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 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 69% of the estimated total future cash inflows related to the Company’s crude oil and natural gas reserves as of December 31, 2021 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 72% of the gross wells and 89% of the net wells which comprise the Company’s properties during the year 2021.

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.

In March 2020, the World Health Organization declared the outbreak of the novel strain of the coronavirus (“COVID-19”) a global pandemic. COVID-19 has led to global shutdowns as governments imposed, and continue to impose, regulations in efforts to control the spread of COVID-19. As a result, physical and economic uncertainties have arisen which have at times negatively impacted the Company’s operations, cash flows and financial position.

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.”

Acquisition of Prospects.   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 in 2000, the Company began generating fewer prospects and has participated in more joint ventures with other operators. As of December 31, 2021, the Company’s current leasehold inventory consists of approximately 20 prospects in various stages of maturity representing less than 100 net acres under lease.

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.  The Company does not currently participate in the operation of such wells, and has not yet determined whether, or to what extent, it might exercise its right to do so.

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 ongoing leasehold acquisition and development activities. The Company did not acquire any producing oil and gas properties during 2021 or 2020.

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. In April 2020, EEI received an unsecured loan of approximately $327,000 through a commercial bank under the United States Small Business Administration’s (the “SBA”) Paycheck Protection Program (the “PPP Loan”), which provided employers relief in response to COVID-19. The PPP Loan was forgiven by the SBA in February 2021. It is currently anticipated that any future indebtedness would consist primarily of borrowings from commercial banks. The Company and EEI had no other borrowings since the PPP Loan and no principal indebtedness was outstanding as of March 10, 2022. 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.”

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, 2021, net of asset retirement obligations, which aggregate to $6,776,000 (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. 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 2021 and 2020.

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, 2022, $102.02 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 the conflict in Ukraine and related sanctions on Russia, 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.

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, increased industrial and commercial energy consumption, global supply chain issues, regulatory actions and executive orders issued by the federal government resulted in a shortage in natural gas supplies. This resulted in increases 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 one gas purchaser (the “Major Gas Purchaser”). Pursuant to the East Ohio Contracts and subject to certain restrictions and adjustments, including termination clauses, the 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 the Major Gas Purchaser’s average Gas Cost Recovery rates.

Since 2002, the Company had multiple annual or biennial contracts with the Major Gas Purchaser, which obligated 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, 2022, the Company has elected to lock-in 380,000 MCF from March 2022 to March 2023 at a weighted average price of $3.93 per MCF, net of regional basis adjustments.

As detailed above, the price paid for natural gas purchased by the Major Gas Purchaser 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 2021, natural gas purchased by the Major Gas Purchaser covered production from approximately 580 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 2021, 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 82% 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 2022.

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 2021, 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 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.

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 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.

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, 2022, EEI had 17 full-time and 1 part-time employee. These employees are primarily engaged in the following areas of business operations: seven in general administration, five in field operations, four in accounting and two 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 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 $2.94 and $1.46 per MCF at December 31, 2021 and 2020 respectively, and the crude oil prices used in the estimation of proved reserves were $63.16 and $36.30 per BBL at December 31, 2021 and 2020, 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 our 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, 2021, 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 40 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, 2021. 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 2021 or 2020.

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, 2021.

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 2021 and 2020.

Productive Wells.   The following table sets forth the gross and net oil and gas wells of the Company as of December 31, 2021.

Standardized Measure of Discounted Future Net Cash Flows.⁽¹⁾ The following table summarizes, as of December 31, 2021, 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, 2021, discounted to present value at 10%.

Acreage.   The Company had approximately 44,500 gross developed acres and 30,100 net developed acres as of December 31, 2021. Developed acreage is that acreage assignable to productive wells. The Company had less than 100 gross and net proved undeveloped acres as of December 31, 2021.

Drilling Activity.   The Company was not involved in any drilling activities during 2021 or 2020. Such information and the results of prior drilling activities should not be considered as necessarily indicative of future activities.

Present Activities.   The Company has not participated in the drilling of any wells since December 31, 2021.

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 82% of the Company’s consolidated natural gas sales during 2021. 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, 2022 are as follows: Brian A. Staebler, 47, President and Principal Executive Officer and director of EEI and EMC; Michael W. Rathburn, 38, Vice President, Secretary-Treasurer, Principal Financial and Accounting Officer and director; William A. Siskovic, 66, Vice President and Principal Operations Officer and director since March 2021. The executive officers of EEI and EMC have served their respective positions since March 2021.

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, 2022, there were 5,334,473 Units held by 1,234 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 paid cash distributions equal to $0.25 per Unit in April 2020. The Company intends to make a cash distribution equal to $0.50 per Unit in April 2022 and future distributions as cash flows warrant.

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 81,039 of its Units of limited partnership interest at a price of $0.86 per Unit pursuant to the terms of the Company’s Offer to Purchase dated April 30, 2020. The Company accepted an aggregate of 137,455 of its Units of limited partnership interest at a price of $0.36 per Unit pursuant to the terms of the Company’s Offer to Purchase dated April 30, 2021. The Company has determined that the price associated with the 2022 Repurchase Right, based upon the December 31, 2021 calculation, is estimated to be $2.51 per Unit. See Note 3 in the Company’s consolidated financial statements for additional information on the Repurchase Right.

ITEM 6.        SELECTED FINANCIAL DATA

Not a required disclosure for a Smaller Reporting Company.

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 serves as the Chairman of the Board of EEI, Thomas L. Korner.

Liquidity and Capital Resources

Financial Position

The following table summarizes the Company’s financial position at December 31, 2021 and December 31, 2020:

Working capital surplus of $33.5 million as of December 31, 2021 represented a $6.0 million increase from December 31, 2020 due primarily to increases in cash and equivalents, investments and production accounts receivable and decreases in accounts payable and accrued expenses. The increase in cash and equivalents is primarily the result of cash provided by operating activities during 2021, offset somewhat by cash used in investing and financing activities. 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 primarily the combined result of higher average natural gas and crude oil prices received and an increase in natural gas volumes produced during the current receivable period as compared to the prior comparable period. The increase in natural gas volumes produced is primarily the result of less operated oil and gas properties being voluntarily shut-in during the current receivable period as compared to the prior comparable period. The decrease in accounts payable is primarily the result of a decrease in payables associated with the disposal of various oil and gas properties, offset somewhat by an increase in production and related other payables. The decrease in accrued expenses is primarily the result of less current asset retirement obligations at December 31, 2021 as compared to the prior comparable reporting date and the forgiveness of the PPP Loan.

Property and equipment of $6.8 million as of December 31, 2021 represented a $500,000 decrease from December 31, 2020 due primarily to $443,000 of depreciation, depletion and amortization (“DD&A”) recognized during 2021.

In April 2020, EEI received a PPP Loan of approximately $327,000. The PPP Loan was forgiven by the SBA in February 2021. Prior to receiving the PPP Loan, the Company had not held a credit facility with a bank since 2003, nor has it had any additional borrowings since receipt of the PPP Loan. The Company expects to have adequate cash available to fund the Repurchase Right in 2022. 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 and existing cash and equivalents were used in investing and financing activities during 2021 and 2020. The following table summarizes the Company’s Consolidated Statements of Cash Flows for the years ended December 31, 2021 and 2020:

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 $5.5 million represented 100% of total cash sources provided during 2021, and the Company’s cash flow from operations before working capital changes of $187,000 represented 10% of total cash sources provided during 2020. The increase in cash flow from operations before working capital changes in 2021, as compared to the prior comparable period, was primarily due to more crude oil and natural gas sales, net of increased production costs recognized during 2021 as compared to 2020. Changes in working capital other than cash and equivalents decreased cash by $1.5 million during 2021 and increased cash by $159,000 during 2020. The $1.5 million decrease in cash resulting from changes in working capital other than cash and equivalents in 2021 was primarily the result of an increase in production accounts receivable and decreases in accounts payable and accrued expenses, offset somewhat by an unrealized loss on investments. The increase in production accounts receivable is primarily the combined result of higher average natural gas and crude oil prices received and an increase in natural gas volumes produced during the current receivable period as compared to the prior comparable period. The increase in natural gas volumes produced is primarily the result of less operated oil and gas properties being voluntarily shut-in during the current receivable period as compared to the prior comparable period. The decrease in accounts payable was primarily the result of a decrease in payables associated with the disposal of various oil and gas properties, offset somewhat by an increase in production and related other payables. The decrease in accrued expenses was primarily the result of less current asset retirement obligations at December 31, 2021 as compared to the prior comparable reporting date and the forgiveness of the PPP Loan.

The Company used cash in investing activities of $1.8 million and $747,000 in 2021 and 2020, respectively. The $1.1 million increase in cash used in investing activities was primarily the result of additional cash used for purchases of investments made in 2021 as compared to those made in the prior comparable period, as well as no cash used for the settlement of disposal of property and equipment in 2021 as compared to the prior comparable period, offset somewhat by additional proceeds from sale of property and equipment in 2021 as compared to the prior comparable period.

The Company used cash in financing activities of $39,000 and $1.1 million in 2021 and 2020, respectively. The $1.1 million decrease in cash used in financing activities was primarily the result of no cash distributions paid to Unitholders in 2021 and no loan proceeds received in 2021 as compared to the prior comparable period.

The Company’s ending cash and equivalents balance of $12.4 million at December 31, 2021, as well as on-going monthly operating cash flows, should be adequate to meet short-term cash requirements. The Company intends to make a $0.50 per Unit distribution in April 2022 and future distributions as cash flows warrant.

The Company did not participate in the drilling of any new oil and gas properties during 2021. The Company’s share of proved gas reserves increased by 10.4 BCF, or 181%, between December 31, 2020 and December 31, 2021, while proved oil reserves increased by 101,000 BBLS, or 43%, between December 31, 2020 and December 31, 2021. The Standardized Measure of Discounted Future Net Cash Flows of the Company’s reserves increased by $15.4 million between December 31, 2020 and December 31, 2021. The primary reasons for this increase were due to increases in average natural gas and crude oil prices in 2021, as compared to the prior comparable period, and the related upward revisions in quantities of natural gas and crude oil reserves between December 31, 2020 and 2021.

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 81,039 of its Units of limited partnership interest at a price of $0.86 per Unit pursuant to the terms of the Company’s Offer to Purchase dated April 30, 2020. The Company accepted an aggregate of 137,455 of its Units of limited partnership interest at a price of $0.36 per Unit pursuant to the terms of the Company’s Offer to Purchase dated April 30, 2021. The Company has determined that the price associated with the 2022 Repurchase Right, based upon the December 31, 2021 calculation, is estimated to be $2.51 per Unit, net of a $0.50 per Unit distribution expected to be made in April 2022.

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, 2021 and 2020. 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, 2021 increased $5.8 million, or 152%, compared to the prior comparable period. This increase was due primarily to an increase in crude oil and natural gas sales during 2021 as compared to 2020.

Crude oil and natural gas sales increased $5.7 million, or 166%, from 2020 to 2021. This increase was the combined result of increases in crude oil and natural gas volumes produced and higher average natural gas and crude oil prices received during 2021 as compared to 2020. The Company’s natural gas production increased by 868,000 MCF, or 73%, while crude oil production increased by 5,000 BBLS, or 16%, from 2020 to 2021. The primary reasons for the increase in crude oil and natural gas volumes produced during 2021 as compared to 2020 are the result of less operated oil and gas properties being voluntarily shut-in during 2021 as compared to the prior comparable period, offset somewhat by normal production decline associated with existing oil and gas properties. The average price received per MCF of natural gas increased from $1.85 in 2020 to $3.28 in 2021. The average price received per BBL of crude oil increased from $38.94 in 2020 to $64.46 in 2021. Natural gas sales accounted for 74% and 64% of total crude oil and natural gas sales in 2021 and 2020, respectively.

Production costs increased $339,000, or 17%, from 2020 to 2021. The increase is primarily the result of increased costs associated with Company operated properties as less Company operated properties were voluntarily shut-in during 2021 as compared to the prior comparable period.

DD&A decreased $601,000, or 62%, from 2020 to 2021. The decrease is primarily the result of an increase in natural gas and crude oil reserves as of the most recent valuation date, December 31, 2021, as compared to the prior valuation date, December 31, 2020. The increase in natural gas and crude oil reserves from 2020 to 2021 was primarily the result of higher natural gas and crude oil prices used to value reserves at December 31, 2021 as compared to the prior valuation date. The higher natural gas and crude oil prices contributed to increasing the average economic life of the Company’s oil and gas properties as compared to their prior valuation date. The effect of the increased natural gas and crude oil reserves on DD&A was offset somewhat by additional crude oil and natural gas volumes produced during 2021 as compared to the prior comparable period.

The Company reported net income of $5.7 million during 2021, as compared to a reported net loss of $203,000 during the prior comparable period. The primary reasons for the increase in reported net income are increases in crude oil and natural gas sales and a decrease in DD&A, offset somewhat by an increase in production costs. Net income represented 59% of total revenues during 2021, whereas net loss represented 5% of total revenues during 2020.

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 $300,000 and $903,000 during 2021 and 2020, 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 or increase net loss. The Company did not recognize any impairment during 2021 or 2020.

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.

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, 2021 or 2020. 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 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.

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, 2022, $102.02 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 2021 was $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 $0.94 per MCF as compared to 2019. The Company’s average price of natural gas during 2019 was $2.79 per MCF, an increase of $0.02 per MCF as compared to 2018. The Company’s average price of natural gas during 2018 was $2.77 per MCF, an increase of $0.05 per MCF as compared to 2017. 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 2022 at $4.57 per MCF and the regional basis adjustment settled for the month of March 2022 at $(0.77) per MCF, resulting in a net regional market price of $3.80 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, 2022, the Company has elected to lock-in 380,000 MCF from March 2022 to March 2023 at a weighted average price of $3.93 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, decreasing from $28.2 million at December 31, 2014 to $(8.2) million at December 31, 2015, decreasing to $(9.9) million at December 31, 2016, increasing to $(5.1) million at December 31, 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 and increasing to $6.8 million at December 31, 2021.

The Company’s Standardized Measure of Discounted Future Net Cash Flows increased by $15.4 million from December 31, 2020 to December 31, 2021. 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.

EVERFLOW EASTERN PARTNERS, L. P.

2021 CONSOLIDATED FINANCIAL REPORT

EVERFLOW EASTERN PARTNERS, L. P.

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, 2021 and 2020, 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 Everflow Eastern Partners, L. P. and subsidiaries as of December 31, 2021 and 2020, 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.

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, 2021, asset retirement obligations ("ARO") totaled approximately, $14 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 25, 2022

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

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

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

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

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

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2021.

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, 2021 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, 2021.

Explanatory NoteThis 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 2021 that have materially affected, or are reasonably likely to materially affect the Company’s internal control over financial reporting.

ITEM 9B.    OTHER INFORMATION

Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers.

Effective March 24, 2021, Everflow Management Corporation, managing member of Everflow Management Limited, LLC, general partner of the Company, announced the following appointments and departure:

See “DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE” for further discussion.

PART III

This Amendment No. 1ITEM 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, 2022 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 the Chairman of the Board of EEI, Thomas L. Korner.

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, 2022 are as follows:

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 2021 or 2020.

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.

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 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.

Brian A. Staebler was appointed to serve as President and Principal Executive Officer and director of EEI and EMC in March 2021.  He now 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 and the Ohio Society of Certified Public Accountants.

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. 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 and the Ohio Society of Certified Public Accountants.

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. He remains a director of EEI and EMC. 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 now 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.

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 (this "Amendment No. 1") is being filed to amendfor the Annual Report originally filedyear ended December 31, 2021, for filing with the Securities and Exchange Commission on March 27, 2019, to correct a unit error in the interactive data exhibits made by our filing agent. No other changes have been made to the Annual Report.Commission.

Respectfully submitted by the members of the Audit Committee:

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

EXHIBIT INDEX