 1.26 | $ | 0.93 | $ | 0.33 | 35 | % | ||||||||||||||||||
| Oil and natural gas production taxes | $ | 3,553,891 | $ | 3,584,455 | $ | (30,564) | (1) | % | ||||||||||||||||||
| Average Production taxes per Boe | $ | 2.04 | $ | 2.17 | $ | (0.13) | (6) | % | ||||||||||||||||||
| Production taxes as a percentage of total sales | 4.82 | % | 4.53 | % | 0.29 | % | 6 | % | ||||||||||||||||||
Lease operating expenses. Our total LOE decreased from $19.7 million to $18.1 million and LOE per Boe decreased from $11.89 to $10.41. Total LOE decreased despite a 5% increase in production of 86,322 Boe, as a result of the additional production and well count from the Lime Rock acquisition as well as new wells drilled and completed in our development program. The primary cost drivers for the period were decreases in contract and lease services of $1.0 million, chemicals of $0.9 million, equipment rentals of $0.5 million, location repairs and environmental sustainability of $0.3 million, non-op of $0.2 million, and contract pumping services of $0.1 million. This was offset by increases in LOE costs from salt water disposal of $0.5 million, salaries of $0.4 million, and workovers of $0.4 million.
Gathering, transportation and processing costs. Our total GTP decreased $86,563 from $203,612 to $117,049 and decreased on a per Boe basis from $0.12 to $0.07. The decrease in GTP costs was due to a reduction of $77,561 in gas processing costs and a reduction of $9,002 in NGL processing costs.
Ad valorem taxes. Our total ad valorem taxes increased $0.7 million from $1.5 million to $2.2 million and increased on a per Boe basis from $0.93 to $1.26. An increase in ad valorem taxes of $0.5 million was from the reversal made in the first quarter of 2025 for the 2024 methane tax accrual for the waste emissions charge ("WEC"), which was repealed by Congress on March 14, 2025, with no similar reversal made in 2026. There was also an increase of $0.6 million in Andrews County due primarily to the Lime Rock acquisition. Offsetting these increases was a decrease in the Yoakum County estimates of approximately $0.4 million.
Oil and natural gas production taxes. Oil and natural gas production taxes as a percentage of oil and natural gas sales were 4.53% for the three months ended March 31, 2025 and increased to 4.82% for the three months ended March 31, 2026. The overall average percentage of production taxes to oil and gas sales was consistent period over period.
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Other Costs and Operating Expenses for the Three Months Ended March 31, 2026 and 2025
| For the Three Months Ended | ||||||||||||||||||||||||||
| March 31, 2026 | March 31, 2025 | Change | % Change | |||||||||||||||||||||||
| Depreciation, depletion and amortization (DD&A): | ||||||||||||||||||||||||||
| Depletion | $ | 21,125,376 | $ | 22,254,576 | $ | (1,129,200) | (5) | % | ||||||||||||||||||
| Depreciation | 87,135 | 96,620 | (9,485) | (10) | % | |||||||||||||||||||||
| Amortization of financing lease assets | 193,437 | 264,787 | (71,350) | (27) | % | |||||||||||||||||||||
| Total depreciation, depletion and amortization | $ | 21,405,948 | $ | 22,615,983 | $ | (1,210,035) | (5) | % | ||||||||||||||||||
| Depletion per Boe | $ | 12.13 | $ | 13.44 | $ | (1.31) | (10) | % | ||||||||||||||||||
| Depreciation, depletion and amortization per Boe | $ | 12.29 | $ | 13.66 | $ | (1.37) | (10) | % | ||||||||||||||||||
| Ceiling test impairment | $ | 162,086,257 | $ | — | $ | 162,086,257 | 100 | % | ||||||||||||||||||
| Asset retirement obligation ("ARO") accretion | $ | 395,496 | $ | 326,549 | $ | 68,947 | 21 | % | ||||||||||||||||||
| Operating lease expense | $ | 175,091 | $ | 175,091 | $ | — | — | % | ||||||||||||||||||
| General and administrative expense ("G&A"): | ||||||||||||||||||||||||||
| G&A excluding share-based compensation | $ | 5,913,970 | $ | 6,929,018 | $ | (1,015,048) | (15) | % | ||||||||||||||||||
| Share-based compensation | 1,524,808 | 1,690,958 | (166,150) | (10) | % | |||||||||||||||||||||
| Total general and administrative expense | $ | 7,438,778 | $ | 8,619,976 | $ | (1,181,198) | (14) | % | ||||||||||||||||||
| G&A per Boe | $ | 4.27 | $ | 5.21 | $ | (0.94) | (18) | % | ||||||||||||||||||
| G&A excluding Share-based compensation, per Boe | $ | 3.40 | $ | 4.19 | $ | (0.79) | (19) | % | ||||||||||||||||||
Depreciation, depletion and amortization. Our depreciation, depletion and amortization decreased approximately $1.2 million from $22.6 million to $21.4 million, with substantially all of the reduction from lower depletion. The decrease in depletion was primarily due to a price variance of $(2.3) million, from a lower depletion expense per Boe, due to an increase in the amortization base. Offsetting this, depletion had a volume variance of approximately $1.2 million from a increase of 86,322 in Boe produced. Our average depreciation, depletion and amortization per Boe decreased from $13.66 per Boe to $12.29 per Boe.
Ceiling test impairment. As a result of the lower oil prices impacting the present value of estimated future net revenues, the Company incurred a ceiling test impairment on its oil and natural gas properties of $162.1 million.
Asset retirement obligation accretion. Our ARO accretion increased by $68,947 from $326,549 to $395,496 primarily as a result of newly acquired and drilled wells, offset by those plugged and abandoned and sold.
Operating lease expense. Our operating lease expense costs were the same period over period.
General and administrative expense. G&A expense decreased approximately $1.2 million from $8.6 million to $7.4 million, with the $1.2 million cost decrease primarily due to a decrease of $0.6 million in salaries and bonuses, $0.5 million in additional costs capitalized, and a decrease of $0.1 million in insurance expense.
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Other Income (Expense) for the Three Months Ended March 31, 2026 and 2025
| For the Three Months Ended | ||||||||||||||||||||||||||
| March 31, 2026 | March 31, 2025 | Change | % Change | |||||||||||||||||||||||
| Interest income | $ | 70,529 | $ | 90,058 | $ | (19,529) | (22) | % | ||||||||||||||||||
| Interest expense: | ||||||||||||||||||||||||||
| Interest on revolving line of credit | $ | 7,681,551 | $ | 7,947,642 | $ | (266,091) | (3) | % | ||||||||||||||||||
| Fees associated with revolving line of credit | 193,477 | 277,389 | (83,912) | (30) | % | |||||||||||||||||||||
| Amortization of deferred financing costs | 694,148 | 1,238,493 | (544,345) | (44) | % | |||||||||||||||||||||
| Interest on financing lease liabilities | 23,886 | 28,741 | (4,855) | (17) | % | |||||||||||||||||||||
| Interest paid for notes payable | 6,547 | 6,521 | 26 | — | % | |||||||||||||||||||||
| Total interest expense | $ | 8,599,609 | $ | 9,498,786 | $ | (899,177) | (9) | % | ||||||||||||||||||
| Gain (loss) on derivative contracts: | ||||||||||||||||||||||||||
| Realized gain (loss): | ||||||||||||||||||||||||||
| Crude oil | $ | (6,058,656) | $ | (640,267) | $ | (5,418,389) | (846) | % | ||||||||||||||||||
| Natural gas | 782,645 | 86,673 | 695,972 | 803 | % | |||||||||||||||||||||
| Total realized gain (loss) | $ | (5,276,011) | $ | (553,594) | $ | (4,722,417) | (853) | % | ||||||||||||||||||
| Unrealized gain (loss): | ||||||||||||||||||||||||||
| Crude oil | $ | (79,793,070) | $ | 2,341,425 | $ | (82,134,495) | (3508) | % | ||||||||||||||||||
| Natural gas | 2,838,156 | (2,716,621) | 5,554,777 | 204 | % | |||||||||||||||||||||
| Total unrealized gain (loss) | $ | (76,954,914) | $ | (375,196) | $ | (76,579,718) | (20411) | % | ||||||||||||||||||
| Total gain (loss) on derivative contracts: | $ | (82,230,925) | $ | (928,790) | $ | (81,302,135) | (8754) | % | ||||||||||||||||||
| Gain (loss) on disposal of assets | $ | — | $ | 124,610 | $ | (124,610) | (100) | % | ||||||||||||||||||
| Other income | $ | 5,837 | $ | 8,942 | $ | (3,105) | (35) | % | ||||||||||||||||||
Interest income. Interest income decreased $19,529 from $90,058 to $70,529, as a result of $41,747 in lower earnings on excess cash balances in bank sweep accounts, offset by an increase of $22,218 in severance tax interest receipts.
Interest expense. Interest expense decreased by approximately $0.9 million from $9.5 million to $8.6 million, primarily due to a decrease in the amortization of deferred financing costs as a result of the amendment and restatement of the credit agreement in the second quarter of 2025. Interest on the Credit Facility decreased due to lower interest rates, with a weighted average annual interest rate of 7.3% during the three months ended March 31, 2026 compared to 8.3% during the three months ended March 31, 2025. Offsetting this impact was higher amounts outstanding on our Credit Facility, with a weighted average daily debt of approximately $430.4 million during the three months ended March 31, 2026 compared to approximately $393.3 million during the three months ended March 31, 2025.
Gain (loss) on derivative contracts. We recorded a loss on derivative contracts of $82.2 million for the three months ended March 31, 2026 and a loss on derivative contracts of $0.9 million for the three months ended March 31, 2025. For the derivative contract settlements, we recorded a realized loss of $5.3 million for the three months ended March 31, 2026 compared with a realized loss of $0.6 million for the three months ended March 31, 2025. The change of $4.7 million in the realized derivative gain (loss) was primarily a result of less favorable settlements of crude oil derivative contracts during the current year. For the marked-to-market contracts, we recorded an unrealized loss of $77.0 million for the three months ended March 31, 2026 and an unrealized loss of $0.4 million for the three months ended March 31, 2025. This negative change in unrealized derivatives primarily reflects changes in the crude oil forward curve during the quarter, including a late quarter increase in forward prices, which reduced the fair value of the Company's outstanding crude oil derivative positions.
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Gain (loss) on disposal of assets. The Company's gain on disposal of assets decreased by $124,610 from $124,610 to $— with $131,584 of the decrease from the sale of leased vehicles offset by $6,974 from selling owned vehicles.
Other income. Other income decreased $3,105 from $8,942 to $5,837 due to a reduction of $3,105 in income from the Company's charge card rebate program.
Benefit from (Provision for) Income Taxes: for the Three Months Ended March 31, 2026 and 2025
| For the Three Months Ended | ||||||||||||||||||||||||||
| March 31, 2026 | March 31, 2025 | Change | % Change | |||||||||||||||||||||||
| Benefit from (Provision for) Income Taxes: | ||||||||||||||||||||||||||
| Deferred federal income tax benefit (provision) | $ | 10,702,538 | $ | (2,816,078) | $ | 13,518,616 | 480 | % | ||||||||||||||||||
| Current state income tax provision | (95,587) | (136,393) | 40,806 | 30 | % | |||||||||||||||||||||
| Deferred state income tax benefit (provision) | 1,381,462 | (88,706) | 1,470,168 | 1657 | % | |||||||||||||||||||||
| Benefit from (Provision for) Income Taxes | $ | 11,988,413 | $ | (3,041,177) | $ | 15,029,590 | 494 | % | ||||||||||||||||||
Provision for income taxes. The provision for income taxes changed from a provision of $3.0 million for the three months ended March 31, 2025 to a benefit of $12.0 million for the three months ended March 31, 2026. The provision for income taxes was calculated using the annual effective tax rate method based on our estimated earnings and estimated state and federal income taxes due for 2026, taking into account all applicable tax rates and laws.
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Liquidity and Capital Resources
As of March 31, 2026, we had cash on hand of $1.0 million, compared to $0.9 million as of December 31, 2025. We strive to keep our cash balance as low as possible to minimize our outstanding debt and associated interest. At certain times we reflect a zero book balance while utilizing the float on outstanding checks. We had net cash provided by operating activities for the three months ended March 31, 2026 of $25.9 million, compared to net cash provided by operating activities of $28.4 million for the same period in 2025, which was primarily due to lower year to date revenues, which resulted in less cash received from purchasers. We had net cash used in investing activities of $31.0 million for the three months ended March 31, 2026, compared to net cash used in investing activities of $102.6 million for the same period in 2025, driven by the payments made for the Lime Rock acquisition in 2025, with no comparable payments made to date in 2026. Payments to develop oil and natural gas properties grew slightly and the Company sold non-operated working interests in 2026, as reflected in proceeds from divestiture of oil and natural gas properties. Net cash provided by financing activities was $5.3 million for the three months ended March 31, 2026 and net cash provided by financing activities was $73.5 million for the three months ended March 31, 2025, during which time $6.0 million was the net borrowing and $75.0 million was the net borrowing of principal on our Credit Facility, respectively.
We will continue to focus on maximizing cash flow in 2026 through a combination of cost monitoring and prudent capital allocation, which will include prioritizing our capital to projects we believe will provide high rates of return in the current commodity price environment. We will continue our pursuit of acquisitions and business combinations, seeking opportunities that we believe will provide high margin properties with attractive returns at current commodity prices, ultimately pushing to reduce our debt level and maximize our liquidity.
Availability of Capital Resources under Credit Facility
As of March 31, 2026, $426 million was outstanding on our Credit Facility and we were in compliance with all of the covenants under the Credit Facility. The Credit Facility matures in June 2029. The borrowing base under our Credit Facility is $585 million. The borrowing base is redetermined semi-annually each May and November. See "NOTE 8 — REVOLVING LINE OF CREDIT" in the Notes to the condensed financial statements for more information on our Credit Facility.
Derivative Financial Instruments
The following table reflects the contracts outstanding as of March 31, 2026 (quantities are in barrels (Bbl) for the oil derivative contracts and in million British thermal units (MMBtu) for the natural gas derivative contracts):
| Oil Hedges (WTI) | Q2 2026 | Q3 2026 | Q4 2026 | Q1 2027 | Q2 2027 | Q3 2027 | Q4 2027 | Q1 2028 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Swaps: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (Bbl) | 622,601 | 263,400 | 529,000 | 509,500 | 492,000 | 432,000 | 412,963 | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Weighted average swap price | $ | 66.43 | $ | 61.77 | $ | 65.34 | $ | 62.82 | $ | 60.45 | $ | 61.80 | $ | 57.59 | $ | — | |||||||||||||||||||||||||||||||||||||||||||||||||
| Two-way collars: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (Bbl) | 273,000 | 563,685 | — | — | — | — | — | 400,080 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Weighted average put price | $ | 55.00 | $ | 60.82 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 55.45 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Weighted average call price | $ | 65.65 | $ | 76.19 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 65.45 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Swaps: WTI NYMEX Rolls | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (BBL) | 819,000 | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Weighted average swap price | $ | 5.30 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||||||||||||||||||||||||||||||||||||||||||
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| Gas Hedges (Henry Hub) | Q2 2026 | Q3 2026 | Q4 2026 | Q1 2027 | Q2 2027 | Q3 2027 | Q4 2027 | Q1 2028 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| NYMEX Swaps: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (MMBtu) | 1,165,628 | 600,016 | 1,072,305 | 439,678 | 423,035 | 1,079,906 | 1,046,151 | 1,012,567 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Weighted average swap price | $ | 3.82 | $ | 4.19 | $ | 3.99 | $ | 4.02 | $ | 4.02 | $ | 3.86 | $ | 4.02 | $ | 3.77 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Two-way collars: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (MMBtu) | 139,000 | 648,728 | 128,000 | 717,000 | 694,000 | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Weighted average put price | $ | 3.50 | $ | 3.10 | $ | 3.50 | $ | 3.99 | $ | 3.00 | $ | — | $ | — | $ | — | |||||||||||||||||||||||||||||||||||||||||||||||||
| Weighted average call price | $ | 5.42 | $ | 4.24 | $ | 5.42 | $ | 5.21 | $ | 4.32 | $ | — | $ | — | $ | — | |||||||||||||||||||||||||||||||||||||||||||||||||
| Gas Hedges (Henry Hub) | Q2 2028 | Q3 2028 | Q4 2028 | Q1 2029 | Q2 2029 | Q3 2029 | Q4 2029 | ||||||||||||||||||||||||||||||||||
| NYMEX Swaps: | |||||||||||||||||||||||||||||||||||||||||
| Hedged volume (MMBtu) | 984,322 | 956,865 | 931,539 | 908,117 | 886,933 | 866,585 | 846,134 | ||||||||||||||||||||||||||||||||||
| Weighted average swap price | $ | 3.77 | $ | 3.77 | $ | 3.77 | $ | 3.67 | $ | 3.67 | $ | 3.67 | $ | 3.67 | |||||||||||||||||||||||||||
| Gas Hedges (basis differential) | Q2 2026 | Q3 2026 | Q4 2026 | Q1 2027 | Q2 2027 | Q3 2027 | Q4 2027 | Q1 2028 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Waha basis swaps: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (MMBtu) | — | — | — | 196,372 | 480,325 | 464,360 | 449,846 | 435,403 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Weighted average spread price (1) | $ | — | $ | — | $ | — | $ | 0.78 | $ | 0.78 | $ | 0.78 | $ | 0.78 | $ | 0.68 | |||||||||||||||||||||||||||||||||||||||||||||||||
| El Paso Permian Basin basis swaps: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Hedged volume (MMBtu) | — | — | — | 960,307 | 636,710 | 615,547 | 596,306 | 577,163 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Weighted average spread price (1) | $ | — | $ | — | $ | — | $ | 0.72 | $ | 0.67 | $ | 0.67 | $ | 0.67 | $ | 0.60 | |||||||||||||||||||||||||||||||||||||||||||||||||
(1) The gas basis swap hedges are calculated as the Henry Hub natural gas price less the fixed amount specified as the weighted average spread price above.
Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the accompanying Condensed Balance Sheets. Any gains or losses resulting from changes in fair value of outstanding derivative financial instruments and from the settlement of derivative financial instruments are recognized in earnings and included as a component of Other Income (Expense) in the accompanying Condensed Statements of Operations.
The use of derivative transactions involves the risk that the counterparties, which generally are financial institutions, will be unable to meet the financial terms of such transactions. At March 31, 2026, 100% of our derivative instruments were with lenders under our Credit Facility.
Effects of Inflation and Pricing
The oil and natural gas industry is cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry puts significant pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do associated costs. Material changes in prices impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, and the value of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money, and retain personnel. We anticipate business costs will vary in accordance with commodity prices for oil and natural gas, and the associated increase or decrease in demand for services related to production and exploration.
Off-Balance Sheet Financing Arrangements
As of March 31, 2026, we had no off-balance sheet financing arrangements.
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Capital Resources for Future Acquisition and Development Opportunities
We continuously evaluate potential acquisitions and development opportunities. To the extent possible, we intend to acquire producing properties with lower-risk undeveloped drilling opportunities rather than properties with higher-risk exploratory opportunities. We do not intend to limit our evaluation to any one state, but we presently have no intention to acquire offshore properties or properties located outside of the United States.
The pursuit of and the acquisition of accretive oil and gas properties is highly competitive and may require substantially greater capital than we currently have available and obtaining additional capital may require that we obtain either short-term or long-term debt or sell our equity or both. Further, it may be necessary for us to retain outside consultants and others in our endeavors to locate desirable oil and gas properties.
The process of acquiring one or more additional oil and gas properties would impact our financial position, reduce our cash position and likely increase our debt levels. The types of costs that we may incur include the costs to retain consultants and investment bankers specializing in the purchase of oil and gas properties, obtaining petroleum engineering reports relative to the oil and gas properties that we are investigating, legal fees associated with any such acquisitions including title reports, SEC reporting expenses, and negotiating definitive agreements. Additionally, accounting fees may be incurred relative to obtaining and evaluating historical and pro forma information regarding oil and gas properties. Even though we may incur these costs, there is no assurance that we will ultimately be able to consummate additional acquisitions of oil and gas producing properties.
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Item 3: Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Market risk refers to the risk of loss from decreases in oil and natural gas prices. Realized pricing is primarily driven by the prevailing domestic price for crude oil and spot prices in the Permian Basin. Historically, prices received for oil and natural gas production have been volatile and unpredictable. We expect pricing volatility to continue.
The prices we receive depend on many factors outside of our control. A significant decrease in the prices of oil or natural gas would likely have a material adverse effect on our financial condition and results of operations. In order to reduce commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas, we enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production.
Customer Credit Risk
Our principal exposure to credit risk is through receivables from the sale of our oil and natural gas production (approximately $43.2 million as of March 31, 2026). We are subject to credit risk due to the concentration of our oil and natural gas receivables with our most significant customers, or purchasers. We do not require our purchasers to post collateral, and the inability of our significant purchasers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. Refer to the following table for detail on the top three purchasers of our oil, natural gas, and NGL revenues for the three months ended March 31, 2026. We believe that the loss of any of these purchasers would not materially impact our business as we could readily find other purchasers for our oil and natural gas.
For the Three Months Ended | As of | |||||||||||||
| March 31, 2026 | March 31, 2026 | |||||||||||||
| Percentage of Oil, Natural Gas, and Natural Gas Liquids Revenues | Percentage of accounts receivables from the sale of our oil and natural gas production | |||||||||||||
| Purchaser: | ||||||||||||||
| Phillips 66 Company | 69% | 68% | ||||||||||||
| Energy Transfer Crude Marketing | 14% | 14% | ||||||||||||
| Concord Energy LLC | 12% | 9% | ||||||||||||
Interest Rate Risk
We are subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility, which bears variable interest based upon a prime rate and is therefore susceptible to interest rate fluctuations. Changes in interest rates affect the interest earned on the Company’s cash and cash equivalents and the interest rate paid on borrowings under the Credit Facility.
As of March 31, 2026, we had $426 million outstanding on our Credit Facility with a weighted average annual interest rate for the three months ended March 31, 2026 of 7.3%. A 1% change in the interest rate on our Credit Facility would result in an estimated $4.3 million change in our annual interest expense. See "NOTE 8 — REVOLVING LINE OF CREDIT" in the Notes to the condensed financial statements for more information on the Company’s interest rates of our Credit Facility. Currently, we do not use interest rate derivative instruments to manage exposure to interest rate changes.
Currency Exchange Rate Risk
Foreign sales accounted for none of the Company's sales; the Company accepts payment for its commodity sales only in U.S. dollars. Ring is therefore not exposed to foreign currency exchange rate risk on these sales.
Please also see Item 1A “Risk Factors” for a discussion of other risks and uncertainties we face in our business.
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Item 4: Controls and Procedures
Evaluation of disclosure controls and procedures.
Our management, with the participation of Paul D. McKinney, our principal executive officer, and Sundip S. Johl, our principal financial officer, evaluated the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Exchange Act. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints, and that management is required to apply its judgment in evaluating the benefits of possible controls and procedures relative to their costs.
Based on management’s evaluation, Messrs. McKinney and Johl concluded that our disclosure controls and procedures as of the end of the period covered by this report were effective in ensuring that information required to be disclosed by us in reports that we file or submit under the Exchange Act (i) is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and (ii) is accumulated and communicated to the Company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
We will continue to monitor and evaluate the effectiveness of our disclosure controls and procedures and our internal controls over financial reporting on an ongoing basis and are committed to taking further action and implementing additional enhancements or improvements, as necessary and as funds allow.
Changes in internal control over financial reporting.
We regularly review our system of internal control over financial reporting and make changes to our processes and systems to improve controls and increase efficiency, while ensuring that we maintain an effective internal control environment. Changes may include such activities as implementing new, more efficient systems, consolidating activities, and migrating processes.
There were no changes in our internal control over financial reporting that occurred during the three months ended March 31, 2026 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II — OTHER INFORMATION
Item 1: Legal Proceedings
There were no material developments during the quarter ended March 31, 2026 in the legal proceeding described in our Annual Report on Form 10-K for the year ended December 31, 2025.
Item 1A: Risk Factors
We are subject to certain risks and hazards due to the nature of the business activities we conduct. For a discussion of these risks, see “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2025 as filed with the SEC. We may experience additional risks and uncertainties not currently known to us. Further, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect us. Any such risks may materially and adversely affect our business, financial condition, cash flows, and results of operations.
Item 2: Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3: Defaults Upon Senior Securities
None.
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Item 4: Mine Safety Disclosures
None.
Item 5: Other Information
During the quarter ended March 31, 2026, none of our directors or officers (as defined in Rule 16a-1(f) of the Securities Exchange Act of 1934) adopted terminated
Item 6: Exhibits
| Incorporated by Reference | ||||||||||||||||||||||||||||||||||||||||||||
| Exhibit Number | Exhibit Description | Form | File No. | Exhibit | Filing Date | Filed Here-with | Furnished Herewith | |||||||||||||||||||||||||||||||||||||
| 31.1 | Rule 13a-14(a) Certification by Principal Executive Officer | X | ||||||||||||||||||||||||||||||||||||||||||
| 31.2 | Rule 13a-14(a) Certification by Principal Financial Officer | X | ||||||||||||||||||||||||||||||||||||||||||
| 32.1 | Section 1350 Certification of Principal Executive Officer | X | ||||||||||||||||||||||||||||||||||||||||||
| 32.2 | Section 1350 Certification Principal Financial Officer | X | ||||||||||||||||||||||||||||||||||||||||||
| 101.SCH | Inline XBRL Taxonomy Extension Schema Document | X | ||||||||||||||||||||||||||||||||||||||||||
| 101.CAL | Inline XBRL Taxonomy Extension Calculation Linkbase Document | X | ||||||||||||||||||||||||||||||||||||||||||
| 101.DEF | Inline XBRL Taxonomy Extension Definition Linkbase Document | X | ||||||||||||||||||||||||||||||||||||||||||
| 101.LAB | Inline XBRL Taxonomy Extension Label Linkbase Document | X | ||||||||||||||||||||||||||||||||||||||||||
| 101.PRE | Inline XBRL Taxonomy Extension Presentation Linkbase Document | X | ||||||||||||||||||||||||||||||||||||||||||
| 104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) | |||||||||||||||||||||||||||||||||||||||||||
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| Ring Energy, Inc. | |||||||||||
Date: May 6, 2026 | By: | /s/ Paul D. McKinney | |||||||||
| Paul D. McKinney | |||||||||||
| Chief Executive Officer | |||||||||||
| (Principal Executive Officer) | |||||||||||
Date: May 6, 2026 | By: | /s/ Sundip S. Johl | |||||||||
Sundip S. Johl | |||||||||||
Chief Financial Officer | |||||||||||
(Principal Financial Officer) | |||||||||||
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FAQ
How did Ring Energy (REI) perform financially in Q1 2026?
Ring Energy reported a Q1 2026 net loss of $220.6 million, compared with net income of $9.1 million a year earlier. The loss was mainly driven by a $162.1 million ceiling test impairment and an $82.2 million loss on derivative contracts, despite positive operating cash flow.
What were Ring Energy (REI) revenues and key operating costs in Q1 2026?
Oil, natural gas and NGL revenues were $73.7 million in Q1 2026, down from $79.1 million in Q1 2025. Major expenses included lease operating costs of $18.1 million, production taxes of $3.6 million, and depreciation, depletion and amortization of $21.4 million.
What caused Ring Energy’s large impairment charge in Q1 2026?
Ring Energy uses the full cost method and tests its oil and gas properties against a regulatory ceiling. In Q1 2026, lower oil prices reduced the present value of future net revenues, triggering a $162.1 million ceiling test impairment on its oil and natural gas properties.
How much cash did Ring Energy (REI) generate from operations in Q1 2026?
Despite the accounting loss, Ring Energy generated $25.9 million in net cash from operating activities during Q1 2026. Non-cash items such as $162.1 million of impairment and $82.2 million of derivative losses reconciled the loss back to positive operating cash flow.
What is Ring Energy’s debt and liquidity position as of March 31, 2026?
As of March 31, 2026, Ring Energy had $426.0 million outstanding under its revolving credit facility, with a borrowing base of $585.0 million. After considering $35,000 of standby letters of credit, unused availability was about $159.0 million, and the company remained in covenant compliance.
Did Ring Energy (REI) make any acquisitions or divestitures in early 2026?
Yes. On January 30, 2026, Ring sold certain non-operated interests for approximately $4.3 million in cash. On February 11, 2026, it acquired a working interest partner’s interests in Yoakum County, Texas horizontal wells for about $2.0 million in cash.
What tax-related changes affected Ring Energy in Q1 2026?
Ring Energy recorded an income tax benefit of $12.0 million in Q1 2026, yielding an effective tax rate of 5.15%. The rate was lowered primarily by a new $25 million valuation allowance on federal deferred tax assets, reflecting a three-year cumulative loss position.