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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

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

	For the Fiscal Year Ended December 31, 2025 OR
☐	Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Fiscal Year Ended December 31, 2024

☐ Transition Report Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Commission File No. 0-19279

EVERFLOW EASTERN PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware	34-1659910
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

585 West Main Street
P.O. Box 629
Canfield, Ohio	44406
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (330) 533-2692

Securities registered pursuant to Section 12(b) of the Act.

Title of each class Name of each exchange on which registered ~~None~~

None

Securities registered pursuant to Section 12(g) of the Act:

Units of Limited Partnership Interest

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

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 ☒ No ☐

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 ☒ No ☐

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 the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☐	Accelerated filer ☐

Non-accelerated filer ☒

Smaller reporting company ☒	Emerging growth company ☐

~~Table~~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 ~~Contents~~the Exchange

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. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 USC. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

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

There were 4,~~303~~256,~~775~~501 Units of limited partnership interest held by non-affiliates of the Registrant as of June 30, ~~2024~~2025. At June 30, ~~2024~~2025, there was no public market for the Registrant’s Units of limited partnership interest. There were 4,~~634~~610,~~720~~646 Units of limited partnership interest of the Registrant as of March 10, ~~2025~~2026. The Units generally do not have any voting rights, but, in certain circumstances, the Units are entitled to one vote per Unit.

Except as otherwise indicated, the information contained in this Report is as of December 31, ~~2024~~2025.

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EVERFLOW EASTERN PARTNERS, L.P.

INDEX

	DESCRIPTION		PAGE NO.

Part I.

	Item 1.	Business	1

	Item 1A.	Risk Factors	10

	Item 1B.	Unresolved Staff Comments	10

	Item 1C.	Cybersecurity	10

	Item 2.	Properties	11

	Item 3.	Legal Proceedings	14

	Item 4.	Mine Safety Disclosures	14

	Supplemental Item – Information About Our Executive Officers		14

Part II.

	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	15

	Item 6.	[Reserved]	15

	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16

	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	25

	Item 8.	Financial Statements and Supplementary Data	25

Table of Contents

	DESCRIPTION		PAGE NO.

		Report of Independent Registered Public Accounting Firm (Maloney + Novotny LLC, Cleveland, OH PCAOB ID: 320)	F-3

		Consolidated Balance Sheets	F-5

		Consolidated Statements of Operations	F-7

		Consolidated Statements of Partners’ Equity	F-8

		Consolidated Statements of Cash Flows	F-9

		Notes to Consolidated Financial Statements	F-10

	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	26

	Item 9A.	Controls and Procedures	26

	Item 9B.	Other Information	27

	Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	27

Part III.

	Item 10.	Directors, Executive Officers and Corporate Governance	28

	Item 11.	Executive Compensation	32

	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	35

	Item 13.	Certain Relationships and Related Transactions, and Director Independence	37

	Item 14.	Principal Accounting Fees and Services	38

Part IV.

	Item 15.	Exhibits and Financial Statement Schedules	39

	Item 16.	Form 10-K Summary	39

Exhibit Index			E-1

	DESCRIPTION		PAGE NO.
		Report of Independent Registered Public Accounting Firm (Maloney + Novotny LLC, Cleveland, OH PCAOB ID: 320)	F-3
		Consolidated Balance Sheets	F-5
		Consolidated Statements of Operations	F-7
		Consolidated Statements of Partners’ Equity	F-8
		Consolidated Statements of Cash Flows	F-9
		Notes to Consolidated Financial Statements	F-10
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	26
	Item 9A.	Controls and Procedures	26
	Item 9B.	Other Information	27
	Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	27
Part III.
	Item 10.	Directors, Executive Officers and Corporate Governance	28
	Item 11.	Executive Compensation	32
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	35
	Item 13.	Certain Relationships and Related Transactions, and Director Independence	37
	Item 14.	Principal Accounting Fees and Services	38

Part IV.
	Item 15.	Exhibits and Financial Statement Schedules	39
	Item 16.	Form 10-K Summary	39
Exhibit Index			E-1

Table of Contents

PART I

ITEM 1. BUSINESS

Introduction

Everflow Eastern Partners, L.P. (the “Company”), a Delaware limited partnership, engages in the business of oil and gas acquisition, exploration, development and production. The Company was formed for the purpose of consolidating the business and oil and gas properties of Everflow Eastern, Inc., an Ohio corporation (“EEI”), and the oil and gas properties owned by certain limited partnerships and working interest programs managed or operated by EEI (the “Programs”). Everflow Management Limited, LLC (the “General Partner”), an Ohio limited liability company, is the general partner of the Company.

Exchange Offer. The Company made an offer (the “Exchange Offer”) to acquire the common shares of EEI (the “EEI Shares”) and the interests of investors in the Programs (collectively the “Interests”) in exchange for units of limited partnership interest (the “Units”). The Exchange Offer was made pursuant to a Registration Statement on Form S-1 declared effective by the Securities and Exchange Commission (the “SEC”) on December 19, 1990 (the “Registration Statement”) and the Prospectus dated December 19, 1990, as filed with the ~~Commission~~SEC pursuant to Rule 424(b).

The Exchange Offer terminated on February 15, 1991 and holders of Interests with an aggregate value (as determined by the Company for purposes of the Exchange Offer) of $66,996,249 accepted the Exchange Offer and tendered their Interests. Effective on such date, the Company acquired such Interests, which included partnership interests and working interests in the Programs, and all of the outstanding EEI Shares. Of the Interests tendered in the Exchange Offer, $28,565,244 was represented by the EEI Shares and $38,431,005 by the remaining Interests.

The parties who accepted the Exchange Offer and tendered their Interests received an aggregate of 6,632,464 Units. Everflow Management Company, a predecessor of the General Partner of the Company, contributed Interests with an aggregate exchange value of $670,980 in exchange for a 1% interest in the Company.

The Company. The Company was organized in September 1990. The principal executive offices of the Company, the General Partner and EEI are located at 585 West Main Street, Canfield, Ohio 44406. The telephone number is (330) 533-2692.

Description of the Business

General. The Company has participated on an on-going basis in the acquisition, exploration, development and production of undeveloped oil and gas properties and has pursued the acquisition of producing oil and gas properties.

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Subsidiaries. The Company has two subsidiaries. EEI was organized as an Ohio corporation in February 1979 and, since the consummation of the Exchange Offer, has been a wholly-owned subsidiary of the Company. EEI is engaged in the business of oil and gas production and operations management.

A-1 Storage of Canfield, Ltd. (“A-1 Storage”) was organized as an Ohio limited liability company in 1995 and is 99% owned by the Company and 1% owned by EEI. A-1 Storage’s business includes leasing of office space to the Company as well as rental of storage units to non-affiliated parties.

Current Operations. The properties of the Company consist in large part of fractional undivided working interests in properties containing proved reserves of oil and gas located in the Appalachian Basin region of Ohio and Pennsylvania. Approximately 3766% of the estimated total future cash inflows related to the Company’s crude oil and natural gas reserves as of December 31, ~~2024~~2025 are attributable to natural gas reserves. The majority of such properties are located in Ohio and consist primarily of proved producing properties with established production histories.

The Company’s operations since February 1991 primarily involve the production and sale of oil and gas and the drilling and development of approximately 444 (net) wells. The Company serves as the operator of approximately 7271% of the gross wells and 89% of the net wells which comprise the Company’s properties during the year ~~2024~~2025.

The Company expects to hold its producing properties until the oil and gas reserves underlying such properties are substantially depleted. However, the Company may, from time to time, sell any of its producing or other properties or leasehold interests if the Company believes that such sale would be in its best interest.

Sales of Deep Rights. The Company has sold its deep rights in certain Ohio and Pennsylvania properties for cash consideration as part of various agreements with multiple purchasers (the "Dispositions"). The Dispositions included no producing reserves, and the Company retained the rights to the shallow portion of all acreage sold in addition to some of the rights to a portion of the deep acreage sold, subject to the agreements. During 2012, the Company sold approximately 30,600 acres in conjunction with the Dispositions.

Business Plan. The Company continually evaluates whether it can develop oil and gas properties at historical levels given the current costs of drilling and development activities, the current prices of crude oil and natural gas, and the Company’s ability to find oil and gas in commercially productive quantities. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.”

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~~Table~~Acquisition of ~~Contents~~Prospects. From time to time, the Company maintains a leasehold inventory from which the General Partner will select oil and gas prospects for development by the Company. Prior to 2000, EEI generated approximately 90% of the prospects which were drilled. Since 2000, the Company began generating fewer prospects and has participated in more joint ventures with other operators. As of December 31, 2025, the Company has no leasehold inventory.

~~Acquisition~~In ofchoosing ~~Prospects. From~~oil ~~time~~and togas ~~time,~~prospects for the Company, ~~maintains~~the aGeneral ~~leasehold~~Partner ~~inventory~~does ~~from~~not ~~which~~attempt to manage the ~~General~~risks ~~Partner~~of ~~will~~drilling ~~select~~through ~~oil~~a ~~and~~policy ~~gas~~of selecting diverse prospects ~~for~~in ~~development~~various bygeographic areas or with the ~~Company~~potential of oil and gas production from different geological formations. ~~Prior~~Rather, substantially all prospects are expected to ~~2000,~~be ~~EEI~~located ~~generated~~in ~~approximately~~the ~~90%~~Appalachian Basin of ~~the~~Ohio ~~prospects~~and ~~which~~Pennsylvania ~~were~~and are to be drilled. ~~Since~~primarily ~~2000,~~to the ~~Company~~Clinton/Medina ~~began~~Sands ~~generating~~geological ~~fewer~~formation ~~prospects~~or closely related oil and gas formations in such area. The Company also has ~~participated~~the right to participate in ~~more~~the ~~joint~~development ~~ventures~~of certain wells in the Utica geological formation with ~~other~~various ~~operators~~joint venture partners. In As2025, the Company elected to participate in the development of ~~December~~one ~~31,~~well ~~2024,~~in the Utica geological formation. The well was completed during 2025 and is producing. The Company ~~has~~did nonot ~~leasehold~~participate ~~inventory~~in the development of wells in the Utica geological formation in 2024.

InAcquisition ~~choosing~~of ~~oil~~Producing ~~and~~Properties. As ~~gas~~a ~~prospects~~potential ~~for~~means ~~the~~of ~~Company,~~increasing ~~the~~its ~~General~~reserve ~~Partner~~base, ~~does~~the ~~not~~Company ~~attempt~~expects to ~~manage~~evaluate ~~the~~opportunities ~~risks~~which ofit ~~drilling~~may ~~through~~be apresented ~~policy of selecting diverse prospects in various geographic areas or~~ with ~~the~~to ~~potential~~acquire of oil and gas ~~production~~producing properties from ~~different~~third ~~geological~~parties ~~formations. Rather, substantially all prospects are expected to be located~~ in ~~the~~addition ~~Appalachian Basin of Ohio and Pennsylvania and are~~ to beits ~~drilled~~potential ~~primarily~~leasehold toacquisition ~~the Clinton/Medina Sands geological formation or closely related oil~~ and ~~gas~~development ~~formations in such area~~activities. The Company ~~also~~did ~~has~~not ~~the~~acquire ~~right~~any toproducing ~~participate~~oil inand ~~the~~gas ~~development~~properties ofduring ~~certain~~2025 ~~wells~~and ~~in the Utica geological formation with various joint venture partners~~2024.

Acquisition of Producing Properties. As a potential means of increasing its reserve base, the Company expects to evaluate opportunities which it may be presented with to acquire oil and gas producing properties from third parties in addition to its potential leasehold acquisition and development activities. The Company did not acquire any producing oil and gas properties during 2024 and 2023.

The Company will continue to evaluate properties for acquisition. Such properties may include, in addition to working interests, royalty interests, net profit interests and production payments, other forms of direct or indirect ownership interests in oil and gas production, and properties associated with the production of oil and gas. The Company also may acquire general or limited partner interests in general or limited partnerships and interests in joint ventures, corporations or other entities that have, or are formed to acquire, explore for or develop, oil and gas or conduct other activities associated with the ownership of oil and gas production.

Funding for Activities. The Company has historically financed its current operations, including undeveloped leasehold acquisition activities, primarily through cash generated from operations and existing cash and equivalents. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Results of Operations.”

The Company is permitted to incur indebtedness for any partnership purpose. It is currently anticipated that any future indebtedness would consist primarily of borrowings from commercial banks. The Company had no new borrowings in ~~2023~~2024 or ~~2024~~2025 and no principal indebtedness was outstanding as of March 10, ~~2025~~2026. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Liquidity and Capital Resources.”

Although the Company’s Amended and Restated Agreement of Limited Partnership dated as of February 10, 2010 (as amended from time to time, the “Partnership Agreement”) does not contain any specific restrictions on borrowings, the Company has no specific plans to borrow for the acquisition of producing oil and gas properties or for any other purpose. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Liquidity and Capital Resources.”

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~~Table~~The Company owns a significant amount of ~~Contents~~oil and gas reserves. The Company generally does not expect to borrow funds, from whatever source, in excess of 40% of its total value of proved developed reserves (as determined using the Company’s Standardized Measure of Discounted Future Net Cash Flows). However, there can be no assurance that the Company’s future obligations and liabilities would not lead to borrowings in excess of such amount. Based upon its current business plan, management has no present intention to cause the Company to borrow in excess of this amount. The Company has estimated the value of proved and proved developed reserves, determined as of December 31, 2025, net of asset retirement obligations, which aggregate a net liability of $4,642,000 (Standardized Measure of Discounted Future Net Cash Flows).

The Company owns a significant amount of oil and gas reserves. The Company generally does not expect to borrow funds, from whatever source, in excess of 40% of its total value of proved developed reserves (as determined using the Company’s Standardized Measure of Discounted Future Net Cash Flows). However, there can be no assurance that the Company’s future obligations and liabilities would not lead to borrowings in excess of such amount. Based upon its current business plan, management has no present intention to cause the Company to borrow in excess of this amount. The Company has estimated the value of proved and proved developed reserves, determined as of December 31, 2024, net of asset retirement obligations, which aggregate a net liability of $5,979,000 (Standardized Measure of Discounted Future Net Cash Flows).

Marketing. The ability of the Company to market crude oil and natural gas found in and produced on its properties will depend on a number of factors beyond its control, and the impact of such factors, either individually or in the aggregate, cannot be anticipated or measured. These factors include, among others, the amount of domestic oil and gas production and foreign imports available from other sources, the capacity and proximity of pipelines, governmental regulations, and general market demand.

Crude Oil. Any crude oil produced from the properties can be sold at the prevailing field price to one or more of a number of unaffiliated purchasers in the area. The price paid by these purchasers is generally an established or “posted” price which is offered to all producers in the same region. Historically, posted prices in the areas where the Company’s properties are located have generally been somewhat lower than the spot market prices. There have been substantial fluctuations in crude oil prices in recent years, including ~~2024~~2025 and ~~2023~~2024.

The price of crude oil in the Appalachian Basin has ranged from a low of $8.50 per barrel in December 1998 to a high of $138.00 in July 2008. As of March 10, ~~2025~~2026, $6279.0345 per barrel was the prevailing field price in the Appalachian Basin area, the Company’s principal area of operation. There can be no assurance that prices will not be subject to continual fluctuations. Future crude oil prices are difficult to predict because of the impact of worldwide economic trends, supply and demand variables, and such non-economic factors as the disruption in global supply resulting from various global conflicts, including the March 2026 conflict between the United States of America and Iran, political impact on pricing policies by the Organization of Petroleum Exporting Countries (“OPEC”), governmental instability in foreign oil producing countries, energy and environmental policy of federal, state and local governments, and the possibility of other supply interruptions. To the extent the prices that the Company receives for its crude oil production decline, the Company’s revenues from crude oil production will be reduced accordingly.

Since January 1993, the Company has sold substantially all of its crude oil production to one oil purchaser.

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~~Table~~Natural Gas. The deliverability and price of ~~Contents~~natural gas is subject to various factors affecting the supply and demand of natural gas as well as the effect of federal regulations. Prior to 2000, there had been a surplus of natural gas available for delivery to pipelines and other purchasers. During 2000, decreases in worldwide energy production capability and increases in energy consumption resulted in a shortage in natural gas supplies. This resulted in increases in natural gas prices throughout the United States, including the Appalachian Basin. During 2001, lower energy consumption and increased natural gas supplies reduced prices to historical levels. During the period from 2002 through the first half of 2008, shortages in natural gas supplies had resulted from increased energy consumption from industrial, commercial, residential and electric power usage. During the second half of 2008 and through 2016, excess natural gas supplies resulted from the combination of increased production from integrated and independent producers and decreased industrial and commercial energy consumption resulting from the global and United States financial crises and recession. During 2017 and through 2019, excess natural gas supplies were the continued result of increased production and production capacity from regional integrated and independent producers. During 2020, excess natural gas supplies were primarily the result of decreased industrial and commercial energy consumption resulting from global shutdowns related to COVID-19. During 2021 and through 2022, shortages in natural gas supplies were the continued result of increased industrial and commercial energy consumption following COVID-19, global supply chain issues, regulatory actions and executive orders issued by the federal government and decreased supply in Europe resulting from the conflict in Ukraine. During 2023 and 2024, excess natural gas supplies were the continued result of increased production and production capacity from regional integrated and independent producers. During 2025, shortages in natural gas supplies were primarily the result of increased industrial, commercial, residential and electric power consumption. This resulted in increases in natural gas prices throughout the majority United States, while having less of an effect on the Appalachian Basin which continues to experience excess natural gas supplies. From time to time, especially in summer months, seasonal restrictions on natural gas production have occurred as a result of distribution system restrictions.

~~Natural~~Over ~~Gas. The~~the ~~deliverability~~ten ~~and~~years ~~price~~prior ~~of natural gas is subject~~ to ~~various~~2002, ~~factors affecting~~ the ~~supply~~Company ~~and~~had ~~demand~~followed ofa ~~natural~~practice ~~gas as well as the effect~~ of ~~federal~~selling ~~regulations. Prior to 2000, there had been~~ a ~~surplus~~significant portion of its natural gas ~~available~~pursuant ~~for delivery~~ to ~~pipelines~~Intermediate ~~and~~Term ~~other~~Adjustable ~~purchasers.~~Price ~~During~~Gas ~~2000,~~Purchase ~~decreases~~Agreements in(the ~~worldwide~~“Contracts”) ~~energy~~with ~~production~~one ~~capability and increases in energy consumption resulted in a shortage in natural~~ gas ~~supplies~~purchaser. ~~This~~Pursuant ~~resulted~~to ~~in increases in natural gas prices throughout~~ the ~~United~~Contracts ~~States, including the Appalachian Basin. During 2001, lower energy consumption~~ and ~~increased~~subject ~~natural gas supplies reduced prices~~ to ~~historical~~certain ~~levels.~~restrictions ~~During~~and ~~the period from 2002 through the first half of 2008~~adjustments, ~~shortages~~including intermination ~~natural gas supplies had resulted from increased energy consumption from industrial~~clauses, ~~commercial, residential and electric power usage. During~~ the ~~second~~gas ~~half~~purchaser ofwas ~~2008~~obligated ~~and~~to ~~through 2016~~purchase, ~~excess natural gas supplies resulted from the combination of increased production from integrated~~ and ~~independent producers and decreased industrial and commercial energy consumption resulting from~~ the ~~global~~Company ~~and~~was ~~United~~obligated ~~States~~to ~~financial crises and recession. During 2017 and through 2019~~sell, ~~excess~~all natural gas ~~supplies were the continued result of increased~~ production ~~and production capacity~~ from ~~regional~~a ~~integrated~~specified ~~and~~list ~~independent producers. During 2020, excess natural gas supplies were primarily the result~~ of ~~decreased industrial and commercial energy consumption resulting from global shutdowns related to COVID-19~~wells. ~~During~~Pricing ~~2021~~under ~~and through 2022, shortages in natural gas supplies were~~ the ~~continued~~Contracts ~~result~~was ofadjusted ~~increased industrial and commercial energy consumption following COVID-19~~annually, ~~global~~up ~~supply~~or ~~chain issues~~down, ~~regulatory actions and executive orders issued~~ by ~~the~~an ~~federal~~amount ~~government~~equal ~~and~~to ~~decreased~~80% ~~supply~~of ~~in Europe resulting from~~ the ~~conflict~~increase inor ~~Ukraine.~~decrease ~~During 2023 and 2024, excess natural gas supplies were the continued result of increased production and production capacity from regional integrated and independent producers. This resulted~~ in ~~significant decreases in natural gas prices throughout~~ the ~~United States, including the Appalachian Basin. From time to time, especially in summer months, seasonal restrictions on natural~~ gas ~~production~~purchaser’s ~~have~~average ~~occurred~~Gas asCost aRecovery ~~result of distribution system restrictions~~rates.

~~Over~~Since 2002, the ~~ten~~Company ~~years~~has ~~prior~~had multiple annual or biennial contracts with various gas purchasers, which obligated the gas purchasers, to ~~2002~~purchase, and the Company ~~had~~to ~~followed~~sell aand ~~practice~~deliver, certain quantities of ~~selling~~natural agas ~~significant~~production ~~portion~~from ofthe ~~its~~Company’s ~~natural~~oil and gas ~~pursuant~~properties tothroughout ~~Intermediate~~the ~~Term~~contract ~~Adjustable~~periods. ~~Price~~The ~~Gas~~Company ~~Purchase~~may ~~Agreements~~elect ~~(the~~to ~~“East~~lock-in ~~Ohio~~specific ~~Contracts”)~~volumes ~~with~~of ~~one~~natural gas ~~purchaser~~to ~~(the~~be ~~“Major~~sold ~~Gas~~in ~~Purchaser”)~~specific months at a mutually agreeable price. ~~Pursuant~~As toof March 10, 2026, the ~~East~~Company ~~Ohio~~has ~~Contracts~~elected ~~and~~to ~~subject~~lock-in 1,170,000 MCF from January 2026 to ~~certain~~April ~~restrictions~~2027 ~~and~~at ~~adjustments,~~a ~~including~~weighted ~~termination~~average ~~clauses~~price of $3.40 per MCF, net of regional basis adjustments. The price paid for natural gas purchased by the ~~Major~~gas ~~Gas~~purchasers ~~Purchaser~~varies ~~was~~based ~~obligated~~on toquantities ~~purchase,~~committed ~~and~~to by the Company ~~was~~from ~~obligated~~time to ~~sell,~~time. ~~all~~Natural ~~natural~~ gas ~~production~~sold ~~from~~under athese ~~specified~~contracts ~~list~~in excess of ~~wells.~~the ~~Pricing~~committed ~~under~~quantities is sold at the ~~East~~month’s ~~Ohio~~closing ~~Contracts~~price ~~was~~at ~~adjusted~~Henry ~~annually~~Hub, upwhich is the location for pricing NYMEX, plus or ~~down~~minus regional basis adjustments, as per the contracts. These contracts are not considered derivatives, but have been designated as annual sales contracts as defined by angenerally ~~amount~~accepted ~~equal~~accounting toprinciples. ~~80%~~During of2025, ~~the~~natural ~~increase~~gas orpurchased ~~decrease~~by inone gas purchaser (the “Major Gas Purchaser”) covered production from approximately 560 gross operated wells. See “MANAGEMENT’sS ~~average~~DISCUSSION ~~Gas~~AND ~~Cost~~ANALYSIS ~~Recovery~~OF ~~rates~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Commodity Pricing, Risk Management Activities and Inflation.”

Since 2002, the Company has had multiple annual or biennial contracts with various gas purchasers, including the Major Gas Purchaser, which obligated the gas purchasers, including the Major Gas Purchaser, to purchase, and the Company to sell and deliver, certain quantities of natural gas production from the Company’s oil and gas properties throughout the contract periods. The Company may elect to lock-in specific volumes of natural gas to be sold in specific months at a mutually agreeable price. As of March 10, 2025, the Company has elected to lock-in 1,200,000 MCF from March 2025 to April 2027 at a weighted average price of $3.34 per MCF, net of regional basis adjustments. The price paid for natural gas purchased by the gas purchasers varies based on quantities committed to by the Company from time to time. Natural gas sold under these contracts in excess of the committed quantities is sold at the month’s closing price at Henry Hub, which is the location for pricing NYMEX, plus or minus regional basis adjustments, as per the contracts. These contracts are not considered derivatives, but have been designated as annual sales contracts as defined by generally accepted accounting principles. During 2024, natural gas purchased by the Major Gas Purchaser covered production from approximately 560 gross operated wells. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Commodity Pricing, Risk Management Activities and Inflation.”

Since the second half of 2013, the market price for natural gas in the Appalachian Basin has experienced a decline relative to the price at Henry Hub primarily as a result of regional basis adjustments resulting primarily from the increased supply of natural gas in the Ohio and Pennsylvania regions. Changes in the market price for natural gas, including regional basis, impact the Company’s revenues, earnings and liquidity. The Company is unable to predict potential future movements in the market price for natural gas, including regional basis, and thus cannot predict the ultimate impact of prices on its operations.

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~~Table~~Since the second half of ~~Contents~~2013, the market price for natural gas in the Appalachian Basin has experienced a decline relative to the price at Henry Hub primarily as a result of regional basis adjustments resulting primarily from the increased supply of natural gas in the Ohio and Pennsylvania regions. Changes in the market price for natural gas, including regional basis, impact the Company’s revenues, earnings and liquidity. The Company is unable to predict potential future movements in the market price for natural gas, including regional basis, and thus cannot predict the ultimate impact of prices on its operations.

During ~~2024~~2025, no one natural gas purchaser accounted for more than 10% of the Company’s natural gas sales other than the Major Gas Purchaser, whose purchases of natural gas from operated wells accounted for approximately 6978% of the Company’s consolidated natural gas sales. The Company expects that the Major Gas Purchaser will be the only material natural gas purchaser during fiscal year ~~2025~~2026.

Seasonality. During summer months, seasonal restrictions on natural gas production have sometimes occurred as a result of distribution system restrictions. These production restrictions, and the nature of the Company’s business, can result in seasonal fluctuations in the Company’s revenue, with the Company sometimes receiving more income in the first and fourth quarters of its fiscal year.

Title to Properties. As is customary in the oil and gas industry, the Company performs a limited investigation as to ownership of leasehold acreage at the time of acquisition and conducts a title examination and necessary curative work prior to the commencement of drilling operations on a tract. Title examinations have been performed for substantially all of the producing oil and gas properties owned by the Company with regard to (i) substantial tracts of land forming a portion of such oil and gas properties and (ii) the wellhead location of such properties. The Company believes that title to its properties is acceptable although such properties may be subject to royalty, overriding royalty, carried and other similar interests in contractual arrangements customary in the oil and gas industry. Also, such properties may be subject to liens incident to operating agreements and liens for current taxes not yet due, as well as other comparatively minor encumbrances.

Competition. The oil and gas industry is highly competitive in all its phases. The Company encounters strong competition from major and independent oil and gas companies in acquiring economically desirable prospects as well as in marketing production therefrom and obtaining external financing. Major oil and gas companies, independent concerns, drilling and production purchase programs and individual producers and operators are active bidders for desirable oil and gas properties, as well as the equipment and labor required to operate those properties. Many of the Company’s competitors have financial resources, personnel and facilities substantially greater than those of the Company.

The availability of a ready market for the oil and gas production of the Company depends in part on the cost and availability of alternative fuels, the level of consumer demand, the extent of other domestic production of oil and gas, the extent of importation of foreign oil and gas, the cost of and proximity to pipelines and other transportation facilities, regulations by state and federal authorities and the cost of complying with applicable environmental regulations. The volatility of prices for oil and gas, and the continued oversupply of domestic natural gas have, at times, including ~~2024~~2025, resulted in a curtailment in exploration for and development of oil and gas properties.

There is also extensive competition in the market for gas produced by the Company. Increases in energy consumption have at times brought about a shortage in energy supplies. This, in turn, has resulted in substantial competition for markets historically served by domestic natural gas resources both with alternate sources of energy, such as residual fuel oil, and among domestic gas suppliers. As a result, at times there has been volatility in crude oil and natural gas prices, widespread curtailment of gas production and delays in producing and marketing gas after it is discovered. Changes in government regulations relating to the production, transportation and marketing of natural gas have also resulted in significant changes in the historical marketing patterns of the industry. Generally, these changes have resulted in the abandonment by many pipelines of long-term contracts for the purchase of natural gas, the development by gas producers of their own marketing programs to take advantage of new regulations requiring pipelines to transport gas for regulated fees, and an increasing tendency to rely on short-term sales contracts priced at spot market prices. See “Marketing” appearing on page 4 herein.

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~~Table~~There is also extensive competition in the market for gas produced by the Company. Increases in energy consumption have at times brought about a shortage in energy supplies. This, in turn, has resulted in substantial competition for markets historically served by domestic natural gas resources both with alternate sources of ~~Contents~~energy, such as residual fuel oil, and among domestic gas suppliers. As a result, at times there has been volatility in crude oil and natural gas prices, widespread curtailment of gas production and delays in producing and marketing gas after it is discovered. Changes in government regulations relating to the production, transportation and marketing of natural gas have also resulted in significant changes in the historical marketing patterns of the industry. Generally, these changes have resulted in the abandonment by many pipelines of long-term contracts for the purchase of natural gas, the development by gas producers of their own marketing programs to take advantage of new regulations requiring pipelines to transport gas for regulated fees, and an increasing tendency to rely on short-term sales contracts priced at spot market prices. See “Marketing” appearing on page 4 herein.

Gas prices, which were once effectively determined by government regulations, are now influenced largely by the effects of competition. Competitors in this market include other producers, gas pipelines and their affiliated marketing companies, independent marketers, and providers of alternate energy supplies.

Regulation of Oil and Gas Industry. The exploration, production and sale of oil and natural gas are subject to numerous state and federal laws and regulations. Such laws and regulations govern a wide variety of matters, including the drilling and spacing of wells, allowable rates of production, marketing, pricing and protection of the environment. Such regulations may restrict the rate at which the Company’s wells produce crude oil and natural gas below the rate at which such wells could produce in the absence of such regulations. In addition, legislation and regulations concerning the oil and gas industry are constantly being reviewed and proposed. Ohio and Pennsylvania, the states in which the Company owns properties and operates, have statutes and regulations governing a number of the matters enumerated above. Compliance with the laws and regulations affecting the oil and gas industry generally increases the Company’s costs of doing business and consequently affects its profitability. Inasmuch as such laws and regulations are frequently amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with such regulations.

The interstate transportation and sale for resale of natural gas is regulated by the Federal Energy Regulatory Commission (the “FERC”) under the Natural Gas Act of 1938. The wellhead price of natural gas is also regulated by the FERC under the authority of the Natural Gas Policy Act of 1978 (“NGPA”). Subsequently, the Natural Gas Wellhead Decontrol Act of 1989 (the “Decontrol Act”) was enacted on July 26, 1989. The Decontrol Act provided for the phasing out of price regulation under the NGPA commencing on the date of enactment and completely eliminated all such gas price regulation on January 1, 1993. In addition, the FERC has adopted and proposed several rules or orders concerning transportation and marketing of natural gas. The impact of these rules and other regulatory developments on the Company cannot be predicted. It is expected that the Company will sell natural gas produced by its oil and gas properties to a number of purchasers, including various industrial customers, pipeline companies and local public utilities, although the majority of natural gas sales from operated wells will be sold to the Major Gas Purchaser as discussed earlier.

As a result of the NGPA and the Decontrol Act, the Company’s natural gas production is no longer subject to price regulation. Natural gas which has been removed from price regulation is subject only to that price contractually agreed upon between the producer and purchaser. Under current market conditions, deregulated gas prices under new contracts tend to be substantially lower than most regulated price ceilings originally prescribed by the NGPA. In addition to the deregulation of gas prices, the FERC has proposed and enacted several rules or orders concerning transportation and marketing of natural gas. In 1992, the FERC finalized Order 636, a rule pertaining to the restructuring of interstate pipeline services. This rule requires interstate pipelines to unbundle transportation and sales services by separately pricing the various components of their services, such as supply, gathering, transportation and sales. These pipeline companies are required to provide customers only the specific service desired without regard to the source for the purchase of the gas. Although the Company is not an interstate pipeline company, it is likely that this regulation may indirectly impact the Company by increasing competition in the marketing of natural gas. Regulation of the production, transportation and sale of oil and gas by federal and state agencies has a significant effect on the Company and its operating results. Certain states, including Ohio and Pennsylvania, have established rules and regulations requiring permits for drilling operations, drilling bonds and reports concerning the spacing of wells. The ultimate impact of these rules and other regulatory developments on the Company cannot be predicted.

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~~Table~~As a result of ~~Contents~~the NGPA and the Decontrol Act, the Company’s natural gas production is no longer subject to price regulation. Natural gas which has been removed from price regulation is subject only to that price contractually agreed upon between the producer and purchaser. Under current market conditions, deregulated gas prices under new contracts tend to be substantially lower than most regulated price ceilings originally prescribed by the NGPA. In addition to the deregulation of gas prices, the FERC has proposed and enacted several rules or orders concerning transportation and marketing of natural gas. In 1992, the FERC finalized Order 636, a rule pertaining to the restructuring of interstate pipeline services. This rule requires interstate pipelines to unbundle transportation and sales services by separately pricing the various components of their services, such as supply, gathering, transportation and sales. These pipeline companies are required to provide customers only the specific service desired without regard to the source for the purchase of the gas. Although the Company is not an interstate pipeline company, it is likely that this regulation may indirectly impact the Company by increasing competition in the marketing of natural gas. Regulation of the production, transportation and sale of oil and gas by federal and state agencies has a significant effect on the Company and its operating results. Certain states, including Ohio and Pennsylvania, have established rules and regulations requiring permits for drilling operations, drilling bonds and reports concerning the spacing of wells. The ultimate impact of these rules and other regulatory developments on the Company cannot be predicted.

In addition, from time to time, prices for either crude oil or natural gas have been regulated by the federal government, and such price regulation could be re-imposed at any time in the future.

Environmental Regulation. The activities of the Company are subject to various federal, state and local laws and regulations designed to protect the environment. The Company does not conduct any offshore activities. Operations of the Company on onshore oil properties may generally be liable for clean-up costs to the federal government under the Federal Clean Water Act for up to $50,000,000 for each incident of oil or hazardous pollution substance contamination and for up to $50,000,000, plus response costs, under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 for hazardous substance contamination. Liability is unlimited in cases of willful negligence or misconduct, and there is no limit on liability for environmental clean-up costs or damages with respect to claims by the state or private persons or entities. In addition, the Company is required by the Environmental Protection Agency (“EPA”) to prepare and implement spill prevention control and countermeasure plans relating to the possible discharge of oil into navigable waters; and the EPA will further require permits to authorize the discharge of pollutants into navigable waters. State and local permits or approvals may also be needed with respect to waste-water discharges and air pollutant emissions. Violations of environment-related lease conditions or environmental permits can result in substantial civil and criminal penalties as well as potential court injunctions curtailing operations. Such enforcement liabilities can result from prosecution by public or private entities.

Various state and governmental agencies are considering, and some have adopted, other laws and regulations regarding environmental protection which could adversely affect the proposed business activities of the Company. The Company cannot predict what effect, if any, current and future regulations may have on the operations of the Company.

Operating Hazards and Uninsured Risks. The Company’s crude oil and natural gas operations are subject to all operating hazards and risks normally incident to drilling for and producing crude oil and natural gas, such as encountering unusual formations and pressures, blow-outs, environmental pollution and personal injury. The Company maintains such insurance coverage as it believes to be appropriate taking into account the size of the Company and its operations. Losses can occur from an uninsurable risk or in amounts in excess of existing insurance coverage. The occurrence of an event which is not insured or not fully insured could have an adverse impact on the Company’s revenues and earnings.

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In certain instances, the Company may continue to engage in exploration and development operations through drilling programs formed with non-industry investors. In addition, the Company will conduct a significant portion of its operations with other parties in connection with the drilling operations conducted on properties in which it has an interest. In these arrangements, all joint interest parties, including the Company, may be fully liable for their proportionate share of all costs of such operations. Further, if any joint interest party defaults on its obligations to pay its share of costs, the other joint interest parties may be required to fund the deficiency until, if ever, it can be collected from the defaulting party. As a result of the foregoing or similar oilfield circumstances, the Company could become liable for amounts significantly in excess of amounts originally anticipated to be expended in connection with such operations. In addition, financial difficulty for an operator of oil and gas properties could result in the Company’s and other joint interest owners’ interests in properties and the wells and equipment located thereon becoming subject to liens and claims of creditors, notwithstanding the fact that non-defaulting joint interest owners and the Company may have previously paid to the operator the amounts necessary to pay their share of such costs and expenses.

Data Security Considerations. The Company has implemented data security measures and has not, to date, been subject to any material data security breaches, data loss or cyber-attacks. However, despite the Company’s efforts to protect sensitive information and confidential and personal data, comply with applicable laws, rules and regulations and implement data security measures, the Company’s facilities and systems may be vulnerable to security breaches and other data loss, including cyber-attacks. In addition, it is not possible to predict the impact on the Company’s business of the future loss, alteration or misappropriation of information in the Company’s possession related to the Company and EEI’s employees, former employees, or others. This could lead to negative publicity, legal claims, theft, modification or destruction of proprietary information or key information, damage to or inaccessibility of critical systems, operational disruptions and other significant costs, which could have an adverse impact on the Company’s revenues and earnings.

Hydraulic Fracturing. Many of the Company’s exploration and production operations depend on the use of hydraulic fracturing to enhance production from oil and gas wells. This technology involves the injection of fluids - usually consisting mostly of water but typically including small amounts of several chemical additives - as well as sand into a well under high pressure in order to create fractures in the formation that allow oil or gas to flow more freely to the wellbore. Most of our wells would not be economical without the use of hydraulic fracturing to stimulate production from the well. Due to concerns raised relating to potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal level and in some states have been initiated to render permitting and compliance requirements more stringent for hydraulic fracturing or prohibit the activity altogether. Such efforts could have an adverse effect on crude oil and natural gas production activities.

Conflicts of Interest. The Partnership Agreement grants the General Partner broad discretionary authority to make decisions on matters such as the Company’s acquisition of or participation in a drilling prospect or a producing property. To limit the General Partner’s management discretion might prevent it from managing the Company properly. However, because the business activities of the affiliates of the General Partner on the one hand and the Company on the other hand are the same, potential conflicts of interest are likely to exist, and it is not possible to completely mitigate such conflicts.

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The Partnership Agreement contains certain restrictions designed to mitigate, to the extent practicable, these conflicts of interest. The agreement restricts, among other things, (i) the cost at which the General Partner or its affiliates may acquire properties from or sell properties to the Company; (ii) loans between the General Partner, its affiliates and the Company, and interest and other charges incurred in connection therewith; and (iii) the use and handling of the Company’s funds by the General Partner.

Employees. As of March 10, ~~2025~~2026, EEI had 1617 full-time and 23 part-time employees. These employees are primarily engaged in the following areas of business operations: ~~seven~~eight in general administration, five in field operations, ~~five~~six in accounting and one in land and lease administration.

ITEM 1A. RISK FACTORS

Not a required disclosure for a Smaller Reporting Company.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None

ITEM 1C. CYBERSECURITY

The Company has implemented data security measures and has not, to date, been subject to any material data security breaches, data loss or cyber-attacks. However, despite the Company’s efforts to protect sensitive information and confidential and personal data, comply with applicable laws, rules and regulations and implement data security measures, the Company’s facilities and systems may be vulnerable to security breaches and other data loss, including cyber-attacks. In addition, it is not possible to predict the impact on the Company’s business of the future loss, alteration or misappropriation of information in the Company’s possession related to the Company and EEI’s employees, former employees, or others. This could lead to negative publicity, legal claims, theft, modification or destruction of proprietary information or key information, damage to or inaccessibility of critical systems, operational disruptions and other significant costs, which could have an adverse impact on the Company’s revenues and earnings.

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ITEM 2. PROPERTIES

Set forth below is certain information regarding the oil and gas properties of the Company which are located in the Appalachian Basin of Ohio and Pennsylvania.

In the following discussion, “gross” refers to the total acres or wells in which the Company has a working interest and “net” refers to gross acres or wells multiplied by the Company’s percentage of working interests therein. Because royalty interests held by the Company will not affect the Company’s working interests in its properties, neither gross nor net acres or wells reflect such royalty interests.

Natural Gas and Crude Oil Reserves. Proved reserves are the estimated quantities of crude oil and natural gas, which, by an analysis of geological and engineering data, can be estimated with reasonable certainty to be recoverable in future years from known reservoirs under existing economic conditions, operating methods and government regulations. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. The estimated reserves include reserves attributable to the Company’s direct ownership interests in crude oil and natural gas properties as well as the reserves attributable to the Company’s percentage interests in crude oil and natural gas properties owned through joint ventures. All of the reserves are generally located in the Appalachian Basin region of Ohio and Pennsylvania. The Company bases its estimates of proved reserves on the 12-month un-weighted average price of the first-day-of-the-month price for each calendar month of the year preceding the evaluation date. The Company then applies any basis adjustments specifically applicable to each oil and gas property based on location and pricing details. The natural gas prices used in the estimation of proved reserves were $12.7668 and $1.7576 per MCF at December 31, ~~2024~~2025 and ~~2023~~2024 respectively, and the crude oil prices used in the estimation of proved reserves were $7261.1197 and $7472.7111 per BBL at December 31, ~~2024~~2025 and ~~2023~~2024, respectively.

Reserve estimates are imprecise and may change as additional information becomes available. Furthermore, estimates of natural gas and crude oil reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production and the timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and crude oil that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.

The preparation of the Company’s natural gas and crude oil reserve estimates was completed in accordance with the Company’s prescribed internal control procedures, which include verification of input data delivered to the Company’s third-party reserve specialist, as well as a multi-functional management review. For the year ended December 31, ~~2024~~2025, the Company retained Wright & Company, Inc. (“Wright & Company”), a third-party, independent petroleum engineering firm, to prepare a report of proved reserves. The reserves report included a detailed review of all of the Company’s crude oil and natural gas properties. Wright & Company’s evaluation was based on more than 4035 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations applicable as of December 31, ~~2024~~2025. The Wright & Company report, including the qualifications of the chief technical person responsible for the report, was prepared in accordance with generally accepted petroleum engineering and evaluation principles and is attached as Exhibit 99.1 to this Annual Report on Form 10-K.

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~~Table~~Reserves Reported to Other Agencies. There were no estimates of ~~Contents~~total, proved net oil or gas reserves filed with or included in reports to any other federal authority or agency during 2025 or 2024.

~~Reserves~~Proved ~~Reported to Other Agencies~~Reserves.(1) The ~~There~~following ~~were~~table noreflects the estimates of ~~total,~~the Company’s proved ~~net oil or gas~~ reserves ~~filed~~which ~~with~~are orbased ~~included~~on inthe ~~reports~~Company’s toreserves ~~any~~report ~~other~~as ~~federal~~of ~~authority~~December or31, ~~agency during 2024 or 2023~~2025.

Proved Reserves.(1) The following table reflects the estimates of the Company’s proved reserves which are based on the Company’s reserves report as of December 31, 2024.

	Oil (BBLS)		Gas (MCF)

Proved Developed		253,000		11,067,000
Proved Undeveloped		-		-
Total		253,000		11,067,000

	Oil (BBLS)		Gas (MCF)
Proved Developed		252,000		6,083,000
Proved Undeveloped		-		-
Total		252,000		6,083,000

(1)	The Company has not determined proved reserves associated with its proved and other undeveloped properties, including its deep property interests, at December 31, 2025. A reconciliation of the Company’s proved reserves is included in the Notes to the Consolidated Financial Statements.

~~(1)~~ Production. The ~~Company~~following ~~has~~table ~~not~~summarizes ~~determined~~the ~~proved~~net ~~reserves~~crude ~~associated~~oil ~~with its proved~~ and ~~other~~natural ~~undeveloped~~gas ~~properties~~production, ~~including~~average ~~its~~sales ~~deep~~prices ~~property~~and ~~interests,~~average atproduction ~~December~~(lifting) ~~31,~~costs ~~2024.~~per Aequivalent ~~reconciliation~~unit of ~~the~~production ~~Company’s~~for ~~proved~~2025 ~~reserves~~and ~~is included in the Notes to the Consolidated Financial Statements~~2024.

Production. The following table summarizes the net crude oil and natural gas production, average sales prices and average production (lifting) costs per equivalent unit of production for 2024 and 2023.

					Average
	Production				Sales Price				Average Lifting Cost
	Oil (BBLS)		Gas (MCF)		per BBL		per MCF		per Equivalent MCF⁽¹⁾

2025		30,000		1,434,000	$	61.57	$	3.28	$	1.56
2024		31,000		1,077,000	$	72.37	$	2.15	$	1.82

	Production				Average Sales Price				Average Lifting Cost
	Oil (BBLS)		Gas (MCF)		per BBL		per MCF		per Equivalent MCF(1)
2024		31,000		1,077,000	$	72.37	$	2.15	$	1.82
2023		33,000		1,226,000	$	74.29	$	2.49	$	1.60


	⁽¹⁾	Oil production is converted to MCF equivalents at the rate of 6 MCF per BBL.

Productive Wells. The following table sets forth the gross and net oil and gas wells of the Company as of December 31, ~~2024~~2025.

Gross Wells						Net Wells	~~Net Wells~~
(1)	(1)					(1)	~~(1)~~	(1)	~~(1)~~
Oil	Gas		Total	~~Total~~		Oil	~~Oil~~	Gas	~~Gas~~Total		~~Total~~
311		756			1,067			179		499		678
247	816		1,063			136		539	675

(1) Oil wells are those wells which generated the majority of their revenues from crude oil production during ~~2024~~2025; gas wells are those wells which generated the majority of their revenues from natural gas production during ~~2024~~2025.

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~~Table~~Standardized Measure of ~~Contents~~Discounted Future Net Cash Flows.(1) The following table summarizes, as of December 31, 2025, the oil and gas reserves attributable to the oil and gas properties owned by the Company. The determination of the standardized measure of discounted future net cash flows as set forth herein is based on criteria promulgated by the SEC, using calculations based solely on proved reserves, current un-escalated costs, prices based on the 12-month average of the first day of the month price for each month in the year ended December 31, 2025, discounted to present value at 10%.

Standardized Measure of Discounted Future Net Cash Flows.(1) The following table summarizes, as of December 31, 2024, the oil and gas reserves attributable to the oil and gas properties owned by the Company. The determination of the standardized measure of discounted future net cash flows as set forth herein is based on criteria promulgated by the SEC, using calculations based solely on proved reserves, current un-escalated costs, prices based on the 12-month average of the first day of the month price for each month in the year ended December 31, 2024, discounted to present value at 10%.

	(Thousands)

Future cash inflows from sales of oil and gas	$	45,410
Future production and development costs		(27,416	)
Future asset retirement obligations, net of salvage		(19,572	)
Future income tax expense		(222	)

Future net cash flows		(1,800	)
Effect of discounting future net cash flows at 10% per annum		(2,842	)
Standardized measure of discounted future net cash flows	$	(4,642	)

	(Thousands)
Future cash inflows from sales of oil and gas	$	28,921
Future production and development costs		(17,042	)
Future asset retirement obligations, net of salvage		(17,639	)
Future income tax expense		(175	)
Future net cash flows		(5,935	)
Effect of discounting future net cash flows at 10% per annum		(44	)
Standardized measure of discounted future net cash flows	$	(5,979	)


	⁽¹⁾	See the Notes to the Consolidated Financial Statements for additional information.

Acreage. The Company had approximately 44,~~800~~700 gross developed acres and 29,~~400~~200 net developed acres as of December 31, ~~2024~~2025. Developed acreage is that acreage assignable to productive wells. The Company held no unproved acres at December 31, ~~2024~~2025.

Drilling Activity. The ~~Company was not involved in any drilling activities during 2024. The~~ following table sets forth the results of drilling activities during ~~2023~~2025. Such information and the results of prior drilling activities should not be considered as necessarily indicative of future activities. The Company was not involved in any drilling activities during 2024.

	Development Wells (1)
	Productive (2)				Dry (2)
	Gross		Net		Gross		Net
2023		4.00		0.02		-		-
2025		1.00		0.01		-		-

(1) All wells are located in the United States. All wells are development wells. No exploratory wells were drilled.

	⁽¹⁾	All wells are located in the United States. All wells are development wells. No exploratory wells were drilled.

	⁽²⁾	A productive well is any well that is not a dry well. A dry well is a well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil and gas well. Completion refers to installation of permanent equipment for production of oil and gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned. All wells drilled were completed during the fiscal year, regardless of when drilling was initiated.

(2) A productive well is any well that is not a dry well. A dry well is a well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil and gas well. Completion refers to installation of permanent equipment for production of oil and gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned. All wells drilled were completed during the fiscal year, regardless of when drilling was initiated.

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~~Table~~Present Activities. The Company has not participated in the drilling of ~~Contents~~any wells since December 31, 2025.

~~Present~~Delivery ~~Activities~~Commitments. The Company has ~~not~~entered ~~participated~~into invarious contracts with the ~~drilling~~Major ofGas ~~any~~Purchaser, which, subject to certain restrictions and adjustments, obligate the Major Gas Purchaser to purchase and the Company to sell and deliver all natural gas production from certain operated contract wells. ~~since~~These ~~December~~operated 31contract wells comprised approximately 78% of the Company’s consolidated natural gas sales during 2025. In addition, ~~2024~~the Company has entered into other various short-term contracts which obligate the purchasers to purchase and the Company to sell and deliver undetermined quantities of natural gas production on a monthly basis throughout the term of the contracts.

Delivery Commitments. The Company has entered into various contracts with the Major Gas Purchaser, which, subject to certain restrictions and adjustments, obligate the Major Gas Purchaser to purchase and the Company to sell and deliver all natural gas production from certain operated contract wells. These operated contract wells comprised approximately 69% of the Company’s consolidated natural gas sales during 2024. In addition, the Company has entered into other various short-term contracts which obligate the purchasers to purchase and the Company to sell and deliver undetermined quantities of natural gas production on a monthly basis throughout the term of the contracts.

Company Headquarters. The Company owns an approximately 6,400 square foot building located in Canfield, Ohio.

ITEM 3. LEGAL PROCEEDINGS

There are no material pending legal proceedings to which the Company is a party or to which any of its property is subject.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

SUPPLEMENTAL ITEM — INFORMATION ABOUT OUR EXECUTIVE OFFICERS

The executive officers of EEI and EMC as of March 10, ~~2025~~2026 are as follows: Brian A. Staebler, 5051, President and Principal Executive Officer and director; Michael W. Rathburn, 4142, Vice President, Secretary-Treasurer, Principal Financial and Accounting Officer and director; William A. Siskovic, 6970, Vice President and Principal Operations Officer, and Chairman of the Board of EEI. The executive officers of EEI and EMC have served their respective positions since March 2021.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market

There is currently no established public trading market for the Units. At the present time, the Company does not intend to list any of the Units for trading on any exchange or otherwise take any action to establish any market for the Units. As of March 10, ~~2025~~2026, there were 4,~~634~~610,~~720~~646 Units held by 1,~~085~~051 holders of record.

Distribution History

The Company commenced operations with the consummation of the Exchange Offer in February 1991. Management’s stated intention was to make quarterly cash distributions equal to $0.125 per Unit (or $0.50 per Unit on an annualized basis) for the first eight quarters following the closing date of the Exchange Offer. The Company paid a quarterly distribution every quarter from July 1991 through October 2015. The Company did not make a cash distribution from 2016 to 2018. The Company paid cash distributions in 2019 and in 2020. The Company did not make a cash distribution in 2021. The Company paid a cash distribution in 2022 and in 2023. The Company paid total cash distributions equal to $0.5020 per Unit in ~~2023~~2024. ~~and~~The Company did not make a cash distribution in 2025. The Company intends to make a cash distribution equal to $0.2050 per Unit in ~~2024~~April 2026.

Repurchase Right

The Partnership Agreement provides that beginning in 1992 and annually thereafter the Company offers to repurchase for cash up to 10% of the then outstanding Units, to the extent Holders offer Units to the Company for repurchase (the “Repurchase Right”). The Repurchase Right entitles any Holder(s), between May 1 and June 30 of each year, to notify the Company that the Holder(s) elects to exercise the Repurchase Right and have the Company acquire certain or all Units. The Company accepted an aggregate of ~~526~~141,~~433~~966 of its Units of limited partnership interest at a price of $61.3646 per Unit pursuant to the terms of the Company’s Offer to Purchase dated April 30, ~~2023~~2024. The Company accepted an aggregate of ~~141~~48,~~966~~148 of its Units of limited partnership interest at a price of $1.4632 per Unit pursuant to the terms of the Company’s Offer to Purchase dated April 30, ~~2024~~2025. The Company has determined that the price associated with the ~~2025~~2026 Repurchase Right, based upon the December 31, ~~2024~~2025 calculation, is estimated to be $1.3235 per Unit. See Note 3 in the Company’s consolidated financial statements for additional information on the Repurchase Right.

ITEM 6. [RESERVED]

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

General

The Company was organized in September 1990 as a limited partnership under the laws of the State of Delaware. Everflow Management Limited, LLC, an Ohio limited liability company, is the general partner of the Company. The Company was formed to engage in the business of oil and gas acquisition, exploration, development and production through a proposed consolidation of the business and oil and gas properties of EEI, and the oil and gas properties owned by certain limited partnerships and working interest programs managed or operated by the Programs.

Effective February 15, 1991, pursuant to the Exchange Offer to acquire the EEI shares and the Interests in exchange for Units of the Company’s limited partnership interest, the Company acquired the Interests and the EEI Shares and EEI became a wholly-owned subsidiary of the Company.

The General Partner is a limited liability company, Everflow Management Limited LLC (“EML”). The members of the General Partner are Everflow Management Corporation, an Ohio Corporation ("EMC"); three individuals who are officers and directors of EEI, Brian A. Staebler, Michael W. Rathburn and William A. Siskovic and one individual who is a director of EEI, Thomas L. Korner. Mr. Siskovic also serves as Chairman of the Board of EEI.

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Table of Contents

Liquidity and Capital Resources

Financial Position

The following table summarizes the Company’s financial position at December 31, ~~2024~~2025 and December 31, ~~2023~~2024:

	December 31, 2024					December 31, 2023
	December 31, 2025					December 31, 2024
	Amount		%			Amount		%
	(Amounts in Thousands)					(Amounts in Thousands)
Working capital	$	3438,~~858~~407		85	%	$	34,~~065~~858		8385	%
Property and equipment (net)		6,~~079~~327		1514			6,~~645~~079		1715
Other		~~268~~307		-1			~~241~~268		-
Total	$	4145,~~205~~041		100	%	$	4041,~~951~~205		100	%
Long-term liabilities	$	2022,~~870~~278		5149		$	1920,~~716~~870		4851
Partners' equity		2022,~~335~~763		4951			2120,~~235~~335		5249
Total	$	4145,~~205~~041		100	%	$	4041,~~951~~205		100	%

Working capital surplus of $3438.94 million as of December 31, ~~2024~~2025 represented an increase of $~~800,000~~3.5 million from December 31, ~~2023~~2024 due primarily to increases in investments and production accounts receivable, offset somewhat by ~~decreases~~a decrease in cash and equivalents and ~~other~~an ~~current~~increase ~~assets~~in accounts payable. The increase in investments is primarily the result of additional purchases of shares in a mutual fund that invests primarily in investment grade, short-term fixed and floating rate debt securities. The increase in production accounts receivable is the combined result of higher average natural gas prices received and aan ~~decrease~~increase in ~~production~~natural ~~costs~~gas ~~incurred~~volumes produced, offset somewhat by ~~lower~~an ~~crude~~increase ~~oil prices received and decreases~~ in ~~natural~~production ~~gas~~costs ~~volumes produced and crude oil volumes shipped~~incurred, during the current receivable period as compared to the prior comparable period. The ~~decreases~~increases in ~~production costs and~~ natural gas volumes produced isand production costs incurred are primarily the result of ~~additional~~fewer Company operated properties being voluntarily shut-in during the current receivable period ~~that~~as ~~were~~compared ~~otherwise~~to ~~producing during~~ the prior comparable receivable period. The decrease in cash and equivalents is primarily the result of cash used in investing ~~and financing~~ activities during ~~2024~~2025, offset somewhat by cash provided by operating activities. The ~~decrease~~increase in ~~other~~accounts ~~current~~payable ~~assets~~ is primarily the result of ~~refundable~~additional ~~Federal~~production ~~tax~~and ~~credits~~related ~~received~~other bypayables outstanding at December 31, 2025 as compared to the ~~Company~~prior incomparable ~~2024~~reporting date.

Long-term liabilities of $2022.93 million as of December 31, ~~2024~~2025 represented a $1.24 million increase from December 31, ~~2023~~2024 due primarily to accretion associated with asset retirement obligations, ~~and~~ additional operational advances collected during ~~2024~~2025 and revisions of cash flows measured at December 31, 2025.

Partner’s equity of $2022.38 million as of December 31, ~~2024~~2025 represented aan ~~decrease~~increase of $~~900,000~~2.5 million from December 31, ~~2023~~2024 due primarily to ~~a Unitholder distribution paid in April 2024 and the repurchase of limited partnership Units related to the 2024 Repurchase Right paid in July 2024, offset somewhat by~~ current year net income.

In ~~2023~~2024 and ~~2024~~2025, the Company had no new borrowings or credit facility with a bank. The Company expects to have adequate cash available to fund the Repurchase Right in ~~2025~~2026. As a result, additional financing will not likely be required in the event the Repurchase Right is fully subscribed. In the event that additional financing is necessary to fund the Repurchase Right, the Company would likely enter into a commitment for a new line of credit. The Company cannot provide any assurance as to the availability of any such line of credit under current market conditions. As further discussed below, the Company expects existing cash and equivalents and cash flows from ongoing operations to meet short-term cash requirements.

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Table of Contents

Cash Flows from Operating, Investing and Financing Activities

Cash provided by the Company’s operating activities and existing cash and equivalents were used in investing and financing activities during ~~2024~~2025 and ~~2023~~2024. The following table summarizes the Company’s Consolidated Statements of Cash Flows for the years ended December 31, ~~2024~~2025 and ~~2023~~2024:

	2024						2023
	2025						2024
	Dollars			%			Dollars			%
	(Amounts in Thousands)						(Amounts in Thousands)
Operating Activities:
Net income before adjustments	$	~~226~~2,460			954	%	$	~~222~~226			39	%
Adjustments		1,~~816~~500			7333			21,~~897~~816			3973
Cash flow from operations before working capital changes		23,~~042~~960			8287			32,~~119~~042			4282
Changes in working capital		85(253	)		3(5	)		~~655~~85			93
Net cash provided by operating activities		23,~~127~~707			8582			32,~~774~~127			5185
Investing Activities:
Purchase of investments		(13,~~409~~981	)		(5788	)		(1,~~212~~409	)		(1657	)
Purchase of property and equipment		(39344	)		(27	)		(~~363~~39	)		(52	)
Proceeds from disposal of property and equipment		8188			32			4181			13
Net cash used in investing activities		(14,~~367~~237	)		(5693	)		(1,~~534~~367	)		(2056	)
Financing Activities:
Distributions		~~(963~~-	)		~~(39~~-	)		(~~2,655~~963	)		(3639	)
Repurchase of Units		(~~207~~64	)		(82	)		(~~3,348~~207	)		(478	)
Proceeds from options exercised		4432			21			~~191~~44			32
Net cash used in financing activities		(~~1,126~~32	)		(451	)		(51,~~812~~126	)		(8045	)
Net change in cash and equivalents	$	(~~366~~562	)		(1612	)%	$	(~~3,572~~366	)		(4916	)%

Note: All items in the previous table are calculated as a percentage of total cash sources. Total cash sources include the following items, if positive: cash flow from operations before working capital changes, changes in working capital, net cash provided by investing activities and net cash provided by financing activities, plus any decrease in cash and equivalents.

As the above table indicates, the Company’s cash flow from operations before working capital changes of $2.0 million represented 82% of total cash sources provided during 2024, and the Company’s cash flow from operations before working capital changes of $3.1 million represented 42% of total cash sources provided during 2023. The decrease in cash flow from operations before working capital changes in 2024, as compared to the prior comparable period, was primarily due to less crude oil and natural gas sales during 2024 as compared to 2023. Changes in working capital other than cash and equivalents increased cash by $85,000 and $655,000 during 2024 and 2023, respectively. The $85,000 in cash provided by changes in working capital other than cash and equivalents in 2024 was primarily the result of a decrease in other current assets, offset somewhat by an increase in production accounts receivable. The decrease in other current assets is primarily related to the Company receiving refundable Federal tax credits during 2024. The increase in production accounts receivable is the combined result of higher average natural gas prices received and a decrease in production costs incurred, offset somewhat by lower crude oil prices received and decreases in natural gas volumes produced and crude oil volumes shipped, during the current receivable period as compared to the prior comparable period. The decreases in production costs and natural gas volumes produced are primarily the result of additional Company operated properties being voluntarily shut-in during the current receivable period that were otherwise producing during the prior comparable production period.

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~~Table~~As the above table indicates, the Company’s cash flow from operations before working capital changes of ~~Contents~~$4.0 million represented 87% of total cash sources provided during 2025, and the Company’s cash flow from operations before working capital changes of $2.0 million represented 82% of total cash sources provided during 2024. The increase in cash flow from operations before working capital changes in 2025, as compared to the prior comparable period, was primarily due to higher crude oil and natural gas sales during 2025 as compared to 2024. Changes in working capital other than cash and equivalents decreased cash by $253,000 during 2025 and increased cash by $85,000 during 2024. The $253,000 decrease in working capital other than cash and equivalents and non-cash items in 2025 was primarily the result of an increase in production accounts receivable, offset somewhat by an increase in accounts payable. The increase in production accounts receivable is the combined result of higher average natural gas prices received and an increase in natural gas volumes produced, offset somewhat by an increase in production costs incurred, during the current receivable period as compared to the prior comparable period. The increases in natural gas volumes produced and production costs incurred are primarily the result of fewer Company operated properties being voluntarily shut-in during the current receivable period as compared to the prior comparable receivable period. The increase in accounts payable is primarily the result of additional production and related other payables outstanding at December 31, 2025 as compared to the prior comparable reporting date.

The Company used cash in investing activities of $1.4.2 million and $1.54 million in ~~2024~~2025 and ~~2023~~2024, respectively. The ~~decrease~~increase in cash used in investing activities was primarily the result of ~~less~~additional cash used for purchases of investments and property and equipment in ~~2024~~2025, ~~offset somewhat by additional cash used for purchases of investments in 2024,~~ as compared to the prior comparable period.

The Company used cash in financing activities of $~~1.1~~32,000 ~~million~~ and $51.81 million in ~~2024~~2025 and ~~2023~~2024, respectively. The decrease in cash used in financing activities was primarily the result of ~~less~~no cash distributions paid to Unitholders in ~~2024~~2025 ~~as compared to the prior comparable period~~ and less cash used to repurchase Units in ~~2024~~2025 as compared to the prior comparable period.

The Company’s ending cash and equivalents balance of $98.27 million at December 31, ~~2024~~2025, as well as on-going monthly operating cash flows, should be adequate to meet short-term cash requirements, including the ~~2025~~2026 Repurchase Right.

The Company ~~did~~participated ~~not participate~~ in the drilling of ~~any~~one new oil and gas ~~properties~~property ~~during~~in ~~2024~~2025. The Company’s share of proved gas reserves ~~decreased~~increased by 15.90 BCF, or 2482%, between December 31, ~~2023~~2024 and December 31, ~~2024~~2025, while proved oil reserves ~~decreased~~increased by 351,000 BBLS, or 12less than 1%, between December 31, ~~2023~~2024 and December 31, ~~2024~~2025. The Standardized Measure of Discounted Future Net Cash Flows of the Company’s reserves ~~decreased~~increased by $21.23 million between December 31, ~~2023~~2024 and December 31, ~~2024~~2025. The primary reasons for this ~~decrease~~increase were due to aan ~~decrease~~increase in average ~~crude~~natural ~~oil~~gas prices and ~~increase~~decrease in ~~average~~ lease operating expenses in ~~2024~~2025, as compared to the prior comparable period, and the related ~~downward~~upward revisions in quantities of natural gas and crude oil reserves between December 31, ~~2023~~2024 and ~~2024~~2025.

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~~Table~~The Partnership Agreement provides that the Company annually offers to repurchase for cash up to 10% of ~~Contents~~the then outstanding Units, to the extent Unitholders offer Units to the Company for repurchase pursuant to the Repurchase Right. The Repurchase Right entitles any Unitholder, between May 1 and June 30 of each year, to notify the Company of his or her election to exercise the Repurchase Right and have the Company acquire such Units. The price to be paid for any such Units will be calculated based upon the audited financial statements of the Company as of December 31 of the year prior to the year in which the Repurchase Right is to be effective and independently prepared reserve reports. The price per Unit will be equal to 66% of the adjusted book value of the Company allocable to the Units, divided by the number of Units outstanding at the beginning of the year in which the applicable Repurchase Right is to be effective less all Interim Cash Distributions received by a Unitholder. The adjusted book value is calculated by adding partner’s equity, the Standardized Measure of Discounted Future Net Cash Flows and the tax effect included in the Standardized Measure and subtracting from that sum the carrying value of oil and gas properties, net of undeveloped lease costs. If more than 10% of the then outstanding Units are tendered during any period during which the Repurchase Right is to be effective, the Investor’s Units so tendered shall be prorated for purposes of calculating the actual number of Units to be acquired during any such period. The Company accepted an aggregate of 141,966 of its Units of limited partnership interest at a price of $1.46 per Unit pursuant to the terms of the Company’s Offer to Purchase dated April 30, 2024. The Company accepted an aggregate of 48,148 of its Units of limited partnership interest at a price of $1.32 per Unit pursuant to the terms of the Company’s Offer to Purchase dated April 30, 2025. The Company has determined that the price associated with the 2026 Repurchase Right, based upon the December 31, 2025 calculation, is estimated to be $1.35 per Unit, net of a $0.50 per Unit distribution expected to be made in April 2026.

The Partnership Agreement provides that the Company annually offers to repurchase for cash up to 10% of the then outstanding Units, to the extent Unitholders offer Units to the Company for repurchase pursuant to the Repurchase Right. The Repurchase Right entitles any Unitholder, between May 1 and June 30 of each year, to notify the Company of his or her election to exercise the Repurchase Right and have the Company acquire such Units. The price to be paid for any such Units will be calculated based upon the audited financial statements of the Company as of December 31 of the year prior to the year in which the Repurchase Right is to be effective and independently prepared reserve reports. The price per Unit will be equal to 66% of the adjusted book value of the Company allocable to the Units, divided by the number of Units outstanding at the beginning of the year in which the applicable Repurchase Right is to be effective less all Interim Cash Distributions received by a Unitholder. The adjusted book value is calculated by adding partner’s equity, the Standardized Measure of Discounted Future Net Cash Flows and the tax effect included in the Standardized Measure and subtracting from that sum the carrying value of oil and gas properties, net of undeveloped lease costs. If more than 10% of the then outstanding Units are tendered during any period during which the Repurchase Right is to be effective, the Investor’s Units so tendered shall be prorated for purposes of calculating the actual number of Units to be acquired during any such period. The Company accepted an aggregate of 526,433 of its Units of limited partnership interest at a price of $6.36 per Unit pursuant to the terms of the Company’s Offer to Purchase dated April 30, 2023. The Company accepted an aggregate of 141,966 of its Units of limited partnership interest at a price of $1.46 per Unit pursuant to the terms of the Company’s Offer to Purchase dated April 30, 2024. The Company has determined that the price associated with the 2025 Repurchase Right, based upon the December 31, 2024 calculation, is estimated to be $1.32 per Unit.

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Table of Contents

Results of Operations

The following table and discussion is a review of the results of operations of the Company for the years ended December 31, ~~2024~~2025 and ~~2023~~2024. All items in the table are calculated as a percentage of total revenues. This table should be read in conjunction with the discussions of each item below:

	Year Ended December 31,
	2024			2023
	2025			2024
Revenues:
Crude oil and natural gas sales		9293	%		9392	%
Well management and operating and other		87			78
Total revenues		100			100
Expenses:
Production costs		4636			3846
Well management and operating		4			54
Depreciation, depletion and amortization		95			279
Accretion expense		2313			2023
General and administrative expense		4932			4049
Total expenses		~~131~~90			~~130~~131
Other income:
Investment income		3523			2535
Gain on disposal of property and equipment		12			1
Other income		-			8
Total other income		25			36
Total other income		36			34
Net income		35	%		5	%
Net income		5	%		4	%

Revenues for the year ended December 31, ~~2024~~2025 ~~decreased~~increased $12.01 million, or 1742%, compared to the prior comparable period. This ~~decrease~~increase was due primarily to an ~~decrease~~increase in crude oil and natural gas sales during ~~2024~~2025 as compared to ~~2023~~2024.

Crude oil and natural gas sales ~~decreased~~increased $~~939~~2.0 million,~~000,~~ or 1744%, from ~~2023~~2024 to ~~2024~~2025. This ~~decrease~~increase was due primarily to ~~lower~~higher average natural gas ~~and crude oil~~ prices received and ~~less~~additional natural gas ~~and~~volumes produced during 2025 as compared to 2024, offset somewhat by lower average crude oil ~~volumes~~prices ~~produced~~received during ~~2024~~2025 as compared to ~~2023~~2024. The Company’s natural gas production ~~decreased~~increased by ~~149~~357,000 MCF, or 1233%. The primary reason for the ~~decrease~~increase in natural gas volumes produced during ~~2024~~2025 as compared to ~~2023~~2024 was a result of ~~more~~fewer Company operated oil and gas properties being voluntarily shut-in during ~~2024~~2025 as compared to the prior comparable period. The ~~primary reason for the decrease in crude oil volumes produced during 2024 as compared to 2023 was the result of normal production decline associated with existing oil and gas properties. The~~ average price received per MCF of natural gas ~~decreased~~increased from $2.4915 in ~~2023~~2024 to $23.1528 in ~~2024~~2025. The average price received per BBL of crude oil decreased from $7472.2937 in ~~2023~~2024 to $7261.3757 in ~~2024~~2025. Natural gas sales accounted for 5171% and 5551% of total crude oil and natural gas sales in ~~2024~~2025 and ~~2023~~2024, respectively.

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~~Table~~Accretion expense decreased $210,000, or 19%, from 2024 to 2025. The decrease was primarily the result of ~~Contents~~more asset retirement obligations being fully accreted at January 1, 2025 as compared to January 1, 2024, which resulted in less discounted asset retirement obligations available to accrete during 2025 as compared to 2024.

~~Depreciation,~~The ~~depletion~~Company ~~and~~reported ~~amortization~~net ~~decreased~~income of $12.15 million, ~~or 71% from 2023 to 2024. The decrease is primarily the result of decreases in crude oil~~ and ~~natural~~$226,000 ~~gas~~during ~~volumes~~2025 ~~produced~~ and ~~the Company’s oil and gas properties having less depletable basis available in~~ 2024 ~~as compared to the prior comparable period offset somewhat by a decrease in natural gas and crude oil reserves as of the most recent valuation date~~, ~~December 31~~respectively, ~~2024,~~representing as35% ~~compared to the prior valuation date, December 31, 2023. The decrease in crude oil~~ and ~~natural~~5% ~~gas~~of ~~volumes~~total ~~produced~~revenues during ~~2024~~2025 as compared the prior comparable period was primarily due to additional Company operated properties being voluntarily shut-in during 2024 that were not shut-in during the prior comparable period as well as normal production decline associated with existing oil and ~~gas properties. The decreased natural gas and crude oil reserves from 2023 to~~ 2024 ~~was primarily the result of lower crude oil prices and higher production costs used to value reserves at December 31~~, ~~2024 as compared to the prior valuation date~~respectively. ~~The lower crude oil prices and higher production costs contributed to decreasing the average economic life of the Company’s oil and gas properties as compared to their prior valuation date.~~

Investment income increased $245,000, or 16% from 2023 to 2024. The increase is primarily due to higher average investment balances held and higher dividend rates yielded on investments during 2024 as compared to 2023.

The Company did not have any other income during 2024. During 2023, other income included the ERC refund applied for by the Company.

The Company reported net income of $226,000 and $222,000 during 2024 and 2023, respectively, representing 5% and 4% of total revenues during 2024 and 2023, respectively.

Application of Critical Accounting Policies

Property and Equipment. The Company uses the successful efforts method of accounting for oil and gas exploration and production activities. Under successful efforts, costs to acquire mineral interests in oil and gas properties and to drill and equip development wells are initially capitalized. Costs of development wells (on properties the Company has no further interest in) that do not find proved reserves and geological and geophysical costs are expensed. The Company has not participated in exploratory drilling and owns no interest in unproved properties.

Capitalized costs of proved properties, after considering estimated dismantlement and abandonment costs and estimated salvage values, are amortized by the unit-of-production method based upon estimated proved developed reserves. Depletion, depreciation and amortization on proved properties amounted to $~~390~~307,000 and $~~1.5~~390,000 ~~million~~ during ~~2024~~2025 and ~~2023~~2024, respectively.

On sale or retirement of a unit of a proved property (which generally constitutes the amortization base), the cost and related accumulated depreciation, depletion, amortization and write down are eliminated from the property accounts, and the resultant gain or loss is recognized.

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Table of Contents

The Company evaluates its crude oil and natural gas properties for impairment annually. Generally accepted accounting principles require that long-lived assets (including crude oil and natural gas properties) and certain identifiable intangibles be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The Company utilizes a field by field basis for assessing impairment of its oil and gas properties.

Management of the Company believes that the accounting estimate related to crude oil and natural gas property impairment is a “critical accounting estimate” because it is highly susceptible to change from year to year. It requires the use of crude oil and natural gas reserve estimates that are directly impacted by future crude oil and natural gas prices and future production volumes. Actual crude oil and natural gas prices have fluctuated in the past and are likely to do so in the future.

Crude oil and natural gas reserve estimates are prepared annually based on existing contractual arrangements and current market conditions. Any increases in estimated future cash flows would have no impact on the reported value of the Company’s crude oil and natural gas properties. In contrast, decreases in estimated future cash flows could require the recognition of an impairment loss equal to the difference between the estimated fair value of the crude oil and natural gas properties (determined by calculating the discounted value of the estimated future cash flows) and the carrying amount of the crude oil and natural gas properties. Any impairment loss would reduce property and equipment as well as total assets of the Company. An impairment loss would also decrease net income or increase net loss. The Company did not recognize any impairment during ~~2024~~2025 or ~~2023~~2024.

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Asset Retirement Obligations. The Company follows generally accepted accounting principles which require the fair value of a liability for an asset retirement obligation to be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. For the Company, these obligations include dismantlement, plugging and abandonment of crude oil and natural gas wells and associated pipelines and equipment. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depleted over the estimated useful life of the related asset.

The estimated liability is based on historical experience in dismantling, plugging and abandoning wells, estimated remaining lives of those wells based on reserves estimates, estimates of the external cost to dismantle, plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability will likely occur due to: changes in estimates of dismantlement, plugging and abandonment costs; changes in estimated remaining lives of the wells; changes in federal or state regulations regarding dismantlement, plugging and abandonment requirements; and other factors. At December 31, 2025, the Company made a revision in the estimate of dismantlement, plugging and abandonment costs. The revision increased the liability by $417,000 at December 31, 2025.

The Company has no assets legally restricted for purposes of settling its asset retirement obligations. The Company has determined that there are no other material retirement obligations associated with tangible long-lived assets.

Revenue Recognition. The Company recognizes crude oil and natural gas revenues when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred, title and risk of loss have transferred to the purchaser, and collectability of the revenue is reasonably assured. The Company utilizes the sales method to account for gas production volume imbalances. Under this method, revenue is recognized only when gas is produced and sold on the Company’s behalf. The Company had no material gas imbalances at December 31, ~~2024~~2025 or ~~2023~~2024. Other revenues consist of miscellaneous revenues that are recognized at the time services are rendered, the Company has a contractual right to such revenue and collection is reasonably assured.

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Table of Contents

The Company participates (and may act as drilling contractor) with unaffiliated joint venture partners and employees in the drilling, development and operation of jointly owned crude oil and natural gas properties. Each owner, including the Company, has an undivided interest in the jointly owned properties. Generally, the joint venture partners and employees participate on the same drilling/development cost basis as the Company and, therefore, no revenue, expense or income is recognized on the drilling and development of the properties. The Company receives reimbursement of administrative costs associated with preparation, drilling and development of jointly owned crude oil and natural gas properties from certain joint venture partners. Accounts receivable from joint venture partners, if applicable, consist principally of drilling and development costs the Company has advanced or incurred on behalf of joint venture partners. Accounts payable to joint venture partners consist principally of deposits received from joint venture partners for drilling and development costs. The Company earns and receives monthly management and operating fees from certain joint venture partners and employees after the properties are completed and placed into production.

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Commodity Pricing, Risk Management Activities and Inflation

The Company’s revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and crude oil. Declines in oil and gas prices may have a material adverse effect on the Company’s financial condition, liquidity, ability to obtain financing and operating results. Lower oil and gas prices also may reduce the amount of oil and gas that the Company can produce economically. Historically, oil and gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Depressed prices in the future would have a negative impact on the Company’s future financial results. In particular, substantially lower prices would significantly reduce revenue, potentially increase depletion, depreciation and amortization and potentially trigger impairment under generally accepted accounting principles.

The majority of the Company’s production is sold at market responsive prices. Generally, if the related commodity index falls, the price received for the Company’s production will also decline. Therefore, the amount of revenue the Company realizes is partially determined by factors beyond the Company’s control. However, management has in recent years and may in the future mitigate this price risk on a portion of the Company’s anticipated production by shutting-in wells during certain periods of depressed natural gas prices in an attempt to hold production for the future when natural gas prices have recovered. Under this arrangement, there is also a risk that natural gas prices will not recover and that the production of future volumes will be sold at the same depressed or potentially further depressed natural gas prices.

While the cost of operations is impacted by inflation, crude oil and natural gas prices have fluctuated in recent years and generally have not matched inflation. The price of crude oil in the Appalachian Basin has ranged from a low of $8.50 per barrel in December 1998 to a high of $138.00 in July 2008. As of March 10, ~~2025~~2026, $6279.0345 per barrel was the prevailing field price in the Appalachian Basin area, the Company’s principal area of operation.

Natural gas prices have also fluctuated more recently. The Company’s average price of natural gas during 2025 was $3.28 per MCF, an increase of $1.13 per MCF as compared to 2024. The Company’s average price of natural gas during 2024 was $2.15 per MCF, a decrease of $0.34 per MCF as compared to 2023. The Company’s average price of natural gas during 2023 was $2.49 per MCF, a decrease of $3.17 per MCF as compared to 2022. The Company’s average price of natural gas during 2022 was $5.66 per MCF, an increase of $2.38 as compared to 2021. The price of natural gas in the Appalachian Basin increased significantly throughout 2005 and reached a high of more than $14.00 per MCF in October and November 2005. More recently, the price for Henry Hub Natural Gas on the NYMEX settled for the month of March 2026 at $2.97 per MCF and the regional basis adjustment settled for the month of March 2026 at $(0.62) per MCF, resulting in a net regional market price of $2.35 per MCF. Since 2002, the Company has had and continues to have multiple annual or biennial contracts with various purchasers of natural gas, which obligate certain purchasers to purchase, and the Company to sell and deliver, certain quantities of natural gas production from the Company’s oil and gas properties throughout the contract periods. Per the terms of one of the Company’s contracts with a gas purchaser, the Company may elect to lock-in specific volumes of natural gas to be sold in specific months at a mutually agreeable price. As of March 10, 2026, the Company has elected to lock-in 1,170,000 MCF from January 2026 to April 2027 at a weighted average price of $3.40 per MCF, net of regional basis adjustments.

- 24 -

~~Table~~The Company’s sales are significantly impacted by pricing instability in the crude oil and natural gas markets. One of ~~Contents~~the consequences of these pricing fluctuations is evident in the Company’s Standardized Measure of Discounted Future Net Cash Flows, decreasing from $4.4 million at December 31, 2018 to $(2.5) million at December 31, 2019, decreasing to $(8.6) million at December 31, 2020, increasing to $6.8 million at December 31, 2021, increasing to $34.6 million at December 31, 2022, decreasing to $(3.7) million at December 31, 2023, decreasing to $(6.0) million at December 31, 2024 and increasing to $(4.6) million at December 31, 2025.

~~Natural gas prices have also fluctuated more recently.~~ The Company’s ~~average~~Standardized ~~price~~Measure of ~~natural~~Discounted ~~gas~~Future ~~during~~Net ~~2024~~Cash ~~was~~Flows ~~$2.15~~increased ~~per~~by ~~MCF, a decrease of~~ $01.~~34 per MCF as compared to 2023. The Company’s average price of natural gas during 2023 was $2.49 per MCF, a decrease of $~~3~~.17~~ ~~per~~million ~~MCF~~from asDecember ~~compared to 2022. The Company’s average price of natural gas during 2022 was $5.66 per MCF~~31, an2024 ~~increase of $2.38 as compared~~ to ~~2021.~~December ~~The Company’s average price of natural gas during 2021 was $3.28 per MCF~~31, ~~an increase of $1~~2025.43 ~~per~~A ~~MCF~~reconciliation ~~as compared to 2020. The price~~ of ~~natural gas in~~ the ~~Appalachian~~Changes ~~Basin increased significantly throughout 2005 and reached a high of more than $14.00 per MCF~~ in ~~October and November 2005. More recently,~~ the ~~price~~Standardized ~~for~~Measure ~~Henry Hub Natural Gas on the NYMEX settled for the month~~ of ~~March~~Discounted ~~2025~~Future atNet ~~$3.91~~Cash ~~per~~Flows ~~MCF~~is ~~and~~included ~~the regional basis adjustment settled for the month of March 2025 at $(0.41) per MCF, resulting~~ in ~~a net regional market price of $3.50 per MCF. Since 2002,~~ the Company has had and continues to have multiple annual or biennial contracts with various purchasers of natural gas, which obligate certain purchasers to purchase, and the Company to sell and deliver, certain quantities of natural gas production from the Company’s ~~oil~~consolidated ~~and~~financial ~~gas properties throughout the contract periods~~statements. Per the terms of one of the Company’s contracts with a gas purchaser, the Company may elect to lock-in specific volumes of natural gas to be sold in specific months at a mutually agreeable price. As of March 10, 2025, the Company has elected to lock-in 1,200,000 MCF from March 2025 to April 2027 at a weighted average price of $3.34 per MCF, net of regional basis adjustments.

The Company’s sales are significantly impacted by pricing instability in the crude oil and natural gas markets. One of the consequences of these pricing fluctuations is evident in the Company’s Standardized Measure of Discounted Future Net Cash Flows, increasing from $(5.1) million at December 31, 2017 to $4.4 million at December 31, 2018, decreasing to $(2.5) million at December 31, 2019, decreasing to $(8.6) million at December 31, 2020, increasing to $6.8 million at December 31, 2021, increasing to $34.6 million at December 31, 2022, decreasing to $(3.7) million at December 31, 2023 and decreasing to $(6.0) million at December 31, 2024.

The Company’s Standardized Measure of Discounted Future Net Cash Flows decreased by $2.2 million from December 31, 2023 to December 31, 2024. A reconciliation of the Changes in the Standardized Measure of Discounted Future Net Cash Flows is included in the Company’s consolidated financial statements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not a required disclosure for a Smaller Reporting Company.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

See attached pages F-1 to F-23.

- 25 -

Table of Contents

EVERFLOW EASTERN PARTNERS, L. P.

~~2024~~2025 CONSOLIDATED FINANCIAL REPORT

F-1

Table of Contents

EVERFLOW EASTERN PARTNERS, L. P.

CONTENTS


	Page

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM	F-3

FINANCIAL STATEMENTS
Consolidated balance sheets	F-5
Consolidated statements of operations	F-7
Consolidated statements of partners' equity	F-8
Consolidated statements of cash flows	F-9
Notes to consolidated financial statements	F-10

F-2

Table of Contents

Report of Independent Registered Public Accounting Firm

To the Partners

Everflow Eastern Partners, L. P.

Canfield, Ohio

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Everflow Eastern Partners, L. P. and subsidiaries (the "Company") as of December 31, ~~2024~~2025 and ~~2023~~2024, and the related consolidated statements of operations, partners' equity, and cash flows for the years then ended and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Company as of December 31, ~~2024~~2025 and ~~2023~~2024, and the consolidated results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

Basis of Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

F-3

Table of Contents

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing separate opinions on the critical audit matter or on the accounts or disclosures to which it relates.

Accounting for Asset Retirement Obligations

Description of the Matter

At December 31, ~~2024~~2025, asset retirement obligations ("ARO") totaled approximately, $1819 million. As further described in Note 1G, the Company’s ARO reflects the estimated present value of its obligations, for dismantlement, plugging and abandonment of crude oil and natural gas wells and associated pipelines and equipment. The estimation of the ARO requires significant judgment given the magnitude of the expected retirement costs and higher estimation uncertainty related to the timing of settlements and settlement amounts. Auditing the Company’s ARO is complex and highly judgmental because of the significant estimation required by management in determining the obligation. In particular, the estimate was sensitive to significant subjective assumptions such as retirement cost estimates and the estimated timing of settlements, which are both affected by expectations about future market and economic conditions.

How We Addressed the Matter in Our Audit

We obtained an understanding of the Company’s internal controls over its ARO estimation process, including management’s review of the significant assumptions that have a material effect on the determination of the obligations. To test the ARO, our audit procedures included, among others, assessing the significant assumptions and inputs used in the valuation, such as retirement cost estimates and timing of settlement assumptions. For example, we evaluated retirement cost estimates by comparing the Company’s estimates to its recent costs to retire wells. Additionally, we compared assumptions for the timing of settlements to production forecasts and tested the mathematical accuracy of the ARO calculations.

/s/ Maloney + Novotny LLC

We have served as the Company's auditor since 1988.

Cleveland, Ohio

March 2526, ~~2025~~2026

F-4

~~Table~~EVERFLOW ofEASTERN ~~Contents~~PARTNERS, L. P. CONSOLIDATED BALANCE SHEETS December 31, 2025 and 2024

EVERFLOW EASTERN PARTNERS, L. P. CONSOLIDATED BALANCE SHEETS December 31, 2024 and 2023

	2025		2024
ASSETS

CURRENT ASSETS
Cash and equivalents	$	8,657,066	$	9,219,826
Investments		32,506,083		28,402,617
Production accounts receivable		1,228,476		918,745
Other		31,364		28,060
Total current assets		42,422,989		38,569,248

PROPERTY AND EQUIPMENT
Proved properties (successful efforts accounting method)		133,787,643		134,156,537
Pipeline and support equipment		656,630		617,217
Corporate and other		2,175,101		2,156,948
Gross property and equipment		136,619,374		136,930,702
Less accumulated depreciation, depletion, amortization and write down		130,292,651		130,851,814
Net property and equipment		6,326,723		6,078,888

OTHER ASSETS		307,302		267,575

TOTAL ASSETS	$	49,057,014	$	44,915,711

	2024		2023
ASSETS
CURRENT ASSETS
Cash and equivalents	$	9,219,826	$	9,586,524
Investments		28,402,617		26,965,697
Production accounts receivable		918,745		790,547
Other		28,060		510,861
Total current assets		38,569,248		37,853,629
PROPERTY AND EQUIPMENT
Proved properties (successful efforts accounting method)		134,156,537		135,663,041
Pipeline and support equipment		617,217		617,217
Corporate and other		2,156,948		2,131,815
Gross property and equipment		136,930,702		138,412,073
Less accumulated depreciation, depletion, amortization and write down		130,851,814		131,767,001
Net property and equipment		6,078,888		6,645,072
OTHER ASSETS		267,575		241,178
TOTAL ASSETS	$	44,915,711	$	44,739,879

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

F-5

~~Table~~EVERFLOW ofEASTERN ~~Contents~~PARTNERS, L. P. CONSOLIDATED BALANCE SHEETS December 31, 2025 and 2024

EVERFLOW EASTERN PARTNERS, L. P. CONSOLIDATED BALANCE SHEETS December 31, 2024 and 2023

	2025		2024
LIABILITIES AND PARTNERS' EQUITY

CURRENT LIABILITIES
Accounts payable	$	2,984,192	$	2,714,240
Accrued expenses		1,031,477		997,093
Total current liabilities		4,015,669		3,711,333

OPERATIONAL ADVANCES		3,538,740		3,287,702

ASSET RETIREMENT OBLIGATIONS		18,740,023		17,581,892

COMMITMENTS AND CONTINGENCIES

LIMITED PARTNERS' EQUITY, SUBJECT TO REPURCHASE RIGHT
Authorized - 8,000,000 Units Issued and outstanding - 4,610,646 and 4,634,720 Units, respectively		22,436,073		20,044,593

GENERAL PARTNER'S EQUITY		326,509		290,191
Total partners' equity		22,762,582		20,334,784


TOTAL LIABILITIES AND PARTNERS' EQUITY	$	49,057,014	$	44,915,711

	2024		2023
LIABILITIES AND PARTNERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$	2,714,240	$	2,776,546
Accrued expenses		997,093		1,011,724
Total current liabilities		3,711,333		3,788,270
OPERATIONAL ADVANCES		3,287,702		3,064,191
ASSET RETIREMENT OBLIGATIONS		17,581,892		16,652,494
COMMITMENTS AND CONTINGENCIES		-		-
LIMITED PARTNERS' EQUITY, SUBJECT TO REPURCHASE RIGHT
Authorized - 8,000,000 Units Issued and outstanding - 4,634,720 and 4,746,686 Units, respectively		20,044,593		20,938,936
GENERAL PARTNER'S EQUITY		290,191		295,988
Total partners' equity		20,334,784		21,234,924
TOTAL LIABILITIES AND PARTNERS' EQUITY	$	44,915,711	$	44,739,879

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

F-6

~~Table~~EVERFLOW ofEASTERN ~~Contents~~PARTNERS, L.P. CONSOLIDATED STATEMENTS OF OPERATIONS Years Ended December 31, 2025 and 2024

EVERFLOW EASTERN PARTNERS, L.P. CONSOLIDATED STATEMENTS OF OPERATIONS Years Ended December 31, 2024 and 2023

	2025			2024
REVENUES
Crude oil and natural gas sales	$	6,558,645		$	4,562,324
Well management and operating		482,082			390,021
Other		1,377			3,013
Total revenues		7,042,104			4,955,358

DIRECT COST OF REVENUES
Production costs		2,516,886			2,297,314
Well management and operating		289,899			234,579
Depreciation, depletion and amortization		374,591			466,778
Accretion expense		920,663			1,130,918
Total direct cost of revenues		4,102,039			4,129,589

GENERAL AND ADMINISTRATIVE EXPENSE		2,232,173			2,417,933
Total cost of revenues		6,334,212			6,547,522


INCOME (LOSS) FROM OPERATIONS		707,892			(1,592,164	)

OTHER INCOME
Investment income		1,635,559			1,733,909
Gain on disposal of property and equipment		102,922			70,542
Total other income		1,738,481			1,804,451

INCOME BEFORE INCOME TAXES		2,446,373			212,287

INCOME TAX EXPENSE (BENEFIT)
Current		67,798			-
Deferred		(81,000	)		(13,800	)
Total income tax benefit		(13,202	)		(13,800	)

NET INCOME	$	2,459,575		$	226,087


Allocation of Partnership Net Income:
Limited Partners	$	2,424,385		$	222,899
General Partner		35,190			3,188

Net income	$	2,459,575		$	226,087


Net income per Unit	$	0.52		$	0.05

	2024			2023
REVENUES
Crude oil and natural gas sales	$	4,562,324		$	5,500,946
Well management and operating		390,021			441,694
Other		3,013			3,503
Total revenues		4,955,358			5,946,143
DIRECT COST OF REVENUES
Production costs		2,297,314			2,273,596
Well management and operating		234,579			265,145
Depreciation, depletion and amortization		466,778			1,589,887
Accretion expense		1,130,918			1,184,585
Total direct cost of revenues		4,129,589			5,313,213
GENERAL AND ADMINISTRATIVE EXPENSE		2,417,933			2,394,282
Total cost of revenues		6,547,522			7,707,495
LOSS FROM OPERATIONS		(1,592,164	)		(1,761,352	)
OTHER INCOME
Investment income		1,733,909			1,488,441
Gain on disposal of property and equipment		70,542			32,702
Other income		-			481,937
Total other income		1,804,451			2,003,080
INCOME BEFORE INCOME TAXES		212,287			241,728
INCOME TAX EXPENSE (BENEFIT)
Current		-			20,900
Deferred		(13,800	)		(1,000	)
Total income tax expense (benefit)		(13,800	)		19,900
NET INCOME	$	226,087		$	221,828
Allocation of Partnership Net Income:
Limited Partners	$	222,899		$	218,888
General Partner		3,188			2,940
Net income	$	226,087		$	221,828
Net income per Unit	$	0.05		$	0.04

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

F-7

~~Table~~EVERFLOW ofEASTERN ~~Contents~~PARTNERS, L.P. CONSOLIDATED STATEMENTS OF PARTNERS' EQUITY Years Ended December 31, 2025 and 2024

EVERFLOW EASTERN PARTNERS, L.P. CONSOLIDATED STATEMENTS OF PARTNERS' EQUITY Years Ended December 31, 2024 and 2023

	2025			2024


PARTNERS' EQUITY – BEGINNING OF YEAR	$	20,334,784		$	21,234,924

Net income		2,459,575			226,087

Cash distributions ($0.20 per Unit in 2024)		-			(962,757	)

Repurchase of Units		(63,555	)		(207,270	)

Options exercised		31,778			43,800


PARTNERS' EQUITY – END OF YEAR	$	22,762,582		$	20,334,784

	2024			2023
PARTNERS' EQUITY – BEGINNING OF YEAR	$	21,234,924		$	26,825,519
Net income		226,087			221,828
Cash distributions ($0.20 and $0.50 per Unit in 2024 and 2023, respectively)		(962,757	)		(2,655,109	)
Repurchase of Units		(207,270	)		(3,348,114	)
Options exercised		43,800			190,800
PARTNERS' EQUITY – END OF YEAR	$	20,334,784		$	21,234,924

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

F-8

~~Table~~EVERFLOW ofEASTERN ~~Contents~~PARTNERS, L.P. CONSOLIDATED STATEMENTS OF CASH FLOWS Years Ended December 31, 2025 and 2024

EVERFLOW EASTERN PARTNERS, L.P. CONSOLIDATED STATEMENTS OF CASH FLOWS Years Ended December 31, 2024 and 2023

	2025			2024
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	2,459,575		$	226,087
Adjustments to reconcile to net cash provided by operating activities:
Depreciation, depletion and amortization		470,687			558,011
Accretion expense		920,663			1,130,918
Unrealized gain on investments		(122,554	)		(27,553	)
Gain on disposal of property and equipment		(102,922	)		(70,542	)
Deferred income taxes		(81,000	)		(13,800	)
Changes in assets and liabilities:
Production accounts receivable		(309,731	)		(128,198	)
Other current assets		(3,304	)		482,801
Other assets		41,273			(12,597	)
Accounts payable		269,952			(62,306	)
Accrued expenses		(87,522	)		(179,794	)
Operational advances		251,038			223,511
Total adjustments		1,246,580			1,900,451
Net cash provided by operating activities		3,706,155			2,126,538

CASH FLOWS FROM INVESTING ACTIVITIES
Purchase of investments		(3,980,912	)		(1,409,367	)
Purchase of property and equipment		(344,085	)		(38,713	)
Proceeds from disposal of property and equipment		87,859			81,071
Net cash used in investing activities		(4,237,138	)		(1,367,009	)

CASH FLOWS FROM FINANCING ACTIVITIES
Distributions		-			(962,757	)
Repurchase of Units		(63,555	)		(207,270	)
Proceeds from options exercised		31,778			43,800
Net cash used in financing activities		(31,777	)		(1,126,227	)

NET CHANGE IN CASH AND EQUIVALENTS		(562,760	)		(366,698	)

CASH AND EQUIVALENTS AT BEGINNING OF YEAR		9,219,826			9,586,524

CASH AND EQUIVALENTS AT END OF YEAR	$	8,657,066		$	9,219,826

	2024			2023
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	226,087		$	221,828
Adjustments to reconcile to net cash provided by operating activities:
Depreciation, depletion and amortization		558,011			1,673,892
Accretion expense		1,130,918			1,184,585
Unrealized gain on investments		(27,553	)		(81,051	)
Gain on disposal of property and equipment		(70,542	)		(32,702	)
Deferred income taxes		(13,800	)		(1,000	)
Changes in assets and liabilities:
Production accounts receivable		(128,198	)		1,247,980
Other current assets		482,801			(458,066	)
Other assets		(12,597	)		14,345
Accounts payable		(62,306	)		84,629
Accrued expenses		(179,794	)		(138,531	)
Operational advances		223,511			58,084
Total adjustments		1,900,451			3,552,165
Net cash provided by operating activities		2,126,538			3,773,993
CASH FLOWS FROM INVESTING ACTIVITIES
Purchase of investments		(1,409,367	)		(1,211,377	)
Purchase of property and equipment		(38,713	)		(363,276	)
Proceeds from disposal of property and equipment		81,071			40,570
Net cash used in investing activities		(1,367,009	)		(1,534,083	)
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions		(962,757	)		(2,655,109	)
Repurchase of Units		(207,270	)		(3,348,114	)
Proceeds from options exercised		43,800			190,800
Net cash used in financing activities		(1,126,227	)		(5,812,423	)
NET CHANGE IN CASH AND EQUIVALENTS		(366,698	)		(3,572,513	)
CASH AND EQUIVALENTS AT BEGINNING OF YEAR		9,586,524			13,159,037
CASH AND EQUIVALENTS AT END OF YEAR	$	9,219,826		$	9,586,524

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

F-9

~~Table~~EVERFLOW ofEASTERN ~~Contents~~PARTNERS, L. P.

EVERFLOW EASTERN PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1.

Organization and Summary of Significant Accounting Policies

Organization and Principles of Consolidation – Everflow Eastern Partners, L.P. ("Everflow") is a Delaware limited partnership which was organized in September 1990 to engage in the business of oil and gas acquisition, exploration, development and production. Everflow was formed to consolidate the business and crude oil and natural gas properties of Everflow Eastern, Inc. ("EEI") and subsidiaries and the crude oil and natural gas properties owned by certain limited partnership and working interest programs managed or sponsored by EEI ("EEI Programs" or the "Programs").

Everflow Management Limited, LLC ("EML"), an Ohio limited liability company, is the general partner of Everflow and, as such, is authorized to perform all acts necessary or desirable to carry out the purposes and conduct of the business of Everflow. At December 31, ~~2024~~2025, the members of EML include Everflow Management Corporation ("EMC"); three individuals who are officers and directors of EEI, which includes the Chairman of the Board of EEI, and one individual who is a director of EEI. EMC is an Ohio corporation formed in September 1990 and is the managing member of EML. EML holds no assets other than its general partner's interest in Everflow, nor does it have any liabilities. In addition, EML has no separate operations or role apart from its role as Everflow's general partner.

The consolidated financial statements include the accounts of Everflow, its wholly-owned subsidiaries, including EEI, and interests with joint venture partners (collectively, the "Company"), which are accounted for under the proportional consolidation method. All significant accounts and transactions between the consolidated entities have been eliminated.

Use of Estimates – The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America ("generally accepted accounting principles" or "GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates impacting the Company's financial statements include revenue and expense accruals and oil and gas reserve quantities. In the oil and gas industry, and especially as related to the Company's natural gas sales, the processing of actual transactions generally occurs 60-90 days after the month of delivery of its product. Consequently, accounts receivable from production and crude oil and natural gas sales are recorded using estimated production volumes and market or contract prices. Differences between estimated and actual amounts are recorded in subsequent periods’ financial results. As is typical in the oil and gas industry, a significant portion of the Company's accounts receivable from production and crude oil and natural gas sales consists of unbilled receivables. Oil and gas reserve quantities are utilized in the calculation of depreciation, depletion and amortization and the impairment of crude oil and natural gas properties and also impact the timing and costs associated with asset retirement obligations. The Company's estimates, especially those related to oil and gas reserves, could change in the near term and could significantly impact the Company's results of operations and financial position.

F-10

~~Table~~EVERFLOW ofEASTERN ~~Contents~~PARTNERS, L. P.

EVERFLOW EASTERN PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1.

Organization and Summary of Significant Accounting Policies

Fair Value of Financial Instruments – The fair values of cash and equivalents, accounts receivable, accounts payable and other short-term obligations approximate their carrying values because of the short maturity of these financial instruments. The carrying values of the Company's long-term obligations approximate their fair value because they are considered to be at current market rates. In accordance with generally accepted accounting principles, rates available to the Company at the balance sheet dates are used to estimate the fair value of existing obligations.

D. Cash and Equivalents – The Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. The Company maintains, at various financial institutions, cash and equivalents which may exceed federally insured amounts and which may, at times, significantly exceed balance sheet amounts due to float. Cash and equivalents include $3,~~287~~538,~~702~~740 and $3,~~064~~287,~~191~~702 of operational advances at December 31, ~~2024~~2025 and ~~2023~~2024, respectively, which are funds collected and held on behalf of joint venture partners for their anticipated share of future plugging and abandonment costs. Operational advances include approximately $1,~~029~~116,~~600~~200 and $~~941~~1,~~700~~029,600 held on behalf of employees, including officers and directors, at December 31, ~~2024~~2025 and ~~2023~~2024, respectively.

Investments – The Company’s investments are classified as available-for-sale securities and consist of shares held in a mutual fund that invests primarily in investment grade, U.S. dollar denominated short-term fixed and floating rate debt securities. The mutual fund seeks current income while seeking to maintain a low volatility of principal.

The Financial Accounting Standards Board established a framework for measuring fair value and expands disclosures about fair value measurements by establishing a fair value hierarchy that prioritizes the inputs and defines valuation techniques used to measure fair value. The hierarchy gives highest priority to Level I inputs and lowest priority to Level III inputs. The three levels of the fair value hierarchy are described below:

Level I – Quoted prices are available in active markets for identical financial instruments as of the reporting date.

Level II – Pricing inputs are other than quoted prices in active markets, which are either directly or indirectly observable as of the reporting date, and fair value is determined through the use of models or other valuation methodologies.

Level III – Pricing inputs are unobservable for the financial instrument and include situations where there is little, if any, market activity for the financial instrument. The inputs into the determination of fair value require significant management judgment or estimation.

The Company’s investments are carried at fair market value based on quoted prices available in active markets and are therefore classified as Level I.

F-11

~~Table~~EVERFLOW ofEASTERN ~~Contents~~PARTNERS, L. P.

EVERFLOW EASTERN PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1.

Organization and Summary of Significant Accounting Policies

Property and Equipment – The Company uses the successful efforts method of accounting for oil and gas exploration and production activities. Under successful efforts, costs to acquire mineral interests in oil and gas properties, to drill and equip development wells and related asset retirement costs are capitalized. Costs of development wells (on properties the Company has no further interest in) that do not find proved reserves and geological and geophysical costs are expensed. The Company has not participated in exploratory drilling and owns no interest in unproved properties.

Capitalized costs of proved properties, after considering estimated dismantlement and abandonment costs and estimated salvage values, are amortized by the unit-of-production method based upon estimated proved developed reserves. Depletion, depreciation, and amortization on proved properties amounted to $~~390~~306,~~157~~772 and $1390,~~506,961~~157 during ~~2024~~2025 and ~~2023~~2024, respectively.

Generally accepted accounting principles require that long-lived assets (including oil and gas properties) and certain identifiable intangibles be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The Company, at least annually, reviews its proved crude oil and natural gas properties (on a field by field basis) for impairment by comparing the carrying value of its properties to the properties' undiscounted estimated future net cash flows. Estimates of future crude oil and natural gas prices, operating costs, and production are utilized in determining undiscounted future net cash flows. The estimated future production of oil and gas reserves is based upon the Company's independent reserve engineer's estimate of proved reserves which includes assumptions regarding field decline rates and future prices and costs. For properties where the carrying value exceeds undiscounted future net cash flows, the Company recognizes as impairment the difference between the carrying value and fair market value of the properties. The Company determines fair market value, using the income approach, as the properties’ discounted estimated future net cash flows. The key assumptions above are not observable in the market and, therefore, the fair value of the oil and gas properties is classified as Level III. The Company did not write down any crude oil and natural gas properties during ~~2024~~2025 or ~~2023~~2024.

Pipeline and support equipment and other corporate property and equipment are recorded at cost and depreciated principally on the straight-line method over their estimated useful lives (pipeline and support equipment - 10 to 15 years, other corporate equipment - 3 to 7 years, building and improvements - 39 to 40 years). Depreciation on pipeline and support equipment amounted to $67,819 and $76,621 for the years ended December 31, 2025 and 2024, respectively. Depreciation on other corporate property and equipment, included in general and administrative expense, amounted to $96,096 and $91,233 for the years ended December 31, 2025 and 2024, respectively.

F-12

~~Table~~EVERFLOW ofEASTERN ~~Contents~~PARTNERS, L. P.

EVERFLOW EASTERN PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1.

Organization and Summary of Significant Accounting Policies

Property and Equipment (Continued)

Pipeline and support equipment and other corporate property and equipment are recorded at cost and depreciated principally on the straight-line method over their estimated useful lives (pipeline and support equipment - 10 to 15 years, other corporate equipment - 3 to 7 years, building and improvements - 39 to 40 years). Depreciation on pipeline and support equipment amounted to $76,621 and $82,926 for the years ended December 31, 2024 and 2023, respectively. Depreciation on other corporate property and equipment, included in general and administrative expense, amounted to $91,233 and $84,005 for the years ended December 31, 2024 and 2023, respectively.

Maintenance and repairs of property and equipment are expensed as incurred. Major renewals and improvements are capitalized, and the assets replaced are retired.

Asset Retirement Obligations – Generally accepted accounting principles require the fair value of a liability for an asset retirement obligation to be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. For the Company, these obligations include dismantlement, plugging and abandonment of crude oil and natural gas wells and associated pipelines and equipment. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depleted over the estimated useful life of the related asset.

The estimated liability is based on historical experience in dismantling, plugging and abandoning wells, estimated remaining lives of those wells based on reserves estimates, estimates of the external cost to dismantle, plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability will likely occur due to: changes in estimates of dismantlement, plugging and abandonment costs, changes in estimated remaining lives of the wells, changes in federal or state regulations regarding plugging and abandonment requirements, and other factors. At December 31, 2025, the Company made a revision in estimate of dismantlement, plugging and abandonment costs.

The schedule below is a reconciliation of the Company's liability for the years ended December 31:

	2024			2023
	2025			2024
Beginning of period	$	1617,~~868~~750,~~494~~892		$	1516,~~888~~868,~~385~~494
Liabilities incurred		-233			~~184~~-
Liabilities settled		(~~248~~106,~~520~~615	)		(~~204~~248,~~660~~520	)
Accretion expense		1920,~~130,918~~663			1,~~184~~130,~~585~~918
End of period	$	17,750,892		$	16,868,494
Revision of estimated cash flows		416,850			-
End of period	$	18,982,023		$	17,750,892

F-13

~~Table~~EVERFLOW ofEASTERN ~~Contents~~PARTNERS, L. P.

EVERFLOW EASTERN PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1.

Organization and Summary of Significant Accounting Policies

Revenue Recognition – Revenues from contracts with customers are recognized when performance obligations are satisfied in accordance with contractual terms.

For the sale of crude oil and natural gas from operated properties, the Company generally considers each unit (BBL or MCF) to be a separate performance obligation. The transaction price may consist of fixed and variable consideration, in which the variable amount is determinable each production period and is recognized as revenue upon pickup/delivery of the crude oil or natural gas, which is the point in time that the customer obtains control of the crude oil or natural gas and the Company's performance obligation is satisfied.

Crude oil and natural gas sales derived from third party operated wells are recognized under similar terms as sales of crude oil and natural gas from operated properties and revenue is recognized at a point in time when the product is delivered, the purchaser obtains control and the Company's performance obligation is satisfied.

Crude oil and natural gas sales represent the Company's share of revenues, net of royalties and other revenue interests owned by other parties. When settling crude oil and natural gas sales on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis.

Based on the Company's judgment, the Company's performance obligations have been satisfied and an unconditional right to consideration exists at December 31, ~~2024~~2025 and ~~2023~~2024, respectively; therefore, the Company recognized amounts due from contracts with customers as production accounts receivable within the Company’s consolidated balance sheets at December 31, ~~2024~~2025 and ~~2023~~2024, respectively.

The Company utilizes the sales method to account for gas production volume imbalances. Under this method, revenue is recognized only when gas is produced and sold on the Company’s behalf. The Company had no material gas imbalances at December 31, ~~2024~~2025 and ~~2023~~2024.

The Company frequently participates (and may act as drilling contractor) with affiliated and unaffiliated joint venture partners and certain employees, officers and directors in the drilling, development and operation of jointly owned oil and gas properties. Each owner, including the Company, has an undivided interest in the jointly owned properties. Generally, the joint venture partners, employees, officers and directors participate on the same drilling/development cost basis as the Company and, therefore, no revenue, expense or income is recognized on the drilling and development of the properties. Well management and operating revenues are derived from a variety of both verbal and written operating agreements with joint venture partners, and are recognized monthly as services are provided and properties are managed and operated. Other revenues consist of miscellaneous revenues that are recognized at the time services are rendered, the Company has a contractual right to such revenue and collection is reasonably assured.

F-14

~~Table~~EVERFLOW ofEASTERN ~~Contents~~PARTNERS, L. P.

EVERFLOW EASTERN PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1.

Organization and Summary of Significant Accounting Policies

Income Taxes – Everflow is not a tax-paying entity and the net taxable income or loss, other than the taxable income or loss allocable to EEI, which is a C corporation owned by Everflow, is allocated directly to its respective partners. The non-taxable status of the Programs and Everflow is the primary reconciling item between taxes computed at the Federal statutory rate and the effective tax rate in the consolidated statements of operations. The Company is not able to determine the net difference between the tax bases and the reported amounts of Everflow's assets and liabilities due to separate elections that were made by owners of the working interests and limited partnership interests that comprised the Programs.

EEI accounts for income taxes under generally accepted accounting principles, which require income taxes be provided for all items (as they relate to EEI) in the consolidated statements of operations regardless of the period when such items are reported for income tax purposes. Therefore, deferred tax assets and liabilities are recognized for temporary differences between the financial reporting basis and tax basis of certain EEI assets and liabilities. Deferred tax assets, recorded with other assets, and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to be recovered or settled. The impact on deferred taxes of changes in tax rates and laws, if any, is reflected in the financial statements in the period of enactment. Items giving rise to deferred taxes consist primarily of temporary differences arising from differences in financial reporting and tax reporting methods for EEI's proved properties, ~~percentage depletion~~ and general business credits.

The Company believes that it has appropriate support for any tax positions taken and, as such, does not have any uncertain tax positions that are material to the financial statements.

J. ~~Other~~Allocation of Income –and ~~The~~Per ~~Coronavirus~~Unit ~~Aid,~~Data ~~Relief~~– ~~and~~Under ~~Economic~~the ~~Security~~terms ~~Act~~of ~~created~~ the ~~Employee~~limited ~~Retention~~partnership ~~Credit (“ERC”)~~agreement, ainitially ~~refundable~~99% ~~Federal~~of ~~payroll~~revenues ~~tax~~and ~~credit.~~costs Inwere ~~July~~allocated ~~2023, EEI applied~~ to the ~~Internal~~Unitholders ~~Revenue~~(the ~~Service~~limited ~~(“IRS”~~partners) ~~for~~and ~~credits~~1% of ~~$481,937~~revenues and ~~recognized~~costs ~~them~~were asallocated ~~other~~to ~~income~~the ingeneral ~~2023~~partner. Such allocation has changed and ~~other~~may ~~current~~change ~~assets~~in atthe ~~December~~future ~~31,~~as ~~2023.~~Unitholders ~~Approximately~~elect ~~$474,000~~to ofexercise the ~~credits~~Repurchase ~~were~~Right ~~received~~and ~~from~~select ~~the~~officers ~~IRS~~and inemployees ~~2024~~elect to exercise options (See Note 3).

K. Allocation of Income and Per Unit Data – Under the terms of the limited partnership agreement, initially 99% of revenues and costs were allocated to the Unitholders (the limited partners) and 1% of revenues and costs were allocated to the general partner. Such allocation has changed and may change in the future as Unitholders elect to exercise the Repurchase Right and select officers and employees elect to exercise options (See Note 3).

Net income per limited partner Unit has been computed based on the weighted average number of Units outstanding during each year presented.

F-15

~~Table~~EVERFLOW ofEASTERN ~~Contents~~PARTNERS, L. P.

EVERFLOW EASTERN PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1.

Organization and Summary of Significant Accounting Policies

LK. New Accounting Standards – In November 2023, the Financial Accounting Standards Board issued Accounting Standards Update 2023-07, “Segment Reporting (Topic 280) – Improvement to Reportable Segment Disclosures” (“ASU 2023-07”). ASU 2023-07 expands annual and interim disclosure requirements for reportable segments, primarily through enhanced disclosures about significant segment expenses. ASU 2023-07 is effective for fiscal years beginning after December 15, 2023. The Company ~~adopted ASU 2023-07 on January 1, 2024, which did not have a material impact on the Company’s consolidated financial statements and related disclosures. The Company~~ has reviewed ~~all other~~ recently issued accounting standards in order to determine their effects, if any, on the consolidated financial statements. Based on that review, the Company believes that none of these standards will have a significant effect on ~~the~~ current or future earnings or results of operations.

Note 2.

Current Liabilities

The Company's accounts payable and accrued expenses consist of the following at December 31:

	2024		2023
	2025		2024
Accounts Payable:
Production and related other	$	2,~~644~~911,~~137~~105	$	2,~~698~~644,~~368~~137
Other		7073,~~103~~087		7870,~~178~~103
Total accounts payable	$	2,~~714~~984,~~240~~192	$	2,~~776~~714,~~546~~240
Accrued Expenses:
Payroll and retirement plan contributions	$	~~769~~728,~~526~~134	$	~~746~~769,~~841~~526
Current portion of asset retirement obligations		~~169~~242,000		~~216~~169,000
Federal, state and local taxes		35,~~867~~943		3635,~~083~~867
Other general and administrative		2225,~~700~~400		1222,~~800~~700
Total accrued expenses	$	~~997~~1,~~093~~031,477	$	1997,~~011,724~~093

F-16

Table of Contents

EVERFLOW EASTERN PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 3.

Partners' Equity

Units represent limited partnership interests in Everflow. The Units are transferable subject only to the approval of any transfer by EML and to the laws governing the transfer of securities. The Units are not listed for trading on any securities exchange nor are they quoted in the automated quotation system of a registered securities association. However, Unitholders may have an opportunity to require Everflow to repurchase their Units pursuant to the Repurchase Right.

The partnership agreement provides that Everflow will repurchase for cash up to 10% of the then outstanding Units, to the extent Unitholders offer Units to Everflow for repurchase pursuant to the Repurchase Right. The Repurchase Right entitles any Unitholder, between May 1 and June 30 of each year, to notify Everflow that the Unitholder elects to exercise the Repurchase Right and have Everflow acquire certain or all Units. The price to be paid for any such Units is calculated based upon the audited financial statements of the Company as of December 31 of the year prior to the year in which the Repurchase Right is to be effective and independently prepared reserve reports. The price per Unit equals 66% of the adjusted book value of the Company allocable to the Units, divided by the number of Units outstanding at the beginning of the year in which the applicable Repurchase Right is to be effective less all interim cash distributions received by a Unitholder. The adjusted book value is calculated by adding partners' equity, the standardized measure of discounted future net cash flows and the tax effect included in the standardized measure and subtracting from that sum the carrying value of oil and gas properties (net of undeveloped lease costs). If more than 10% of the then outstanding Units are tendered during any period during which the Repurchase Right is to be effective, the investors' Units tendered shall be prorated for purposes of calculating the actual number of Units to be acquired during any such period. The price associated with the 2025 Repurchase Right, based upon the December 31, 2024 calculation, is estimated to be $1.32 per Unit.F-16

InEVERFLOW ~~June~~EASTERN ~~2024~~PARTNERS, ~~the Company repurchased 141,966 Units pursuant to the Repurchase Right at a price of $1~~L.46 ~~per Unit~~P. In June 2023, the Company repurchased 526,433 Units pursuant to the Repurchase Right at a price of $6.36 per Unit. In June 2022, the Company repurchased 121,354 Units pursuant to the Repurchase Right at a price of $2.51 per Unit.

~~The~~NOTES ~~Company~~TO ~~has~~CONSOLIDATED anFINANCIAL Option Repurchase Plan (the "Option Plan") which permits the grant of options to repurchase certain Units to select officers and employees (the "Option Plan Participants"). The purpose of the Option Plan is to assist the Company in attracting and retaining officers and other key employees and to enable those individuals to acquire or increase their ownership interest in the Company in order to encourage them to promote the growth and profitability of the Company. The Option Plan is designed to align directly the financial interests of the Option Plan Participants with the financial interests of the Unitholders. The Company granted 30,000 options to officers and certain key employees in June 2024, 2023, and 2022, respectively. All options granted were exercised on the same date.STATEMENTS

~~All~~Note ~~Units repurchased pursuant to the Repurchase Right are retired except for those Units granted and exercised as options pursuant to the Option Plan~~3. ~~There~~Partners' ~~were~~Equity 4,634,720, 4,746,686 and 5,243,119 outstanding Units following the Company’s repurchase of Units and granting of options in June 2024, 2023, and 2022, respectively. There were no instruments outstanding at December 31, 2024 or 2023 that would potentially dilute net income per Unit.(Continued)

The partnership agreement provides that Everflow will repurchase for cash up to 10% of the then outstanding Units, to the extent Unitholders offer Units to Everflow for repurchase pursuant to the Repurchase Right. The Repurchase Right entitles any Unitholder, between May 1 and June 30 of each year, to notify Everflow that the Unitholder elects to exercise the Repurchase Right and have Everflow acquire certain or all Units. The price to be paid for any such Units is calculated based upon the audited financial statements of the Company as of December 31 of the year prior to the year in which the Repurchase Right is to be effective and independently prepared reserve reports. The price per Unit equals 66% of the adjusted book value of the Company allocable to the Units, divided by the number of Units outstanding at the beginning of the year in which the applicable Repurchase Right is to be effective less all interim cash distributions received by a Unitholder. The adjusted book value is calculated by adding partners' equity, the standardized measure of discounted future net cash flows and the tax effect included in the standardized measure and subtracting from that sum the carrying value of oil and gas properties (net of undeveloped lease costs). If more than 10% of the then outstanding Units are tendered during any period during which the Repurchase Right is to be effective, the investors' Units tendered shall be prorated for purposes of calculating the actual number of Units to be acquired during any such period. The price associated with the 2026 Repurchase Right, based upon the December 31, 2025 calculation, is estimated to be $1.35 per Unit, net of a $0.50 per Unit distribution expected to be made in April 2026.

In June 2025, the Company repurchased 48,148 Units pursuant to the Repurchase Right at a price of $1.32 per Unit. In June 2024, the Company repurchased 141,966 Units pursuant to the Repurchase Right at a price of $1.46 per Unit. In June 2023, the Company repurchased 526,433 Units pursuant to the Repurchase Right at a price of $6.36 per Unit.

The Company has an Option Repurchase Plan (the "Option Plan") which permits the grant of options to repurchase certain Units to select officers and employees (the "Option Plan Participants"). The purpose of the Option Plan is to assist the Company in attracting and retaining officers and other key employees and to enable those individuals to acquire or increase their ownership interest in the Company in order to encourage them to promote the growth and profitability of the Company. The Option Plan is designed to align directly the financial interests of the Option Plan Participants with the financial interests of the Unitholders. The Company granted 24,074, 30,000 and 30,000 options to officers and certain key employees in June 2025, 2024 and 2023, respectively. All options granted were exercised on the same date.

All Units repurchased pursuant to the Repurchase Right are retired except for those Units granted and exercised as options pursuant to the Option Plan. There were 4,610,646, 4,634,720 and 4,746,686 outstanding Units following the Company’s repurchase of Units and granting of options in June 2025, 2024 and 2023, respectively. There were no instruments outstanding at December 31, 2025 or 2024 that would potentially dilute net income per Unit.

F-17

~~Table~~EVERFLOW ofEASTERN ~~Contents~~PARTNERS, L. P.

EVERFLOW EASTERN PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 4.

Retirement Plan

The Company has a defined contribution plan pursuant to Section 401(k) of the Internal Revenue Code for all employees who have reached defined minimum age and term of service requirements (the “Defined Contribution Plan”, or the “DC Plan”). The Company makes safe harbor contributions and matches employees' contributions to the Defined Contribution Plan as annually determined by EMC's Board of Directors. Additionally, the DC Plan has a profit sharing component which provides for contributions to the DC Plan at the discretion of EMC's Board of Directors. Amounts contributed to the DC Plan vest immediately. The Company's total contributions to the Defined Contribution Plan amounted to approximately $~~228~~229,~~400~~300 and $~~217~~228,~~300~~400 for the years ended December 31, ~~2024~~2025 and ~~2023~~2024, respectively.

Note 5.

Business Segments, Risks and Major Customers

The Company operates exclusively in Ohio and Pennsylvania of the United States in the acquisition, exploration, development and production of oil and gas. The Company has determined that all of its business activities meet the aggregation criteria of ASU 2023-07 and those business activities are collectively reviewed by the Company’s Chief Executive Officer, who has been identified as the ~~Chief~~chief ~~Operating~~operating ~~Decision~~decision ~~Maker (“CODM”)~~maker.

The ~~CODM~~CEO regularly evaluates performance of the aggregated single operating and reporting segment, makes operating decisions and allocates resources based on net income calculated on the same basis as is net income reported in the Company’s consolidated statement of operations. The ~~CODM~~CEO is also regularly provided with expense information at a level consistent with that disclosed in the Company’s consolidated statement of operations.

The Company operates in an environment with many financial risks, including, but not limited to, the ability to acquire additional economically recoverable oil and gas reserves, the inherent risks of the search for, development of and production of oil and gas, the ability to sell oil and gas at prices which will provide attractive rates of return, the volatility and seasonality of oil and gas production and prices, and the highly competitive and, at times, seasonal nature of the industry and worldwide economic conditions. The Company's ability to expand its reserve base and diversify its operations is also dependent upon the Company's ability to obtain the necessary capital through operating cash flow, borrowings or equity offerings. Various federal, state and governmental agencies are considering, and some have adopted, laws and regulations regarding environmental protection which could adversely affect the proposed business activities of the Company. The Company cannot predict what effect, if any, current and future regulations may have on the operations of the Company.

Management of the Company continually evaluates whether the Company can develop oil and gas properties at historical levels given current industry and market conditions. If the Company is unable to do so, it could be determined that it is in the best interests of the Company and its Unitholders to reorganize, liquidate or sell the Company. However, management cannot predict whether any sale transaction will be a viable alternative for the Company in the immediate future.

Natural gas sales accounted for 51% and 55% of total crude oil and natural gas sales in 2024 and 2023, respectively. Approximately 79% and 76% of total crude oil and natural gas sales were derived from operated wells in 2024 and 2023, respectively. The Company had one significant purchaser of natural gas production from operated wells for the years ended December 31, 2024 and 2023 (the “Major Gas Purchaser”). Natural gas sales to the Major Gas Purchaser as a percentage of consolidated crude oil and natural gas sales were 35% and 37% in 2024 and 2023, respectively.

F-18

~~Table~~EVERFLOW ofEASTERN ~~Contents~~PARTNERS, L. P.

EVERFLOW EASTERN PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 5.

Business Segments, Risks and Major Customers (Continued)

AsNatural gas sales accounted for 71% and 51% of ~~December~~total ~~31,~~crude ~~2024,~~oil and natural gas ~~purchased~~sales byin ~~the~~2025 ~~Major~~and ~~Gas~~2024, ~~Purchaser~~respectively. ~~covers~~Approximately ~~production~~84% ~~from~~and ~~approximately~~79% ~~560~~of ~~gross~~total crude oil and natural gas sales were derived from operated wells in 2025 and 2024, respectively. ~~Production~~The ~~purchased~~Company byhad ~~the~~one ~~Major~~significant ~~Gas~~purchaser ~~Purchaser~~of natural gas production from operated wells ~~comprised~~for ~~approximately~~the ~~69%~~years ended December 31, 2025 and ~~66%~~2024 of(the “Major Gas Purchaser”). Natural gas sales to the ~~Company's~~Major Gas Purchaser as a percentage of consolidated crude oil and natural gas sales was 55% and 35% in ~~2024~~2025 and ~~2023~~2024, respectively.

As of December 31, 2025, natural gas purchased by the Major Gas Purchaser covers production from approximately 560 gross operated wells. Production purchased by the Major Gas Purchaser from operated wells comprised approximately 78% and 69% of the Company's consolidated natural gas sales in 2025 and 2024, respectively.

The Company sells substantially all its crude oil production from operated wells to one purchaser (the “Major Oil Purchaser”).

The Company's production accounts receivable result from sales of natural gas and crude oil. A significant portion of the Company's production accounts receivable is due from the Company's ~~major~~Major ~~customers~~Gas Purchaser and Major Oil Purchaser. The Company does not view such concentration as an unusual credit risk. However, the Company does not require collateral from its customers and could incur losses if its customers fail to pay. As a result of management's review of current and historical credit losses as well as the current and expected economic trends, a valuation allowance was not deemed necessary at December 31, ~~2024~~2025 and ~~2023~~2024. The Company expects that the Major Gas Purchaser and Major Oil Purchaser will continue to be the only major customers for natural gas and crude oil production from its operated wells in ~~2025~~2026. Historically, the Company has not tracked the purchasers of natural gas and crude oil derived from third party operated wells which may have the same customers.

Note 6.

Commitments and Contingencies

The Company has multiple contracts with the Major Gas Purchaser which obligate the Major Gas Purchaser to purchase, and the Company to sell and deliver, certain quantities of natural gas production from the Company’s oil and gas properties throughout the contract periods. The Company may elect to lock-in specific volumes of natural gas to be sold in specific months at a mutually agreeable price. The Company has elected to lock-in various monthly quantities of natural gas which total 1,~~350~~170,000 MCF from January ~~2025~~2026 through April 2027 at various monthly weighted-average pricing provisions averaging $3.3440 per MCF, net of regional basis adjustments. Pricing provisions with the Major Gas Purchaser apply to certain fixed quantities on a monthly basis with excess monthly quantities being priced based on a monthly settlement price, net of a regional basis adjustment. The impact of these contracts on the Company’s future oil and gas sales cannot fully be measured until actual production volumes and prices have been determined. Management believes the Company can meet its delivery commitments based on estimated production.

F-19

~~Table~~EVERFLOW ofEASTERN ~~Contents~~PARTNERS, L. P.

EVERFLOW EASTERN PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 7.

Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited)

The following supplemental unaudited oil and gas information is required by generally accepted accounting principles.

The tables on the following pages set forth pertinent data with respect to the Company's oil and gas properties, all of which are located within the continental United States.

CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES

CAPITALIZED COSTS RELATING TO OIL AND GAS
PRODUCING ACTIVITIES


	Years ended December 31,
	2025		2024

Proved oil and gas properties	$	133,787,643	$	134,156,537

Pipeline and support equipment		656,630		617,217

Gross capitalized costs		134,444,273		134,773,754

Accumulated depreciation, depletion, amortization and write down		128,966,022		129,526,077

Net capitalized costs	$	5,478,251	$	5,247,677

COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
	Years ended December 31,
	2024		2023
	2025		2024
Proved oil and gas properties	$	134,156,537	$	135,663,041
Property acquisition costs	$	1,451	$	-
Pipeline and support equipment		617,217		617,217
Development costs		46,574		-
Gross capitalized costs		134,773,754		136,280,258
Accumulated depreciation, depletion, amortization and write down		129,526,077		130,523,254
Net capitalized costs	$	5,247,677	$	5,757,004

~~COSTS~~The ~~INCURRED~~Company INhad ~~OIL~~no ~~AND~~purchases ~~GAS~~of ~~PRODUCING~~producing ~~ACTIVITIES~~oil and gas properties in 2025 or 2024.

	Years ended December 31,
	2024		2023
Property acquisition costs	$	-	$	6,111
Development costs		-		188,250

The Company had no purchases of producing oil and gas properties in 2024 or 2023.

F-20

~~Table~~EVERFLOW ofEASTERN ~~Contents~~PARTNERS, L. P.

EVERFLOW EASTERN PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 7.

Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) (Continued)

RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES

RESULTS OF OPERATIONS FOR OIL AND
GAS PRODUCING ACTIVITIES

	Years ended December 31,
	2025			2024

Crude oil and natural gas sales	$	6,558,645		$	4,562,324
Production costs		(2,516,886	)		(2,297,314	)
Depreciation, depletion and amortization		(374,591	)		(466,778	)
Accretion expense		(920,663	)		(1,130,918	)

Results of operations before income tax benefit		2,746,505			667,314

Income tax benefit		13,202			13,800

Results of operations for oil and gas producing activities (excluding corporate overhead and financing costs)	$	2,759,707		$	681,114

	Years ended December 31,
	2024			2023
Crude oil and natural gas sales	$	4,562,324		$	5,500,946
Production costs		(2,297,314	)		(2,273,596	)
Depreciation, depletion and amortization		(466,778	)		(1,589,887	)
Accretion expense		(1,130,918	)		(1,184,585	)
Results of operations before income tax expense (benefit)		667,314			452,878
Income tax expense (benefit)		(13,800	)		19,900
Results of operations for oil and gas producing activities (excluding corporate overhead and financing costs)	$	681,114		$	432,978

Income tax benefit was computed using statutory tax rates and reflects temporary differences that are reflected in the Company's consolidated income tax benefit for the year.

Income tax expense (benefit) was computed using statutory tax rates and reflects temporary differences that are reflected in the Company's consolidated income tax expense (benefit) for the year.

F-21

~~Table~~EVERFLOW ofEASTERN ~~Contents~~PARTNERS, L. P.

EVERFLOW EASTERN PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 7.

Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) (Continued)

ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES

ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES


	Oil			Gas
	(BBLS)			(MCF)

Balance, January 1, 2024		287,000			7,953,000
Production		(31,000	)		(1,077,000	)
Revision of previous estimates		(4,000	)		(793,000	)

Balance, December 31, 2024		252,000			6,083,000
Extensions, discoveries and other additions		2,000			20,000
Production		(30,000	)		(1,434,000	)
Revision of previous estimates		29,000			6,398,000

Balance, December 31, 2025		253,000			11,067,000

	Oil			Gas
	(BBLS)			(MCF)
Balance, January 1, 2023		398,000			21,713,000
Extensions, discoveries and other additions		7,000			109,000
Production		(33,000	)		(1,226,000	)
Revision of previous estimates		(85,000	)		(12,643,000	)
Balance, December 31, 2023		287,000			7,953,000
Production		(31,000	)		(1,077,000	)
Revision of previous estimates		(4,000	)		(793,000	)
Balance, December 31, 2024		252,000			6,083,000

The Company has not determined proved reserves associated with its proved and other undeveloped properties, including its deep property interests. The Company has no net proved undeveloped acres at December 31, 2025 and 2024.

STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS


	December 31,
	2025			2024
	(Thousands of Dollars)
Future cash inflows from sales of oil and gas	$	45,410		$	28,921
Future production and development costs		(27,416	)		(17,042	)
Future asset retirement obligations, net of salvage		(19,572	)		(17,639	)
Future income tax expense		(222	)		(175	)

Future net cash flows		(1,800	)		(5,935	)
Effect of discounting future net cash flows at 10% per annum		(2,842	)		(44	)

Standardized measure of discounted future net cash flows	$	(4,642	)	$	(5,979	)

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

	December 31,
	2024			2023
	(Thousands of Dollars)
Future cash inflows from sales of oil and gas	$	28,921		$	35,450
Future production and development costs		(17,042	)		(20,906	)
Future asset retirement obligations, net of salvage		(17,639	)		(17,817	)
Future income tax expense		(175	)		(195	)
Future net cash flows		(5,935	)		(3,468	)
Effect of discounting future net cash flows at 10% per annum		(44	)		(273	)
Standardized measure of discounted future net cash flows	$	(5,979	)	$	(3,741	)

F-22

~~Table~~EVERFLOW ofEASTERN ~~Contents~~PARTNERS, L. P.

EVERFLOW EASTERN PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 7.

Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) (Continued)

CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

CHANGES IN THE STANDARDIZED MEASURE OF
DISCOUNTED FUTURE NET CASH FLOWS


	Years Ended December 31,
	2025			2024
	(Thousands of Dollars)

Balance, beginning of year	$	(5,979	)	$	(3,741	)
Extensions, discoveries and other additions		66			-
Revision of quantity estimates		3,447			(236	)
Sales of crude oil and natural gas, net of production costs		(4,042	)		(2,265	)
Net change in income taxes		(30	)		10
Net changes in prices and production costs		1,833			(947	)
Accretion of discount		(598	)		(374	)
Other		661			1,574

Balance, end of year	$	(4,642	)	$	(5,979	)

	Years Ended December 31,
	2024			2023
	(Thousands of Dollars)
Balance, beginning of year	$	(3,741	)	$	34,634
Extensions, discoveries and other additions		-			353
Revision of quantity estimates		(236	)		(36	)
Sales of crude oil and natural gas, net of production costs		(2,265	)		(3,227	)
Net change in income taxes		10			485
Net changes in prices and production costs		(947	)		(50,232	)
Accretion of discount		(374	)		3,463
Other		1,574			10,819
Balance, end of year	$	(5,979	)	$	(3,741	)

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the Company. The estimated future cash flows are determined based on crude oil and natural gas pricing parameters established by generally accepted accounting principles, adjusted for contract terms within contract periods, estimated production of proved crude oil and natural gas reserves, estimated future production and development costs of reserves and future retirement obligations (net of salvage), based on current economic conditions, and the estimated future income tax expense, based on year-end statutory tax rates (with consideration of future tax rates already legislated) to be incurred on pretax net cash flows less the tax basis of the properties involved. Such cash flows are then discounted using a 10% rate.

The methodology and assumptions used in calculating the standardized measure are those required by generally accepted accounting principles and United States Securities and Exchange Commission reporting requirements. It is not intended to be representative of the fair market value of the Company's proved reserves. The valuation of revenues and costs does not necessarily reflect the amounts to be received or expended by the Company. In addition to the valuations used, numerous other factors are considered in evaluating known and prospective oil and gas reserves.

Average adjusted natural gas prices used in the estimation of proved reserves were $12.7668 and $1.7576 per MCF at December 31, ~~2024~~2025 and ~~2023~~2024, respectively, and the average adjusted crude oil prices used in the estimation of proved reserves were $7261.1197 and $7472.7111 per BBL at December 31, ~~2024~~2025 and ~~2023~~2024, respectively.

F-23

Table of Contents

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

As of the end of the period covered by this report, management performed, with the participation of our Chief Executive Officer and Chief Financial Officer, an evaluation of the effectiveness of our disclosure controls and procedures as defined in Exchange Act Rules 13a-15. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures. Based on the evaluation, management concluded that our disclosure controls and procedures were effective for the year ended December 31, ~~2024~~2025.

Management’s Report on Internal Control Over Financial Reporting

Management, including our Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Exchange Act Rules 13a-15). Internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Effective internal control can provide only reasonable assurance with respect to financial statement preparation and may not prevent or detect misstatements. Due to limitations on any control systems, no evaluation of controls can provide absolute assurance that all control issues have been detected. In addition, effective internal control at a point in time may become ineffective in future periods because of changes in conditions or due to deterioration in the degrees of compliance with our established policies and procedures. Management intends to continue to evaluate and improve internal controls over financial reporting as necessary and appropriate for the Company’s business, however management cannot provide assurance that such improvements will be sufficient to provide effective internal control over financial reporting.

Management is responsible for assessing the effectiveness of our internal controls over financial reporting. The Company’s management, including the Chief Executive Officer and the Chief Financial Officer, conducted an evaluation of the effectiveness of internal control over financial reporting as of December 31, ~~2024~~2025 based on the guidelines established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) (2013 Framework). Management utilized internal and external resources to assist in the various aspects of its assessment and compliance efforts. As a result of its assessment, management has concluded that the Company’s internal controls over financial reporting were effective as of December 31, ~~2024~~2025.

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Table of Contents

This Annual Report on Form 10-K does not include an attestation report of the Company’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s independent registered public accounting firm pursuant to SEC rules that permit the Company to provide only management’s report in this Annual Report Form 10-K.

Changes in Internal Control Over Financial Reporting

Management, including its Chief Executive Officer and Chief Financial Officer, has concluded that there were no changes in the Company’s internal control over financial reporting during ~~2024~~2025 that have materially affected, or are reasonably likely to materially affect the Company’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

During the year ended December 31, ~~2024~~2025, none of EEI'’s or EMC'’s directors or officers (as defined in Rule 16a-1(f) of the Exchange Act) adopted or terminated a "“Rule 10b5-1 trading arrangement"” or a "“non-Rule 10b5-1 trading arrangement"” (as such items are defined in Item 408 of Regulation S-K), nor do any of the directors or officers (as defined in Rule 16a-1(f) of the Exchange Act) currently maintain any such arrangements.

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

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Table of Contents

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The Company, as a limited partnership, does not have any directors or executive officers. The General Partner of the Company is Everflow Management Limited, LLC, an Ohio limited liability company formed in March 1999, as the successor to the Company’s original general partner. The members of the General Partner as of March 10, ~~2025~~2026 are EMC; three individuals who are officers and directors of EEI, Brian A. Staebler, Michael W. Rathburn and William A. Siskovic and one director of EEI, Thomas L. Korner. Mr. Siskovic also serves as Chairman of the Board of EEI.

EMC is the Managing Member of the General Partner. EMC was formed in September 1990 to act as the managing general partner of Everflow Management Company, the predecessor of the General Partner. EMC is owned by the other members of the General Partner and EMC currently has no employees, but as managing member of the General Partner makes all management and business decisions on behalf of the General Partner and thus on behalf of the Company.

EEI has continued its separate existence as a holder of interests in many of the same crude oil and natural gas properties that the Company operates. EEI also employs all personnel to conduct all of the Company’s business. All of EEI’s outstanding shares are owned by the Company.

Directors and Officers of EEI and EMC. The executive officers and directors of EEI and EMC as of March 10, ~~2025~~2026 are as follows:

Name	Age	Positions and Offices
Brian A. Staebler	5051	President, Principal Executive Officer and director
		Executive Officer
Michael W. Rathburn	42	Vice President, Principal Financial and Accounting Officer and director
		and director
William A. Siskovic	70	Vice President, Principal Operations Officer and Chairman of the Board
Michael W. Rathburn	41	Vice President, Principal
Thomas L. Korner	72	Director
		Financial and Accounting
		Officer and director
William A. Siskovic	69	Vice President, Principal
		Operations Officer
		and Chairman of the Board
Thomas L. Korner	71	Director

- 28 -

~~Table~~All officers of ~~Contents~~EEI are employed by EEI to conduct business affairs of the Company. All directors of EEI are elected to serve by the Company, which is EEI’s sole shareholder. Directors of EEI received no additional compensation or fees for their services to EEI or their services on behalf of the Company in 2025 or 2024.

All officers of EEI are employed by EEI to conduct business affairs of the Company. All directors of EEI are elected to serve by the Company, which is EEI’s sole shareholder. Directors of EEI received no additional compensation or fees for their services to EEI or their services on behalf of the Company in 2024 or 2023.

All directors and officers of EMC hold their positions with EMC pursuant to a shareholders’ agreement among EMC and such directors and officers. The shareholders agreement controls the operation of EMC, provides for changes in share ownership of EMC, and determines the identity of the directors and officers of EMC as well as their replacements.

As a result of the foregoing organizational structure, the Company does not have a nominating committee or a compensation committee. The Directors of EMC function as the Company’s audit committee. None of the members of EMC’s board are “independent.” The Company believes that its status as a limited partnership, the limited voting rights possessed by holders of limited partnership units, and the existence of contractual arrangements governing the selection of EMC’s directors and officers makes it appropriate for the Company not to maintain nominating or compensation committees. Each director of EMC participates in determining the compensation of the executive officers of the Company.

Brian A. Staebler was appointed to serve as President and Principal Executive Officer and director of EEI and EMC in March 2021. He supervises and oversees all aspects of the Company and EEI’s business, including oil and gas property acquisition, development, operation and marketing. He had previously served as Vice President, Secretary-Treasurer, Principal Financial Accounting Officer and director of EEI and EMC from January 2010 to March 2021. Prior to his role as Vice President, he had served as the Internal Audit Manager for the Company since September 2007, leading the Company’s efforts to become compliant with Sarbanes Oxley regulations. Prior to joining the Company, Mr. Staebler was a Senior Manager with Hausser + Taylor LLC, certified public accountants, and lead in-charge of the audit team that performed the annual audit and quarterly reviews of the Company as well as many other companies in the oil and gas industry. He had been a member of the audit team since December 1997. Mr. Staebler also served as a member of the firm’s oil and gas industry practice, covering an array of areas including attestation, financial reporting and consulting, and tax regulation. Mr. Staebler’s experience in working with the Company for 10 years as an independent auditor, financial reporting consultant and tax consultant, in addition to his experience as an employee of the Company working with Sarbanes Oxley regulations and compliance as it relates specifically to the Company, as well as his role as a senior financial executive since January 2010, qualifies him as an officer and director. Mr. Staebler has a Business Administration Degree in Accounting from the University of Toledo, is an active Certified Public Accountant licensed by the Accountancy Board of Ohio, and is a current member of the American Institute of Certified Public Accountants, the Ohio Society of Certified Public Accountants, and, the Ohio Oil and Gas Association.

Michael W. Rathburn was appointed to serve as Vice President, Secretary-Treasurer, Principal Financial Accounting Officer and director of EEI and EMC in March 2021. Mr. Rathburn is responsible for the financial operations of the Company and EEI. Prior to his role as Vice President, he had served as the Production Revenue Manager for the Company since April 2019, responsible for overseeing all aspects of the Company’s operations over oil and gas revenues, expenses and production distributions. Prior to joining the Company, Mr. Rathburn was a Senior Manager with Maloney + Novotny, LLC, certified public accountants, and lead in-charge of the audit team that performed the annual audit and quarterly reviews of the Company as well as other companies in the oil and gas industry and public sector. He had been a member of the audit team since May 2007. Mr. Rathburn also served as a member of the firm’s oil and gas industry practice, accounting and attestation practice and SEC practice. While at the firm, Mr. Rathburn specialized in attestation, financial reporting (both public and private sectors), corporate taxation and business consulting. Mr. Rathburn’s experience in working with the Company for 12 years as an independent auditor, financial reporting and tax consultant, in addition to his experience as an employee of the Company working as the Production Revenue Manager, qualifies him as an officer, director and audit committee financial expert. Mr. Rathburn has a Business Administration Degree in Accounting from Miami University, is an active Certified Public Accountant licensed by the Accountancy Board of Ohio and is a current member of the American Institute of Certified Public Accountants, the Ohio Society of Certified Public Accountants, and the Ohio Oil and Gas Association.

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~~Table~~Michael W. Rathburn was appointed to serve as Vice President, Secretary-Treasurer, Principal Financial Accounting Officer and director of ~~Contents~~EEI and EMC in March 2021. Mr. Rathburn is responsible for the financial operations of the Company and EEI. Prior to his role as Vice President, he had served as the Production Revenue Manager for the Company since April 2019, responsible for overseeing all aspects of the Company’s operations over oil and gas revenues, expenses and production distributions. Prior to joining the Company, Mr. Rathburn was a Senior Manager with Maloney + Novotny, LLC, certified public accountants, and lead in-charge of the audit team that performed the annual audit and quarterly reviews of the Company as well as other companies in the oil and gas industry and public sector. He had been a member of the audit team since May 2007. Mr. Rathburn also served as a member of the firm’s oil and gas industry practice, accounting and attestation practice and SEC practice. While at the firm, Mr. Rathburn specialized in attestation, financial reporting (both public and private sectors), corporate taxation and business consulting. Mr. Rathburn’s experience in working with the Company for 12 years as an independent auditor, financial reporting and tax consultant, in addition to his experience as an employee of the Company working as the Production Revenue Manager, qualifies him as an officer, director and audit committee financial expert. Mr. Rathburn has a Business Administration Degree in Accounting from Miami University, is an active Certified Public Accountant licensed by the Accountancy Board of Ohio and is a current member of the American Institute of Certified Public Accountants, the Ohio Society of Certified Public Accountants, and the Ohio Oil and Gas Association.

William A. Siskovic was President and Principal Executive Officer of EEI and EMC from January 2010 to March 2021, when he resigned from these positions to accept a reduced role as Vice President and Principal Operations Officer. Mr. Siskovic was appointed as Chairman of the Board of EEI and EMC in March 2024. Mr. Siskovic had also previously served as Vice President of EEI from January 1989 to January 2010 and as Vice President, Secretary-Treasurer, Principal Financial and Accounting Officer and a director of EMC. He had served as Principal Financial and Accounting Officer and Secretary of EMC since November 1995 and in all other capacities since the formation of EMC in September 1990. Mr. Siskovic’s experience as a senior financial executive with EEI and EMC since the Company’s formation provides the Company with a valuable resource and qualifies him for his role as officer and director. He is responsible for ~~day-to-day~~ operational efficiency of the Company and EEI. From August 1980 to July 1984, Mr. Siskovic served in various financial and accounting capacities including Assistant Controller of Towner Petroleum Company, a public independent oil and gas operator, producer and drilling fund sponsor company. From August 1984 to September 1985, Mr. Siskovic was a Senior Consultant for Arthur Young & Company, certified public accountants, where he was primarily responsible for the firm’s oil and gas consulting practice in the Cleveland, Ohio office. From October 1985 until joining EEI in April 1988, Mr. Siskovic served as Controller and Principal Accounting Officer of Lomak Petroleum, Inc., a public independent oil and gas operator and producer. Mr. Siskovic has a Business Administration Degree in Accounting from Cleveland State University and currently serves on the Board of Trustees of the Children's Mental Health Circle of Friends Foundation, a nonprofit organization that serves a counseling center providing behavioral health care services, and is a member of the Ohio Oil and Gas Association.

Thomas L. Korner was President and Principal Executive Officer of EEI and EMC from November 1995 to January 2010, when he resigned from these positions and was appointed as Chairman of the Board for both entities. Mr. Korner served as Chairman of the Board for both entities from January 2010 to March 2024, when he resigned from these roles. He remains a director of EEI and EMC. Mr. Korner had also served as a director of EMC since its formation in September 1990. He served as Vice President and Secretary of EEI from April 1985 to November 1995 and as Vice President and Secretary of EMC from September 1990 to November 1995. He served as the Treasurer of EEI from June 1982 to June 1986. In these roles, Mr. Korner has successfully led the Company since its formation. Prior to joining EEI in June 1982, Mr. Korner was a practicing certified public accountant with Hill, Barth and King, certified public accountants, and prior to that with Arthur Andersen & Co., certified public accountants. He has a Business Administration Degree from Mt. Union College.

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Table of Contents

Audit Committee

EMC is the managing general partner of the Company. The directors and officers of EMC serve as the Company’s audit committee as specified in section 3(a)(58)(B) of the Exchange Act. Michael W. Rathburn, who is not independent, has been designated the Company’s audit committee financial expert.

REPORT OF THE AUDIT COMMITTEE

The Audit Committee oversees the Company’s financial reporting process on behalf of the Board of Directors of Everflow Management Corporation, the managing general partner of Everflow Management Limited, LLC, the general partner of the Company. Management has the primary responsibility for the financial statements and the reporting process, including the systems of internal controls. The independent registered public accountants are responsible for expressing an opinion on the conformity of those audited financial statements with accounting principles generally accepted in the United States.

We have discussed with the independent registered public accountants of the Company, Maloney + Novotny LLC, the matters that independent registered public accounting firms must communicate to audit committees under Public Company Accounting Oversight Board (the “PCAOB”) requirements, which includes a review of the results of the independent registered public accountant’s examination of the Company’s financial statements and related processes.

We have received and reviewed written disclosures and the letter from Maloney + Novotny LLC, which is required by applicable rules of the PCAOB, and we have discussed with Maloney + Novotny LLC their independence under such standards. We have concluded that the independent registered public accountants are independent from the Company and its management.

Based on our review and discussions referred to above, we have recommended to the Board of Directors that the audited financial statements of the Company be included in the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2024~~2025, for filing with the Securities and Exchange Commission.

Respectfully submitted by the members of the Audit Committee:

Brian A. Staebler (Chairman) Michael W. Rathburn William A. Siskovic Thomas L. Korner

Michael W. Rathburn

William A. Siskovic

Thomas L. Korner

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Table of Contents

Code of Ethics. The Company has adopted a Code of Ethics that applies to the Company’s principal executive officer, principal financial officer, principal accounting officer, or persons performing similar functions (the “Financial Officers”). The Code of Ethics is included as Exhibit 14.1 to this Annual Report on Form 10-K.

Pursuant to the Code of Ethics, the Financial Officers are expected to comply with the rules and regulations of federal, state and local governments, including the federal securities laws. The Company does not maintain a separate Insider Trading Policy given that there is no established trading market for the Units.

A copy of the Code of Ethics will be provided upon written request.

Section 16(a) Beneficial Ownership Reporting Compliance. Section 16(a) of the Securities Exchange Act requires the Company’s officers and directors, and persons who own more than 10% of a registered class of the Company’s equity securities to file reports of ownership and changes in ownership with the SEC. Officers, directors and greater than 10% owners are required by SEC regulation to furnish the Company with copies of all Section 16(a) forms they file.

Based solely on the Company’s review of the copies of such forms furnished to the Company, the Company believes that all required Section 16(a) filings for fiscal year ~~2024~~2025 were timely made.

ITEM 11. EXECUTIVE COMPENSATION

As a limited partnership, the Company has no executive officers or directors, but is managed by the General Partner. The executive officers of EMC and EEI are compensated by EEI. The compensation described below represents all compensation from EEI.

Overview of ~~2024~~2025 Executive Compensation Components

Components of executive compensation in the ~~2024~~2025 fiscal year for the executive officers of EMC and EEI include the following:

●

base salary

●

annual cash bonuses

●

retirement and other benefits

Base Salary

The base salary of the executive officers is intended to provide fixed compensation for the performance of core duties. In determining appropriate salary levels, consideration is given to the level and scope of responsibility, experience, and Company and individual performance. The base salaries paid during fiscal ~~2024~~2025 are shown in the Summary Compensation Table appearing further below in this Item 11.

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Table of Contents

Annual Cash Bonuses

The annual bonus of the executive officers is intended to supplement the fixed compensation provided in the base salary to recognize an individual’s performance in a fiscal year. Payment with respect to any cash bonus is contingent upon the satisfaction of objective and subjective performance criteria. The annual cash bonus is determined at the end of each fiscal year. The amount is awarded in the first fiscal quarter following the end of each fiscal year.

Executive officers are provided an annual cash bonus each year based on the achievement of certain financial and non-financial performance objectives during the previous fiscal year. Annual cash bonuses are based on a percentage of the executive’s base salary. For ~~2024~~2025, the Board of Directors set a range of these bonuses between 50% and 160% of the executive’s base salary, based on the Company achieving specified financial and non-financial performance objectives. In ~~2024~~2025, the financial performance objectives that were used for determining financial performance-based cash awards were asset management, profitability and overall company stability. In ~~2024~~2025, the non-financial performance objectives that were used for determining non-financial performance based cash awards were corporate governance and adherence to policies and procedures as well as other factors that vary depending on responsibilities.

The ~~2025~~2026 target annual cash bonus awards for executive officers are established as a percentage of the executive’s base salary. These target amounts range between 50% and 160% of base salary. These target amounts were determined considering executive pay at companies of comparable size. The Board of Directors believes it is important that these target and maximum payout levels are aligned with the Company’s long-term strategic plan and the Company’s expectation of future financial performance.

Retirement and Other Benefits

The executive officers are entitled to the same benefits coverage as other employees such as health insurance, life and disability insurance, participation in the Company’s 401(k) plan, and the reimbursement of ordinary and reasonable business expenses. The executive officers are also provided with additional supplementary life insurance and a Company owned vehicle.

The Company has an Option Repurchase Plan under which the Company may grant options to repurchase Units acquired by the Company as part of the Repurchase Right to eligible officers and employees. The Company granted a total of 2520,000 and 2925,000 options to executive officers in ~~2024~~2025 and ~~2023~~2024, respectively, all of which were exercised immediately.

The Company does not currently offer any deferred compensation program, supplemental executive retirement plan or any financial planning services for executive officers.

- 33 -

~~Table~~The following table sets forth information concerning the annual compensation for services in all capacities to the Company for the fiscal years ended December 31, 2025 and 2024, of ~~Contents~~those persons who were at December 31, 2025: (i) the Principal Executive Officer of EMC and EEI, (ii) the Principal Financial Officer of EMC and EEI; and (iii) the Principal Operations Officer of EMC and EEI. The Principal Executive Officer, Principal Financial Officer and Operations Officer are hereinafter referred to collectively as the “Named Executive Officers.”

The following table sets forth information concerning the annual compensation for services in all capacities to the Company for the fiscal years ended December 31, 2024 and 2023, of those persons who were at December 31, 2024: (i) the Principal Executive Officer of EMC and EEI, (ii) the Principal Financial Officer of EMC and EEI; and (iii) the Principal Operations Officer of EMC and EEI. The Principal Executive Officer, Principal Financial Officer and Operations Officer are hereinafter referred to collectively as the “Named Executive Officers.”

	SUMMARY COMPENSATION TABLE

	Annual Compensation

						Other
Name and Principal Position	Year	Salary		Bonus		Compensation⁽¹⁾			Total

Brian A. Staebler	2025	$	186,200	$	194,000	$	54,000	⁽²⁾	$	434,200
President and Principal Executive Officer	2024	$	179,400	$	190,000	$	53,800	⁽²⁾	$	423,200

Michael W. Rathburn	2025	$	160,300	$	84,500	$	37,500	⁽³⁾	$	282,300
Vice President and Principal Financial and Accounting Officer	2024	$	155,600	$	82,200	$	41,600	⁽³⁾	$	279,400

William A. Siskovic,	2025	$	113,100	$	139,000	$	37,200	⁽⁴⁾	$	289,300
Vice President and Principal Operations Officer	2024	$	113,100	$	131,600	$	39,800	⁽⁴⁾	$	284,500

	SUMMARY COMPENSATION TABLE
	Annual Compensation
						Other
Name and Principal Position	Year	Salary		Bonus		Compensation(1)			Total
Brian A. Staebler	2024	$	179,400	$	190,000	$	53,800	(2)	$	423,200
President and Principal	2023	$	172,600	$	184,000	$	51,200	(2)	$	407,800
Executive Officer
Michael W. Rathburn	2024	$	155,600	$	82,200	$	41,600	(3)	$	279,400
Vice President and Principal	2023	$	150,400	$	80,000	$	40,900	(3)	$	271,300
Financial and Accounting Officer
William A. Siskovic,	2024	$	113,100	$	131,600	$	39,800	(4)	$	284,500
Vice President and Principal	2023	$	113,100	$	124,500	$	39,100	(4)	$	276,700
Operations Officer

No Named Executive Officer received personal benefits or perquisites during 2025 or 2024 in excess of $10,000.

No Named Executive Officer received personal benefits or perquisites during 2024 or 2023 in excess of $10,000.

(1)

Includes amounts contributed under the Company’s Defined Contribution Plan in the form of employer-matched contributions and profit sharing contributions on behalf of the executive officers, and amounts considered taxable wages with respect to personal use of a Company vehicle, the Company’s Group Term Life Insurance Plan, and additional supplemental life insurance. Additional terms of the Defined Contribution Plan are described in the section entitled “Retirement Plans” appearing later in this Item 11.

(2) During fiscal years ended December 31, ~~2024~~2025 and ~~2023~~2024, includes $2728,~~600~~000 and $2627,~~700~~600, respectively, contributed as profit sharing to the Defined Contribution Plan, $2021,~~700~~000 and $1920,~~600~~700, respectively, contributed as matching contributions to the Defined Contribution Plan, $32,~~000~~500 and $3,~~100~~000, respectively considered taxable wages with respect to personal use of a Company vehicle, and $2,500 ~~and $1,800, respectively~~ considered taxable wages with respect to the Company’s Group Term Life Insurance Plan and additional supplemental life insurance.

(3) During fiscal years ended December 31, ~~2024~~2025 and ~~2023~~2024, includes $16,~~300~~800 and $16,~~200~~300, respectively, contributed as profit sharing to the Defined Contribution Plan, $14,~~300~~700 and $1314,~~800~~300, respectively, contributed as matching contributions to the Defined Contribution Plan, $94,900 and $109,~~000~~900 respectively, considered taxable wages with respect to personal use of a Company vehicle, and $1,100 ~~and 900, respectively~~ considered taxable wages with respect to the Company’s Group Term Life Insurance Plan and additional supplemental life insurance.

(4) During fiscal years ended December 31, ~~2024~~2025 and ~~2023~~2024, includes $1715,~~000~~700 and $1617,~~900~~000, respectively, contributed as profit sharing to the Defined Contribution Plan, $14,~~700~~100 and $14,~~300~~700 contributed as matching contributions to the Defined Contribution Plan, $~~1,600~~900 and $1,~~400~~600, respectively, considered taxable wages with respect to personal use of a Company vehicle, and $6,500 considered taxable wages with respect to the Company’s Group Term Life Insurance Plan and additional supplemental life insurance.

None of the Named Executive Officers has an employment agreement with the Company or EEI.

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Outstanding Equity Awards

The Company granted a total of 2520,000 and 2925,000 options to executive officers in ~~2024~~2025 and ~~2023~~2024, respectively, all of which were exercised immediately. There were no outstanding unexercised options as of December 31, ~~2024~~2025 or ~~2023~~2024.

Retirement Plans

The Company has a defined contribution plan pursuant to section 401(k) of the Internal Revenue Code for all employees, including officers, who have reached the age of 21 and completed one year of service (the “Defined Contribution Plan”, or the “DC Plan”). The Company makes safe harbor contributions and matches employees' contributions to the Defined Contribution Plan as annually determined by EMC's board of directors. Additionally, the DC Plan has a profit sharing component which provides for contributions to the DC Plan at the discretion of EMC's board of directors. Amounts contributed to the DC Plan vest immediately.

The Defined Contribution Plan is further described in Note 4 of the Company’s consolidated financial statements included herein.

Royalties

The Company occasionally awards oil and gas royalties to employees, including officers. The Company awarded $78,900 of oil and gas royalties to officers during 2025, including $33,900 to Brian A. Staebler and Michael W. Rathburn, respectively and $11,100 to William A. Siskovic.

Director Compensation

Brian A. Staebler, Michael W. Rathburn, William A. Siskovic and Thomas L. Korner did not receive any additional compensation for their service as directors during ~~2024~~2025 or ~~2023~~2024.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The General Partner is a limited liability company of which EMC, an Ohio corporation, is the managing member. The members of the General Partner as of March 10, ~~2025~~2026 are EMC; three individuals who are officers and directors of EEI, Brian A. Staebler, Michael W. Rathburn and William A. Siskovic and one individual who serves as a director of EEI, Thomas L. Korner. Mr. Siskovic also serves as the Chairman of the Board of EEI. The General Partner of the Company owns a 1.4243% interest in the Company.

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~~Table~~The following table sets forth certain information with respect to the number of ~~Contents~~Units beneficially owned as of March 10, 2026 by each person known to the management of the Company to own beneficially more than 5% of the outstanding Units; and by each director and officer of EMC. The table also sets forth (i) the ownership interests of the General Partner and (ii) the ownership of EMC.

The following table sets forth certain information with respect to the number of Units beneficially owned as of March 10, 2025 by each person known to the management of the Company to own beneficially more than 5% of the outstanding Units; and by each director and officer of EMC. The table also sets forth (i) the ownership interests of the General Partner and (ii) the ownership of EMC.

BENEFICIAL OWNERSHIP OF UNITS IN THE COMPANY,

EVERFLOW MANAGEMENT LIMITED, LLC AND EMC

					Percentage
					Interest in
			Percentage		Everflow		Percentage
	Units in		of Units in		Management		Interest in
Name of Holder	Company		Company (1)		Limited, LLC (2)		EMC
Directors and Executive Officers
William A. Siskovic (officer, Chairman of the Board & director of EMC)		140,354		3.0304		25.00		25.00
Brian A. Staebler (officer and director of EMC)		8292,~~258~~508		12.7701		25.00		25.00
Thomas L. Korner ( director of EMC)		67,897		1.46		25.00		25.00
Thomas L. Korner (director of EMC)		67,897		1.47		25.00		25.00
Michael W. Rathburn (officer and director of EMC)		4353,~~636~~886		01.9417		25.00		25.00
		334,145		7.20		100.00		100.00
		354,645		7.69		100.00		100.00
Other Beneficial Owners of >5% of the Company
Catherine S. Massie (3)		299,848		6.4750		-		-
		633,993		13.67		100.00		100.00
		654,493		14.19		100.00		100.00

(1) Does not include the interest in the Company owned indirectly by such individuals as a result of their ownership in (i) the General Partner (based on its 1.4243% interest in the Company) or (ii) EMC (based on EMC’s 1% managing member’s interest in the General Partner).

(2)	Includes the interest in the General Partner owned indirectly by such individuals as a result of their share ownership in EMC resulting from EMC’s 1% managing member’s interest in the General Partner.

(3)	All Units held by CSM Associates, a New York limited partnership owned by the family of Catherine S. Massie. Catherine S. Massie is not an officer or director of EMC.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

In the past, certain officers, directors and Unitholders who beneficially own more than 10% of the Company have invested in crude oil and natural gas programs sponsored by EEI on the same terms as other unrelated investors in such programs. In the past, certain officers, directors and/or more than 10% Unitholders of the Company have frequently participated and will likely participate in the future as working interest owners in wells in which the Company has an interest. The Company anticipates that any such participation by individual members of the Company’s management would enable such individuals to participate in the drilling and development of undeveloped drill sites on an equal basis with the Company or the particular drilling program acquiring such drill sites, which participation would be on a uniform basis with respect to all drilling conducted during a specified time frame, as opposed to selective participation. Frequently, such participation has been on more favorable terms than the terms which were available to other unrelated investors in such programs. Prior to the Sarbanes-Oxley Act of 2002, EEI loaned the officers of the Company the funds necessary to participate in the drilling and development of such wells. The Company ceased making these loans in compliance with the Sarbanes-Oxley Act of 2002.

The officers and directors of EMC beneficially own working interests in crude oil and natural gas properties, ~~individually~~ and ~~through equally owned membership interests in a limited liability company, and, as such,~~ contract with the Company to provide field operations on ~~such~~certain Company operated properties. These ownership interests are charged per well fees for such services on the same basis as all other working interest owners. ~~The~~of ~~aforementioned~~the ~~limited~~properties. ~~liability~~Officers ~~company~~and ~~did~~directors ~~not~~made ~~make~~beneficial ~~any~~ownership investments of $10,000 during 2025 in one crude oil and natural gas ~~properties~~property inthat ~~2024,~~the ~~however~~Company italso ~~did~~invested ~~make~~in. There were no investments made in crude oil and natural gas properties ~~of $22,400~~ during ~~2023~~2024.

As a result of its organizational structure, the Company does not have a nominating committee or a compensation committee. The Directors of EMC function as the Company’s audit committee. None of the members of EMC’s board are “independent” under the current independence standards of Rule 5605(a)(2) of the Marketplace Rules of The NASDAQ Stock Market. The Company believes that its status as a limited partnership, the limited voting rights possessed by holders of limited partnership units, and the existence of contractual arrangements governing the selection of EMC’s directors and officers makes it appropriate for the Company not to maintain nominating or compensation committees.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Maloney + Novotny LLC served as the Company’s independent auditor for the years ended December 31, ~~2024~~2025 and ~~2023~~2024. The following is a summary of the fees billed to the Company by Maloney + Novotny LLC for professional services rendered during the years ended December 31, ~~2024~~2025 and ~~2023~~2024, respectively.

	December 31,
	2024		2023
	2025		2024
Audit fees	$	~~139~~119,~~800~~600	$	~~144~~139,~~300~~800
Tax consulting fees		3,500		113,~~300~~500
Total	$	~~143~~120,~~300~~100	$	~~155~~143,~~600~~300

Audit fees include fees for the audit and quarterly reviews of the consolidated financial statements, assistance with and review of documents filed with the SEC, accounting and financial reporting consultations and research work necessary to comply with generally accepted auditing standards.

The Company has a policy to assure the independence of its registered public accounting firm. Prior to each fiscal year, the audit committee receives a written report from its independent auditor describing the elements expected to be performed in the course of its audit of the Company’s financial statements for the coming year.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)

(1)

Financial Statements

The following Consolidated Financial Statements of the Registrant and its subsidiaries are included in Part II, Item 8:

	Page(s)

Report of Independent Registered Public Accounting Firm	F-3
Consolidated Balance Sheets	F-5
Consolidated Statements of Operations	F-7
Consolidated Statements of Partners’ Equity	F-8
Consolidated Statements of Cash Flows	F-9
Notes to Consolidated Financial Statements	F-10

(a)

(2)

Financial Statements Schedules

All schedules for which provision is made in the applicable accounting regulation of the SEC are not required under the related instructions or are inapplicable, and therefore have been omitted.

(a)

(3)

Exhibits

See the Exhibit Index at page E-1 of this Annual Report on Form 10-K.

(b) Exhibits required by Item 601 of Regulation S-K

(b)		Exhibits required by Item 601 of Regulation S-K

		Exhibits required to be filed by the Company pursuant to Item 601 of Regulation S-K are contained in the Exhibits listed under Item 15(a)(3).

(c)		Financial Statements Schedules required by Regulation S-X (17 CFR 210)

Exhibits required to be filed by the Company pursuant to Item 601 of Regulation S-K are contained in the Exhibits listed under Item 15(a)(3).

All schedules for which provision is made in the applicable accounting regulation of the SEC are not required under the related instructions or are inapplicable, and therefore have been omitted.

ITEM 16. FORM 10-K SUMMARY

None.

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Exhibit No.		Description


	3.1	Certificate of Limited Partnership of the Registrant dated September 13, 1990, as filed with the Delaware Secretary of State on September 14, 1990	(1)

	3.2	Amended and Restated Agreement of Limited Partnership of the Registrant, dated as of February 10, 2010	(2)

	3.3	Articles of Incorporation of Everflow Management Corporation	(1)

	3.4	Articles of Organization of Everflow Management Limited LLC	(3)

	3.5	Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Everflow Eastern Partners, L.P.	(7)

	3.6	Second Amended and Restated Operating Agreement of Everflow Management Limited LLC dated December 31, 2021	(8)

	3.7	Second Amended and Restated Close Corporation Agreement of Everflow Management Corporation dated December 31, 2021	(9)

	4.1	Description of Securities

	10.1	Operating facility lease dated October 3, 1995 between Everflow Eastern Partners, L.P. and A-1 Storage of Canfield, Ltd.	(4)

	14.1	Code of Ethics

	21.1	Subsidiaries of the Registrant	(5)

	31.1	Certification of CEO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

	31.2	Certification of CFO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

	32.1	Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

	99.1	Report of Wright & Company, Inc. dated February 3, 2026 concerning evaluation of oil and gas reserves.

	99.2	Audit Committee Charter of Everflow Management Corporation	(6)

Exhibit No.	Description
3.1	Certificate of Limited Partnership of the Registrant dated September 13, 1990, as filed with the Delaware Secretary of State on September 14, 1990	(1)
3.2	Amended and Restated Agreement of Limited Partnership of the Registrant, dated as of February 10, 2010	(2)
3.3	Articles of Incorporation of Everflow Management Corporation	(1)
3.4	Articles of Organization of Everflow Management Limited LLC	(3)
3.5	Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Everflow Eastern Partners, L.P.	(7)
3.6	Second Amended and Restated Operating Agreement of Everflow Management Limited LLC dated December 31, 2021	(8)
3.7	Second Amended and Restated Close Corporation Agreement of Everflow Management Corporation dated December 31, 2021	(9)
4.1	Description of Securities
10.1	Operating facility lease dated October 3, 1995 between Everflow Eastern Partners, L.P. and A-1 Storage of Canfield, Ltd.	(4)
14.1	Code of Ethics
21.1	Subsidiaries of the Registrant	(5)
31.1	Certification of CEO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certification of CFO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1	Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1	Report of Wright & Company, Inc. dated March 4, 2025 concerning evaluation of oil and gas reserves.
99.2	Audit Committee Charter of Everflow Management Corporation	(6)

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Exhibit No.		Description

	101.INS	Inline Instance Document

	101.SCH	Inline XBRL Taxonomy Extension Schema Document

	101.CAL	Inline XBRL Taxonomy Extension Calculation Linkbase Document

	101.DEF	Inline XBRL Taxonomy Extension Definition Document

	101.LAB	Inline XBRL Taxonomy Extension Label Linkbase Document

	101.PRE	Inline XBRL Taxonomy Extension Presentation Linkbase Document

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

(1) Incorporated herein by reference to the appropriate exhibit to Registrant's Registration Statement on Form S-1 (Reg. No. 33-36919).


(1)	Incorporated herein by reference to the appropriate exhibit to Registrant's Registration Statement on Form S-1 (Reg. No. 33-36919).

(2)	Incorporated herein by reference to the appropriate exhibit to the Registrant’s Current Report on Form 8-K dated February 12, 2010 (File No. 0-19279).

(3)	Incorporated herein by reference to the appropriate exhibit to the Registrant’s Quarterly Report on Form 10-Q for the first quarter ended March 31, 1999 (File No. 0-19279).

(4)	Incorporated herein by reference to the appropriate exhibit to the Registrant's Quarterly Report on Form 10-Q for the third quarter ended September 30, 1995 (File No. 0-19279).

(5)	Incorporated herein by reference to the appropriate exhibit to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1995 (File No. 0-19279).

(6)	Incorporated herein by reference to the appropriate exhibit to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2014 (File No. 0-19279).

(7)	Incorporated herein by reference to the appropriate exhibit to the Registrant's Quarterly Report on Form 10-Q for the first quarter ended March 31, 2018 (File No. 0-19279).

(8)	Incorporated herein by reference to the appropriate exhibit to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2021 (File No. 0-19279).

(9)	Incorporated herein by reference to the appropriate exhibit to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2021 (File No. 0-19279).

(2) Incorporated herein by reference to the appropriate exhibit to the Registrant’s Current Report on Form 8-K dated February 12, 2010 (File No. 0-19279).

(3) Incorporated herein by reference to the appropriate exhibit to the Registrant’s Quarterly Report on Form 10-Q for the first quarter ended March 31, 1999 (File No. 0-19279).

(4) Incorporated herein by reference to the appropriate exhibit to the Registrant's Quarterly Report on Form 10-Q for the third quarter ended September 30, 1995 (File No. 0-19279).

(5) Incorporated herein by reference to the appropriate exhibit to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1995 (File No. 0-19279).

(6) Incorporated herein by reference to the appropriate exhibit to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2014 (File No. 0-19279).

(7) Incorporated herein by reference to the appropriate exhibit to the Registrant's Quarterly Report on Form 10-Q for the first quarter ended March 31, 2018 (File No. 0-19279).

(8) Incorporated herein by reference to the appropriate exhibit to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2021 (File No. 0-19279).

(9) Incorporated herein by reference to the appropriate exhibit to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2021 (File No. 0-19279).

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Table of Contents

SIGNATURES

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

EVERFLOW EASTERN PARTNERS, L.P.

By:	EVERFLOW MANAGEMENT LIMITED, LLC
	General Partner

By:	EVERFLOW MANAGEMENT CORPORATION
	Managing Member

By:	/s/ Brian A. Staebler	President, Principal	March 26, 2026	~~March 25, 2025~~
	Brian A. Staebler	Executive Officer and
		Director
By:	/s/ Michael W. Rathburn	Vice President, Secretary -		March 25, 2025
	Michael W. Rathburn	Treasurer, Principal
		Financial and Accounting
		Officer and Director
By:	/s/ William A. Siskovic	Vice President, Principal		March 25, 2025
	William A. Siskovic	Operations Officer and
		Director
By:	/s/ Thomas L. Korner	Director		March 25, 2025
	Thomas L. Korner

By:	/s/ Michael W. Rathburn	Vice President, Secretary-	March 26, 2026
	Michael W. Rathburn	Treasurer, Principal
		Financial and Accounting
		Officer and Director

By:	/s/ William A. Siskovic	Vice President, Principal	March 26, 2026
	William A. Siskovic	Operations Officer and
		Director

By:	/s/ Thomas L. Korner	Director	March 26, 2026
	Thomas L. Korner

Filing Compare · EVERFLOW EASTERN PARTNERS LP