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 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.

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.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 63%40% of the estimated total future cash inflows related to the Company’s crude oil and natural gas reserves as of December 31, 20172023 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 443444 (net) wells. The Company serves as the operator of approximately 59%72% of the gross wells and 76%89% of the net wells which comprise the Company’s properties as of December 31, 2017.during the year 2023.

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.

SalesSales 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.”

Acquisition of Prospects.   TheFrom 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. The Company makes additions to such leasehold inventory on an on-going basis. The Company may also acquire leases from third parties. Prior to 2000, EEI generated approximately 90% of the prospects which were drilled. Beginning inSince 2000, the Company began generating fewer prospects and has participated in more joint ventures with other operators. As of December 31, 2017,2023, the Company’s currentCompany has no leasehold inventory consists of approximately 22 prospects in various stages of maturity representing approximately 14 net acres under lease.inventory.

In choosing oil and gas prospects for the Company, the General Partner does not attempt to manage the risks of drilling through a policy of selecting diverse prospects in various geographic areas or with the potential of oil and gas production from different geological formations. Rather, substantially all prospects are expected to be located in the Appalachian Basin of Ohio and Pennsylvania and are to be drilled primarily to the Clinton/Medina Sands geological formation or closely related oil and gas formations in such area. The Company also has the right to participate in the development of certain wells in the Utica geological formation with various joint venture partners. TheIn 2022, the Company does not currentlyelected to participate in the operationdevelopment of suchfour wells in the Utica geological formation. The wells were completed and has not yet determined whether, or to what extent, it might exercise its right to do so.put into production during 2023.

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 ongoingpotential leasehold acquisition and development activities. The Company did not acquire any producing oil and gas properties during 20172023 or 2016.2022.

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 financeshas 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 suchfuture indebtedness would consist primarily of borrowings from commercial banks. The Company and EEI had no new borrowings during 2017in 2022 or 20162023 and no principal indebtedness was outstanding as of March 10, 2018.11, 2024. 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 (the(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“MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Liquidity and Capital Resources.”

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, 2017,2023, net of asset retirement obligations, which aggregate a net liability of $5,054,000$3,741,000 (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. Generally, purchase contracts for the sale of crude oil are cancelable on 30 days’ notice. The price paid by these purchasers is generally an established or “posted” price which is offered to all producers.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 20172023 and 2016.2022.

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, 2018, $58.0411, 2024, $73.93 per barrel was the postedprevailing 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, 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 Ergon Oil Purchasing, Inc.one oil purchaser.

Natural Gas.   The deliverability and price of 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, 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 have occurred as a result of distribution system restrictions.

Over the ten years prior to 2002, the Company had followed a practice of selling a significant portion of its natural gas pursuant to Intermediate Term Adjustable Price Gas Purchase Agreements (the “East Ohio Contracts”) with Dominion Field Services, Inc. and its affiliates (“Dominion”) (including The East Ohioone gas purchaser (the “Major Gas Company)Purchaser”). Pursuant to the East Ohio Contracts and subject to certain restrictions and adjustments, including termination clauses, Dominionthe Major Gas Purchaser was obligated to purchase, and the Company was obligated to sell, all natural gas production from a specified list of wells. Pricing under the East Ohio Contracts was adjusted annually, up or down, by an amount equal to 80% of the increase or decrease in Dominion’sthe Major Gas Purchaser’s average Gas Cost Recovery rates.

Since 2002, the Company has had and continues to have multiple annual or biennial contracts with Dominion,various gas purchasers, including the Major Gas Purchaser, which obligate Dominionobligated 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, 2018, the Company did not have any significant quantities of natural gas volumes locked-in with Dominion.

The Company also has had and continues to have multiple annual or biennial contracts with Interstate Gas Supply, Inc. (“IGS”), which obligates IGS 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, 2018, the Company did not have any significant quantities of natural gas volumes locked-in with IGS.

As detailed above, the price paid for natural gas purchased by Dominion and IGSthe 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 2017,2023, natural gas purchased by Dominionthe Major Gas Purchaser covered production from approximately 500 gross operated wells, while natural gas purchased by IGS covered production from approximately 160560 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.

During 2017,2023, no one natural gas purchaser accounted for more than 10% of the Company’s natural gas sales other than Dominion and IGS,the Major Gas Purchaser, whose purchases of natural gas from operated wells accounted for approximately 60% and 16%, respectively,66% of the Company’s consolidated natural gas sales. The Company expects that Dominion and IGSthe Major Gas Purchaser will be the only material natural gas purchaserspurchaser during fiscal year 2018.2024.

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 of 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 2017,2023, 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.

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 Dominion and IGSthe 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.

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.

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 ConsiderationsConsiderations. 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 itsand 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 ourthe 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.

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, 2018, the Company11, 2024, EEI had 17 full-time and 42 part-time employees. These employees are primarily are engaged in the following areas of business operations: eightseven in general administration, six in accounting, fourfive in field operations, five in accounting and threetwo in land and lease acquisition.administration.

ITEM 1A.          RISK FACTORS

Not a required disclosure for a Smaller Reporting Company.

Item 1b.              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.

ItemITEM 2.                  Properties         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 $2.09$1.75 and $1.41$5.33 per MCF at December 31, 20172023 and 20162022 respectively, and the crude oil prices used in the estimation of proved reserves were $47.48$74.71 and $39.33$90.29 per BBL at December 31, 20172023 and 2016,2022, 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 ourthe 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, 2017,2023, 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 3540 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, 2017.2023. 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.

Reserves Reported to Other Agencies. There were no estimates of total, proved net oil or gas reserves filed with or included in reports to any other federal authority or agency during 20172023 or 2016.2022.

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, 2017.2023.

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 20172023 and 2016.2022.

Productive Wells.   The following table sets forth the gross and net oil and gas wells of the Company as of December 31, 2017.2023.

Standardized Measure of Discounted Future Net Cash Flows.Flows.⁽¹⁾ The following table summarizes, as of December 31, 2017,2023, 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, 2017,2023, discounted to present value at 10%.

Acreage.   The Company had approximately 58,40045,200 gross developed acres and 37,80029,700 net developed acres as of December 31, 2017.2023. Developed acreage is that acreage assignable to productive wells. The Company had approximately 14 gross and net proved undevelopedheld no unproved acres as ofat December 31, 2017.2023.

Drilling Activity.   The following table sets forth the results of drilling activities during 20172023 and 2016 on properties owned by the Company.2022. Such information and the results of prior drilling activities should not be considered as necessarily indicative of future performance.activities.

Present Activities. The Company has not participated in the drilling of any wells since December 31, 2017. 2023.

Delivery Commitments. The Company has entered into various contracts with Dominion and IGSthe Major Gas Purchaser, which, subject to certain restrictions and adjustments, obligate Dominion and IGSthe 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 76%66% of the Company’s consolidated natural gas sales during 2017.2023. 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.

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 ITEMSUPPLEMENTAL ITEM — EXECUTIVE OFFICERSOF THE REGISTRANTINFORMATION ABOUT OUR EXECUTIVE OFFICERS

The executive officers of EEI and EMC as of March 10, 201824, 2024 are as follows:

William A. Siskovic has served asStaebler, 49, President and Principal Executive Officer of EEI and EMC since January 2010. Brian A. Staebler has served asdirector; Michael W. Rathburn, 40, Vice President, Secretary-Treasurer, Principal Financial and Accounting Officer and directordirector; William A. Siskovic, 68, 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 January 2010. March 2021.

PART II

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, 2018,11, 2024, there were 5,587,6164,746,686 Units held by 1,3941,159 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 hasdid 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 since October 2015.in 2021. The Company paid total cash distributions equal to $1.00 per Unit in 2022 and $0.50 per Unit in 2023. The Company intends to make a cash distribution equal to $0.20 per Unit in April 2024.

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 121,354 of its Units of limited partnership interest at a price of $2.51 per Unit pursuant to be paid for any such Units is calculated based on the method provided for interms of the Partnership Agreement.Company’s Offer to Purchase dated April 30, 2022. The Company did not offeraccepted an aggregate of 526,433 of its Units of limited partnership interest at a price of $6.36 per Unit pursuant to purchase Units in 2016 or 2017, as it had determined that the prices associated withterms of the 2016 and 2017 Repurchase Rights, based upon the December 31, 2015 and 2016 calculations, respectively, were negative.Company’s Offer to Purchase dated April 30, 2023. The Company has determined that the price associated with the 20182024 Repurchase Right, based upon the December 31, 20172023 calculation, is estimated to be $0.11$1.46 per Unit. See Note 3 in the Company’s consolidated financial statements for additional information on the Repurchase Right.

Not a required disclosure for a Smaller Reporting Company.ITEM 6.            [RESERVED]

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.company, Everflow Management Limited LLC (“EML”). The members of the General Partner are Everflow Management Corporation, an Ohio Corporation ("EMC"); twothree individuals who are officers and directors of EEI, Brian A. Staebler, Michael W. Rathburn and William A. Siskovic and Brian A. Staebler; one individual who serves as the Chairman of the Board of EEI, Thomas L. Korner; one individual who is an employee of the Company, Richard M. Jones; and one New York limited liability company founded by an individual who is a director of EEI, Robert F. Sykes, and owned byThomas L. Korner. Mr. Siskovic also serves as Chairman of the four adult childrenBoard of Mr. Sykes.EEI.

Liquidity and Capital Resources

Financial Position

The following table summarizes the Company’s financial position at December 31, 20172023 and December 31, 2016:2022:

Working capital surplus of $22.8$34.1 million as of December 31, 20172023 represented a $3.2$3.1 million increasedecrease from December 31, 20162022 due primarily to increasesdecreases in investments, cash and equivalents and production accounts receivable, from production, offset somewhat by increasesan increase in investments. The decrease in cash and equivalents is primarily the result of cash used in investing and financing activities during 2023, offset somewhat by cash provided by operating activities. The decrease in production accounts payablereceivable is the combined result of lower natural gas prices received and accrued expenses.a decrease in natural gas volumes produced during the current receivable production period as compared to the prior comparable production period. The decrease in natural gas volumes produced is primarily the result of additional Company operated properties being voluntarily shut-in during the current receivable production period that were otherwise producing during the prior comparable production period. 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 cash and equivalents is primarily the result of cash provided by operating activities during 2017, offset somewhat by cash used in investing activities. The increase in accounts receivable from production is the combined result of increases in natural gas volumes produced and higher crude oil and natural gas prices received during the current receivable production period as compared to the prior comparable receivable production period. The increase in accounts payable is primarily due to an increase in production and other related payables due. The increase in accrued expenses is primarily the result of additional asset retirement obligations being classified as current liabilities as well as additional costs accrued for drilling of oil and gas properties.

Property and equipment of $9.5$6.6 million as of December 31, 20172023 represented a $746,000$1.4 million decrease from December 31, 20162022 due primarily to $1.0$1.7 million of depreciation, depletion and amortization (“DD&A”) recognized in 2017,during 2023, offset somewhat by $221,000$200,000 of new purchases.additions to oil and gas properties.

Long-term liabilities of $19.7 million as of December 31, 2023 represented a $1.1 million increase from December 31, 2022 due primarily to accretion associated with asset retirement obligations during 2023.

Long-term liabilitiesPartner’s equity of $18.1$21.2 million as of December 31, 20172023 represented an increasea decrease of $311,000$5.6 million from December 31, 20162022 due primarily to an increasea Unitholder distribution paid in operational advances,April 2023 and the repurchase of limited partnership Units related to the 2023 Repurchase Right paid in July 2023, offset somewhat by a decrease in the long-term portion of asset retirement obligations. The decrease in the long-term portion of asset retirement obligations is almost entirely the result of additional asset retirement obligations being classified as current at December 31, 2017, as compared to the prior comparable reporting date, the effect of which is offset somewhat by accretion expense recognized in 2017 to adjust the liabilities to their present value at December 31, 2017.year net income.

TheIn 2022 and 2023, the Company has not held ahad no new borrowings or credit facility with a bank since 2003, nor has it had any borrowings since that time.bank. The Company expects to have more than $70,000 ofadequate cash available to fund the Repurchase Right in 2018.2024. 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.

Cash Flows from Operating, Investing and Financing Activities

Cash provided by the Company’s operating activities was used in investing activities during 2017. The Company usedand existing cash and equivalents were used in investing activities and operating activities during 2016. The Company did not use any cash in financing activities during 2017 or 2016.

2023 and 2022. The following table summarizes the Company’sCompany’s Consolidated Statements of Cash Flows for the years ended December 31, 20172023 and 2016:2022:

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 during 2017of $3.1 million represented 100%42% of total cash sources provided whereasduring 2023, and the Company’s cash flow from operations before working capital changes during 2016 resulted in a 5% useof $9.8 million represented 98% of total cash sources.sources provided during 2022. The increasedecrease in cash flow from operations before working capital changes as a percentage of total cash sources in 2017,2023, as compared to the prior comparable period, was primarily due to higherless crude oil and natural gas sales, net of increaseddecreased production costs less general administrative expenses incurred and additional operational advances collectedincreases in DD&A and accretion expense recognized during 20172023 as compared to 2016.2022. Changes in working capital other than cash and equivalents decreasedincreased cash by $15,000$655,000 and $626,000$203,000 during 20172023 and 2016,2022, respectively. The $626,000 decrease$655,000 in cash resulting fromprovided by changes in working capital other than cash and equivalents in 20162023 was primarily the result of a decrease in production accounts receivable, offset somewhat by an increase in other current assets. The decrease in production accounts receivable from productionis primarily the combined result of lower average natural gas prices received and a decrease in accounts payable. The increase in accounts receivable from production was the combined result of increases in crude oil and natural gas volumes produced and higher crude oil and natural gas prices received during the current receivable production period as compared to the prior comparable receivable production period. The decrease in accounts payable wasnatural gas volumes produced is primarily the result of lessadditional Company operated properties being voluntarily shut-in during the current receivable production and related other payables outstanding at December 31, 2016 as compared toperiod that were otherwise producing during the prior comparable reporting date.production period. The increase in other current assets is primarily related to refundable Federal payroll credits applied for by the Company in 2023.

The Company used cash in investing activities of $2.9$1.5 million and $10.3$3.7 million in 20172023 and 2016,2022, respectively. The $7.4 million decrease in cash used in investing activities was primarily the result of less cash used for purchases of investments made in 20172023 as compared to those made in the prior comparable period, as well as additional proceeds received during 2017 from disposal of property and equipment and sales of other assets.period.

The Company did not have anyused cash flows fromin financing activities during 2017 or 2016.of $5.8 million and $5.6 million in 2023 and 2022, respectively. The increase in cash used in financing activities was primarily the result of additional cash used to fund the 2023 Repurchase Right, offset by less cash distributions paid to Unitholders in 2023 as compared to the prior comparable period.

The Company’s ending cash and equivalents balance of $11.9$9.6 million at December 31, 2017,2023, as well as on-going monthly operating cash flows, should be adequate to meet short-term cash requirements. The Company has not madeintends to make a $0.20 per Unit cash distribution to Unitholders since October 2015.in April 2024.

The Company participated in the drilling of twofour new oil and gas properties during 2017.in 2023. The Company’s share of proved gas reserves increaseddecreased by 6.013.8 BCF, or 113%63%, between December 31, 20162022 and December 31, 2017,2023, while proved oil reserves increaseddecreased by 46,000 barrels,111,000 BBLS, or 19%28%, between December 31, 20162022 and December 31, 2017.2023. The Standardized Measure of Discounted Future Net Cash Flows of the Company’s reserves increaseddecreased by $4.9$38.3 million between December 31, 20162022 and December 31, 2017.2023. The primary reasons for this increasedecrease were due to increasesdecreases in average natural gas and crude oil prices in 2017,2023, as compared to the prior comparable period, and the related upwarddownward revisions in quantities of natural gas and crude oil reserves between December 31, 20172022 and 2016. Management is uncertain at this point if the Company will drill any new wells during 2018, though it is possible that the Company will participate in the drilling2023.

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 did not offeraccepted an aggregate of 121,354 of its Units of limited partnership interest at a price of $2.51 per Unit pursuant to repurchase anythe terms of the Company’s Offer to Purchase dated April 30, 2022. The Company accepted an aggregate of 526,433 of its Units during 2017 or 2016.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 has determined that the price associated with the 20182024 Repurchase Right, based upon the December 31, 20172023 calculation, is estimated to be $0.11$1.66 per Unit.Unit, net of a $0.20 per Unit distribution expected to be made in April 2024.

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, 20172023 and 2016.2022. 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:

Revenues for the year ended December 31, 2017 increased $3.82023 decreased $8.4 million, or 97%58%, compared to the prior comparable period. This increasedecrease was due primarily to an increasedecrease in crude oil and natural gas sales during 20172023 as compared with 2016.to 2022.

Crude oil and natural gas sales increased $3.6decreased $8.2 million, or 106%60%, from 20162022 to 2017.2023. This increasedecrease was the combined result of increases indue primarily to lower average natural gas and crude oil prices received and less natural gas volumes produced and higher crude oil and natural gas prices received during 20172023 as compared to 2016.2022. The Company’s natural gas production increaseddecreased by 747,000654,000 MCF, or 65%, while crude oil production increased by 6,000 BBLS, or 18%, from 2016 to 2017.35%. The primary reason for the increasedecrease in crude oil and natural gas volumes produced during 20172023 as compared to 2016 is the2022 was a result of lessmore Company operated oil and gas properties being voluntarily shut-in during 20172023 as compared to the prior comparable period. The average price received per MCF of natural gas increaseddecreased from $1.81$5.66 in 20162022 to $2.72$2.49 in 2017.2023. The average price received per BBL of crude oil increaseddecreased from $39.67$91.46 in 20162022 to $47.12$74.29 in 2017.2023. Natural gas sales accounted for 73%55% and 61%78% of total crude oil and natural gas sales in 20172023 and 2016,2022, respectively.

Production costsDD&A increased $27,000, or 1%, from 2016 to 2017. This increase was primarily due to additional operating fees, chart integration costs and repairs and maintenance expenses incurred relative to more properties being online during 2017 that were otherwise shut-in during the prior comparable period. The effect of these additional costs was offset significantly by reductions in ad valorem taxes, in lieu of free gas payments and third party operated well expenses from 2016 to 2017.

Depreciation, depletion and amortization decreased $3.8$1.2 million, or 80%,341% from 20162022 to 2017.2023. The Company did not recognize any write down/impairment and abandonment (“Impairment and Abandonment”) of crude oil and natural gas properties during 2017, as compared to $88,000 recognized during 2016. The primary reasons for the decrease in DD&A and Impairment and Abandonment are less depletable bases of oil and gas properties available to deplete during 2017 as compared to the prior comparable period and higher natural gas and crude oil reserves at December 31, 2017 as compared to the prior valuation date, December 31, 2016, the effects of which are offset somewhat by an increase in natural gas and crude oil volumes produced during 2017 as compared to 2016. Less depletable bases of oil and gas properties is primarily the result of $30.3 million of DD&A and Impairment and Abandonment recognized from 2014 through 2016. The increasea decrease in natural gas and crude oil reserves as of the most recent valuation date, December 31, 2023, as compared to the prior valuation dates, December 31, 2022. The decreased natural gas and crude oil reserves from 20162022 to 20172023 was primarily the result of significantly higherlower natural gas and crude oil prices used to value reserves at December 31, 20172023 as compared to the prior comparable valuation date. The higherlower natural gas and crude oil prices contributed to increasingdecreasing the average economic life of the Company’s oil and gas properties at December 31, 2017, as compared to thetheir prior valuation date. Also in conjunction withThe effect of the substantial increases in prices and increases in average economic lives of properties, projected future cash flows associated with thedecreased natural gas and crude oil reserves as of December 31, 2017 increased significantly as compared to those projected at the prior valuation date.

Accretion expense decreased $38,000, or 10%, from 2016 to 2017. The primary reason for this decreaseon DD&A was due to more asset retirement obligations being fully accreted at January 1, 2017 as compared to January 1, 2016, which resulted inoffset somewhat by less discounted asset retirement obligations available to accretenatural gas volumes produced during 2017 as compared to the prior comparable period.

General and administrative expense decreased $83,000, or 4%, from 2016 to 2017. The primary reasons for this decrease are less legal costs incurred during 2017 as compared to the prior comparable period as well as cost-cutting measures management has implemented.

The Company recognized other income of $403,000 during 2017 as compared to $92,000 of other income recognized during the prior comparable period. Other income recognized during 2017 included $80,000 of gains associated with disposal of property and equipment and a $176,000 gain associated with a sale of other assets. In addition, interest and dividend income increased $54,000, or 59%, during 20172023 as compared to the prior comparable period. In addition, the Company recognized $1.3 million of additions to proved properties at December 31, 2022 in association with revisions made to estimates of plugging costs, remaining lives of wells and the inflation rate associated with asset retirement obligations.

Accretion expense increased $1.0 million, or 528% from 2022 to 2023. The increase is primarily due to additional accretion expense associated with the recognition of additional liabilities at December 31, 2022 resulting from revisions made to estimates of plugging costs, remaining lives of wells and the inflation rate associated with asset retirement obligations.

Other income increased $1.7 million during 2023, from $337,000 in 2022. The increase was primarily a result of increases in investment income and other income during 2023 as compared to 2022. The increase in interest andinvestment income is primarily due to higher dividend income was primarily the result of additional investments held and the related dividendsrates yielded on investments during 20172023 as compared to 2022. The increase in other income was due to a refundable Federal payroll tax credit, the prior comparable period.Employee Retention Credit (“ERC”), applied for by the EEI during 2023. The ERC was created by the Coronavirus Aid, Relief and Economic Security Act.

The Company reported net income of $2.1$222,000 and $9.1 million during 2017, as compared to a $6.0 million net loss recognized2023 and 2022, respectively, representing 4% and 64% of total revenues during the prior comparable period.2023 and 2022, respectively. The primary reasons for the increasedecrease in reported net income are increasesa decrease in crude oil and natural gas sales, and other income and decreasesincreases in DD&A Impairment and Abandonment and general and administrative expense. Net income represented 27% of total revenues during 2017, whereas the 2016 net loss represented 154% of total revenues during 2016.accretion expense, offset somewhat by an increase in other income.

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 $890,000$1.5 million and $4.7 million$288,000 during 20172023 and 2016,2022, 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.

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.income or increase net loss. The Company did not recognize any Impairment and Abandonmentimpairment during 2017, whereas $88,000 of Impairment and Abandonment was recognized during 2016 to provide for impairment and abandonment on certain of its crude oil and natural gas properties.2023 or 2022.

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, 2022, the Company made revisions in estimates of plugging costs, lives of wells and the inflation rate. The revisions increased the liability by $1.3 million at December 31, 2022.

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, 20172023 or 2016.2022. 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.

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 and notes receivable from joint venture partners, and employeesif applicable, consist principally of drilling and development costs the Company has advanced or incurred on behalf of joint venture partners and employees.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.

Commodity Pricing, Risk Management Activities and Inflation

The Company’sCompany’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, 2018, $58.0411, 2024, $73.93 per barrel was the postedprevailing 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 20172023 was $2.72$2.49 per MCF, an increasea decrease of $0.91$3.17 per MCF as compared to 2016.2022. The Company’s average price of natural gas during 20162022 was $1.81$5.66 per MCF, a decreasean increase of $0.48 per MCF$2.38 as compared to 2015.2021. The Company’s average price of natural gas during 20152021 was $2.29$3.28 per MCF, an increase of $1.43 per MCF as compared to 2020. The Company’s average price of natural gas during 2020 was $1.85 per MCF, a decrease of $1.44$0.94 per MCF as compared to 2014.2019. 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 20182024 at $2.64$1.62 per MCF and the regional basis adjustment settled for the month of March 20182024 at $(0.54)$(0.43) per MCF, resulting in a net regional market price of $2.10$1.19 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 the Company’s contracts with two gas purchasers, 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, 2018, the Company did not have any significant quantities of natural gas volumes locked-in with any of its gas purchasers.

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, decreasingincreasing from $60.6 million at December 31, 2011 to $33.5 million at December 31, 2012, increasing to $41.7 million at December 31, 2013, decreasing to $28.2 million at December 31, 2014, decreasing to $(8.2) million at December 31, 2015, decreasing to $(9.9) million at December 31, 2016 and increasing to $(5.1) million at December 31, 2017.2017, increasing 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 and decreasing to $(3.7) million at December 31, 2023.

The Company’s Standardized Measure of Discounted Future Net Cash Flows increaseddecreased by $4.8$38.3 million from December 31, 20162022 to December 31, 2017.2023. A reconciliation of the Changes in the Standardized Measure of Discounted Future Net Cash Flows is included in the Company’s consolidated financial statements.

Not a required disclosure for a Smaller Reporting Company.

ItemITEM 8.              Financial Statements and SupplementaRY Data         FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

See attached pages F-1 to F-25.F-23.

EVERFLOW EASTERN PARTNERS, L. P.

20172023 CONSOLIDATED FINANCIAL REPORT

EVERFLOW EASTERN PARTNERS, L. P.

CONSOLIDATED BALANCE SHEETS

December 31, 2023 and 2022

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

EVERFLOW EASTERN PARTNERS, L. P.

CONSOLIDATED BALANCE SHEETS

December 31, 2023 and 2022

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

EVERFLOW EASTERN PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

Years Ended December 31, 2023 and 2022

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

EVERFLOW EASTERN PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF PARTNERS' EQUITY

Years Ended December 31, 2023 and 2022

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

EVERFLOW EASTERN PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

Years Ended December 31, 2023 and 2022