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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No

Indicate by check mark whether the registrant has submitted electronically ~~and posted on its corporate Web site, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit ~~and post~~ such files). Yes NoX No ~~___~~

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§~~229.405 of this chapter)~~229.405) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated ~~filer”~~filer,” “smaller reporting company” and ~~“smaller reporting~~“emerging growth company” in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

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

There were ~~4,439,705~~4,320,927 Units of limited partnership interest held by non-affiliates of the Registrant as of June 30, ~~2016.~~2018. At June 30, ~~2016,~~2018, there was no public market for the Registrant’s Units of limited partnership interest. There were ~~5,587,616~~5,549,355 Units of limited partnership interest of the Registrant as of March 10, ~~2017.~~2019. The Units generally do not have any voting rights, but, in certain circumstances, the Units are entitled to one vote per Unit.

Except as otherwise indicated, the information contained in this Report is as of December 31, ~~2016.~~

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.

~~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.

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 56% of the estimated total future cash inflows related to the Company’s crude oil and natural gas reserves as of December 31, 2016 are attributable to crude oil 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 443 (net) wells. The Company serves as the operator of approximately 59% of the gross wells and 76% of the net wells which comprise the Company’s properties.

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

~~Sales ofDeep 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, 2016, the Company’s current leasehold inventory consists of approximately 33 prospects in various stages of maturity representing approximately 46 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 2016 or 2015.

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

The Company is permitted to incur indebtedness for any partnership purpose. It is currently anticipated that any such indebtedness would consist primarily of borrowings from commercial banks. The Company and EEI had no borrowings during 2016 or 2015 and no principal indebtedness was outstanding as of March 10, 2017. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Liquidity and Capital Resources.”

Although the Company’s Amended and Restated Agreement of Limited Partnership dated as of February 10, 2010 (the “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, 2016, net of asset retirement obligations, which aggregate a net liability of $9,924,000 (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.

~~CrudeOil~~. 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 2016 and 2015.

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, 2017, $44.49 per barrel was the posted 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 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 supply interruptions. To the extent the prices that the Company receives for its crude oil production decline, the Company’s revenues from crude oil production will be reduced accordingly.

~~Since January 1993, the Company has sold substantially all of its crude oil production to Ergon Oil Purchasing, Inc.~~

~~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. From time to time, especially in summer months, seasonal restrictions on natural gas production have occurred as a result of distribution system restrictions.

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

Since 2002, the Company has had and continues to have multiple annual or biennial contracts with Dominion, which obligate Dominionto 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, 2017, the Company has elected to lock-in various monthly quantities of natural gas with Dominion which total 210,000 MCF from March 2017 through October 2017 at various monthly weighted-average pricing provisions averaging $2.42 per MCF, net of regional basis adjustments.

The Company also has had and continues to have multiple annual or biennial contracts with Interstate Gas Supply, Inc. (“IGS”), which obligates IGS to purchase, and the Company to sell and deliver, certain quantities of natural gas production from the Company’s oil and gas properties throughout the contract periods. The Company may elect to lock-in specific volumes of natural gas to be sold in specific months at a mutually agreeable price. As of March 10, 2017, the Company has elected to lock-in various monthly quantities of natural gas with IGS which total 100,000 MCF from March 2017 through October 2017 at various monthly weighted-average pricing provisions averaging $2.44 per MCF, net of regional basis adjustments.

As detailed above, the price paid for natural gas purchased by Dominion and IGS 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 2016, natural gas purchased by Dominion covered production from approximately 460 gross operated wells, while natural gas purchased by IGS covered production from approximately 200 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 from the increased supply of natural gas in the Ohio and Pennsylvania regions. Changes in the market price for natural gas, including 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 2016, no one natural gas purchaser accounted for more than 10% of the Company’s natural gas sales other than Dominion and IGS, whose purchases of natural gas from operated wells accounted for approximately 41% and 22%, respectively, of the Company’s consolidated natural gas sales. The Company expects that Dominion and IGS will be the only material natural gas purchasers during fiscal year 2017.

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

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

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

The availability of a ready market for the oil and gas production of the Company depends in part on the cost and availability of alternative fuels, the level of consumer demand, the extent of other domestic production of oil and gas, the extent of importation of foreign oil and gas, the cost of and proximity to pipelines and other transportation facilities, regulations by state and federal authorities and the cost of complying with applicable environmental regulations. The volatility of prices for oil and gas and the continued oversupply of domestic natural gas have, at times, including 2016, 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 GasIndustry~~. The exploration, production and sale of oil and natural gas are subject to numerous state and federal laws and regulations. Such laws and regulations govern a wide variety of matters, including the drilling and spacing of wells, allowable rates of production, marketing, pricing and protection of the environment. Such regulations may restrict the rate at which the Company’s wells produce crude oil and natural gas below the rate at which such wells could produce in the absence of such regulations. In addition, legislation and regulations concerning the oil and gas industry are constantly being reviewed and proposed. Ohio and Pennsylvania, the states in which the Company owns properties and operates, have statutes and regulations governing a number of the matters enumerated above. Compliance with the laws and regulations affecting the oil and gas industry generally increases the Company’s costs of doing business and consequently affects its profitability. Inasmuch as such laws and regulations are frequently amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with such regulations.

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

~~EnvironmentalRegulation~~. 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.

~~Hydraulic Fracturing.~~ Many of our 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, 2017, the Company had 16 full-time and 3 part-time employees. These employees primarily are engaged in the following areas of business operations: six in accounting, seven in administration, four in field operations and two in land and lease acquisition.

~~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 $1.41 and $1.37 per MCF at December 31, 2016 and 2015 respectively, and the crude oil prices used in the estimation of proved reserves were $39.33 and $46.40 per BBL at December 31, 2016 and 2015, 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, 2016, 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 35 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, 2016. 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 2016 or 2015.~~

~~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, 2016.~~

~~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 2016 and 2015.~~

~~Productive Wells. The following table sets forth the gross and net oil and gas wells of the Company as of December 31, 2016.~~

~~Standardized Measure of Discounted Future Net Cash Flows.~~⁽¹⁾ The following table summarizes, as of December 31, 2016, 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, 2016, discounted to present value at 10%.

~~Acreage~~. The Company had approximately 58,600 gross developed acres and 37,900 net developed acres as of December 31, 2016. Developed acreage is that acreage assignable to productive wells. The Company had approximately 46 gross and net proved undeveloped acres as of December 31, 2016.

~~Drilling Activity~~. The following table sets forth the results of drilling activities during 2016 and 2015 on properties owned by the Company. Such information and the results of prior drilling activities should not be considered as necessarily indicative of future performance.

~~Present Activities. The Company has not participated in the drilling of any wells since December 31, 2016.~~

~~Delivery Commitments~~. The Company has entered into various contracts with Dominion and IGS which, subject to certain restrictions and adjustments, obligate Dominion and IGS to purchase and the Company to sell all natural gas production from certain operated contract wells. The operated contract wells comprised approximately 63% of the Company’s consolidated natural gas sales during 2016. In addition, the Company has entered into other various short-term contracts which obligate the purchasers to purchase and the Company to sell and deliver undetermined quantities of natural gas production on a monthly basis throughout the term of the contracts.

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

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

William A. Siskovic has served as President and Principal Executive Officer of EEI and EMC since January 2010. Brian A. Staebler has served as Vice President, Secretary-Treasurer, Principal Financial and Accounting Officer and director of EEI and EMC since January 2010.

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, 2017, there were 5,587,616 Units held by 1,392 holders of record.

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 total quarterly cash distributions of $0.70 per Unit during 2015. The Company has not paid a distribution since October 2015, and at this time the Company does not intend to resume paying quarterly distributions during 2017, though no assurances can be provided that the Company’s intentions won’t change based upon unforeseen changes in the national and/or regional oil and gas markets or other factors and their related effect on the Company’s future cash flows.

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 price to be paid for any such Units is calculated based on the method provided for in the Partnership Agreement. The Company accepted an aggregate of 26,774 of its Units of limited partnership interest at a price of $4.56 per Unit pursuant to the terms of the Company’s Offer to Purchase dated April 30, 2015. The Company did not offer to purchase Units in 2016, as it had determined that the price associated with the 2016 Repurchase Right, based upon the December 31, 2015 calculation, was negative. The Company has also determined that the price associated with the 2017 Repurchase Right, based upon the December 31, 2016 calculation, is negative, and as such the Company will not be offering to repurchase Units in 2017. See Note 3 in the Company’s consolidated financial statements for additional information on the Repurchase Right.

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

~~The following table summarizes the Company’s financial position at December 31, 2016 and December 31, 2015:~~

Working capital surplus of $19.6 million as of December 31, 2016 represented an $844,000 decrease from December 31, 2015 due primarily to a decrease in cash and equivalents, offset somewhat by increases in investments and accounts receivable from production and a decrease in accounts payable. The increase in investments was the result of purchases of shares in a mutual fund that invests primarily in investment grade, short-term fixed and floating rate debt securities. The increase in accounts receivable from production is the combined result of increases in crude oil and natural gas volumes produced and higher crude oil and natural gas prices received during the current receivable production period as compared to the prior comparable receivable production period. The decrease in accounts payable is primarily the result of less production and related other payables outstanding at December 31, 2016 as compared to the prior comparable reporting date.

Property and equipment of $10.3 million as of December 31, 2016 represented a $4.7 million decrease from December 31, 2015 due primarily to $4.8 million of depreciation, depletion and amortization (“DD&A”) and $88,000 of write down/impairment and abandonment of crude oil and natural gas properties (“Impairment and Abandonment”) recognized in 2016, offset somewhat by $249,000 of new purchases.

Long-term liabilities of $17.8 million as of December 31, 2016 represented an increase of $395,000 from December 31, 2015 due primarily to an increase in asset retirement obligations. The increase in asset retirement obligations is almost entirely the result of accretion expense recognized in 2016 to adjust the liabilities to their present value at December 31, 2016.

The Company has not held a credit facility with a bank since 2003, nor has it had any borrowings since that time. The Company will not be offering to repurchase Units in 2017. As further discussed below, the Company expects existing cash and equivalents and cash flows from ongoing operations to meet short-term cash requirements.

The Company used existing cash and equivalents in investing activities and operating activities during 2016. The Company did not use any cash in financing activities during 2016. The Company generated the majority of its cash sources from operating activities during 2015. During 2015, existing cash and equivalents and cash provided by operations was used primarily to fund distributions to Unitholders.

~~The following table summarizes the Company’s Consolidated Statements of Cash Flows for the years ended December 31, 2016 and 2015:~~

As the above table indicates, the Company’s cash flow from operations before working capital changes during 2016 resulted in a 5% use of total cash sources, whereas cash flow from operations before working capital changes during 2015 represented 19% of total cash sources provided. The decrease in cash flow from operations before working capital changes as a percentage of total cash sources in 2016, as compared to the prior comparable period, was primarily due to less crude oil and natural gas sales, net of decreased production costs and general and administrative expense incurred, during 2016 as compared to 2015. Changes in working capital other than cash and equivalents decreased cash by $626,000 during 2016 and increased cash by $464,000 during 2015. The $626,000 decrease in cash resulting from changes in working capital other than cash and equivalents in 2016 was primarily the result of an increase in accounts receivable from production and a decrease in accounts payable. The increase in accounts receivable from production is the combined result of increases in crude oil and natural gas volumes produced and higher crude oil and natural gas prices received during the current receivable production period as compared to the prior comparable receivable production period. The decrease in accounts payable is primarily the result of less production and related other payables outstanding at December 31, 2016 as compared to the prior comparable reporting date. The $464,000 increase in cash resulting from changes in working capital other than cash and equivalents in 2015 was primarily the result of a decrease in accounts receivable from production, offset by a decrease in accrued expenses. The decrease in accounts receivable from production was the combined result of decreases in crude oil and natural gas volumes produced and lower crude oil and natural gas prices received during the current receivable production period as compared to the prior comparable receivable production period. The decrease in accrued expenses was primarily the result of less payroll and retirement plan contributions accrued during the fourth quarter of 2015 as compared to the prior comparable accrual period.

The Company’s cash flows used in investing activities were $10.3 million in 2016, whereas the Company’s cash flows provided by investing activities were $182,000 in 2015. The variance was primarily the result of purchases of investments in 2016 that were not made in the prior comparable period, additional purchases of property and equipment in 2016 as compared to the prior comparable period, and no proceeds received from the sale of other assets in 2016 as compared to $250,000 received in the prior comparable period.

The Company did not have any cash flows from financing activities during 2016. During 2015, the Company used $4.0 million of cash flows in financing activities primarily to fund quarterly distributions to Unitholders.

The Company’s ending cash and equivalents balance of $11.2 million at December 31, 2016, as well as on-going monthly operating cash flows, should be adequate to meet short-term cash requirements. The Company ceased making quarterly distributions effective January 2016 and management does not provide any assurances as to when quarterly distributions will resume, if ever.

The Company participated in the drilling of one new oil and gas property during 2016. The Company’s share of proved gas reserves decreased by 2.7 BCF, or 34%, between December 31, 2016 and December 31, 2015, while proved oil reserves decreased by 33,000 barrels, or 12%, between December 31, 2016 and December 31, 2015. The Standardized Measureof Discounted Future Net Cash Flows of the Company’s reserves decreased by $1.7 million between December 31, 2016 and December 31, 2015. The primary reasons for this decrease were due to sales of crude oil and natural gas during 2016 and a decrease in average crude oil price and the related downward revisions in quantities of crude oil and natural gas reserves between December 31, 2016 and 2015. Management considers it doubtful at this point that the Company will drill any new wells during 2017, though it may participate in the drilling of a new well or wells through participation with a joint venture partner during 2017.

The Partnership Agreement provides that the Company annually offers to repurchase for cash up to 10% of the then outstanding Units, to the extent Unitholders offer Units to the Company for repurchase pursuant to the Repurchase Right. The Repurchase Right entitles any Unitholder, between May 1 and June 30 of each year, to notify the Company of his or her election to exercise the Repurchase Right and have the Company acquire such Units. The price to be paid for any such Units will be calculated based upon the audited financial statements of the Company as of December 31 of the year prior to the year in which the Repurchase Right is to be effective and independently prepared reserve reports. The price per Unit will be equal to 66% of the adjusted book value of the Company allocable to the Units, divided by the number of Units outstanding at the beginning of the year in which the applicable Repurchase Right is to be effective less all Interim Cash Distributions received by a Unitholder. The adjusted book value is calculated by adding partner’s equity, the Standardized Measure of Discounted Future Net Cash Flows and the tax effect included in the Standardized Measure and subtracting from that sum the carrying value of oil and gas properties, net of undeveloped lease costs. If more than 10% of the then outstanding Units are tendered during any period during which the Repurchase Right is to be effective, the Investor’s Units so tendered shall be prorated for purposes of calculating the actual number of Units to be acquired during any such period. The Company did not offer to repurchase any Units during 2016. The Company repurchased 26,774 Units during 2015 pursuant to the Repurchase Right at a price of $4.56 per Unit. The Company has determined that the price associated with the 2017 Repurchase Right, based upon the December 31, 2016 calculation, is negative, and as such the Company will not be offering to repurchase Units in 2017.

The following table and discussion is a review of the results of operations of the Company for the years ended December 31, 2016 and 2015. 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, 2016 decreased $2.5 million, or 39%, compared to the prior comparable period. This decrease was due primarily to a decrease in crude oil and natural gas sales during 2016 as compared with 2015.

Crude oil and natural gas sales decreased $2.3 million, or 40%, from 2015 to 2016. This decrease was the combined result of decreases in crude oil and natural gas volumes produced and lower crude oil and natural gas prices received during 2016 as compared to 2015. The average price received per MCF of natural gas decreased from $2.29 in 2015 to $1.81 in 2016. The average price received per BBL of crude oil decreased from $46.61 in 2015 to $39.67 in 2016. The Company’s natural gas production decreased by 459,000 MCF, or 28%, while crude oil production decreased by 10,000 BBLS, or 23%, from 2015 to 2016. The primary reason for the decrease incrude oil and natural gas volumes produced during 2016 as compared to 2015 is the result of additional operated oil and gas properties being voluntarily shut-in during 2016 that weren’t otherwise shut-in during the prior comparable period. Natural gas sales accounted for 61% and 65% of total crude oil and natural gas sales in 2016 and 2015, respectively.

The Company recognized $109,000 of other revenues during 2015 primarily as the result of a sale of deep mineral interests associated with 80 acres held by a lease owned by the Company. The Company retained the rights to the shallow portion of the acreage sold. The Company did not have any sales of deep mineral interests in 2016.

Production costs decreased $570,000, or 21%, from 2015 to 2016. This decrease was primarily due to less operating fees incurred relative to additional properties being voluntarily shut-in during 2016 that were producing during the prior comparable period. Other various production costs that decreased in 2016 relative to the prior comparable period include third party operated well expenses, ad valorem taxes, salt water hauling, solvent and water treatments, repairs and maintenance expenses associated with tank batteries, roads, flow lines, sales lines, pump jacks, valves, wellheads and meters, and chart integration.

Depreciation, depletion and amortization decreased $7.6 million, or 62%, from 2015 to 2016. Write down/impairment and abandonment of crude oil and natural gas properties was $88,000 during 2016, a decrease of $9.5 million over the amount recognized in the prior comparable period. The Company recognized $12.4 million of DD&A and $9.6 million of Impairment and Abandonment in 2015, both of which were the highest amounts of record as recognized in the Company’s history. The substantial DD&A and Impairment and Abandonment recognized in 2015 was primarily due to a substantial decrease in natural gas and crude oil reserves at December 31, 2015 as compared to the prior valuation date, December 31, 2014. The decrease in natural gas and crude oil reserves from 2014 to 2015 was primarily the result of significantly lower natural gas and crude oil prices used to value reserves at December 31, 2015 as compared to the prior comparable valuation date. The lower natural gas and crude oil prices contributed to decreasing the average economic life of the Company’s oil and gas properties as compared to their prior valuation date. In conjunction with the substantial declines in prices and decreases in average economic lives of properties, projected future cash flows associated with the natural gas and crude oil reserves as of December 31, 2015 decreased significantly as compared to the prior valuation date. As a result of the substantial amounts of DD&A and Impairment and Abandonment recognized in 2015, the remaining depletable bases of the Company’s oil and gas properties in 2016 were significantly less than those available to deplete and assess for impairment in the prior year, which is the primary reason for the overall decrease in DD&A and Impairment and Abandonment from 2015 to 2016.

Accretion expense decreased $190,000, or 33%, from 2015 to 2016. The primary reason for this decrease was due to more asset retirement obligations being fully accreted at January 1, 2016 as compared to January 1, 2015, which resulted in less discounted asset retirement obligations available to accrete during 2016 as compared to the prior comparable period.

General and administrative expense decreased $394,000, or 15%, from 2015 to 2016. The primary reasons for this decrease are less legal costs incurred during 2016 as compared to the prior comparable period as well as cost-cutting measures management has implemented in response to the current environment of depressed crude oil and natural gas prices within the national and regional oil and gas industries and its related effects on the Company’s sales, operational cash flows and working capital.

~~The Company recognized $240,000 of other income during 2015 in association with a gain on sale of other assets. The Company had no sales of other assets during 2016.~~

The Company reported a net loss of $6.0 million during 2016, as compared to a net loss of $21.5 million recognized in the prior comparable period. The primary reasons for the decrease are decreases in production costs, DD&A, accretion expense, Impairment and Abandonment and general and administrative expense, offset somewhat by decreases in crude oil and natural gas sales and gain on sale of other assets. The net loss represented 154% and 340% of total revenues during the years ended December 31, 2016 and 2015, respectively.

~~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 $4.7 million and $12.3 million during 2016 and 2015, 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 highlysusceptible 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. The Company wrote down crude oil and natural gas properties by $88,000 and $9.6 million during 2016 and 2015, respectively, to provide for impairment and abandonment on certain of its crude oil and natural gas properties.

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

The estimated liability is based on historical experience in dismantling, plugging and abandoning wells, estimated remaining lives of those wells based on reserves estimates, estimates of the external cost to dismantle, plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability will likely occur due to: changes in estimates of dismantlement, plugging and abandonment costs; changes in estimated remaining lives of the wells; changes in federal or state regulations regarding dismantlement, plugging and abandonment requirements; and other factors. At December 31, 2015, the Company made revisions in estimates of remaining lives of wells.

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, 2016 or 2015.Other revenues consist of gain on sale of deep rights and other miscellaneous revenues. Gain on sale of deep rights is recognized when title to deep mineral interests has been transferred and all terms and conditions to the sale have been met. Other miscellaneous revenues are recognized at the time services are rendered, the Company has a contractual right to such revenue and collection is reasonably assured.

The Company participates (and may act as drilling contractor) with unaffiliated joint venture partners and employees in the drilling, development and operation of jointly owned crude oil and natural gas properties. Each owner, including the Company, has an undivided interest in the jointly owned properties. Generally, the joint venture partners and employees participate on the same drilling/development cost basis as the Company and, therefore, no revenue, expense or income is recognized on the drilling and development of the properties. The Company receives reimbursement of administrative costs associated with preparation, drilling and development of jointly owned crude oil and natural gas properties from certain joint venture partners. Accounts and notes receivable from joint venture partners and employees consist principally of drilling and development costs the Company has advanced or incurred on behalf of joint venture partners and employees.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.

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, as they did significantly in 2015.

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 affected 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, 2017, $44.49 per barrel was the posted 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 2016 was $1.81 per MCF, a decrease of $0.48 per MCF as compared to 2015. The Company’s average price of natural gas during 2015 was $2.29 per MCF, a decrease of $1.44 per MCF as compared to 2014. The Company’s average price of natural gas during 2014 was $3.73 per MCF, a decrease of $0.11 per MCF as compared to 2013. 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 2017 at $2.63 per MCF and the regional basis adjustment settled for the month of March 2017 at $(0.57) per MCF, resulting in a net regional market price of $2.06 per MCF. Since 2002, the Company has had and continues to have multiple annual or biennial contracts with various purchasers of natural gas, which obligate certain purchasers to purchase, and the Company to sell and deliver, certain quantities of natural gas production from the Company’s oil and gas properties throughout the contract periods. Per the terms of the Company’s contracts with two gas purchasers, the Company may elect to lock-in specific volumes of natural gas to be sold in specific months at a mutually agreeable price. As of March 10, 2017, the Company has elected to lock-in various monthly quantities of natural gas with two of its natural gas purchasers which total 310,000 MCF from March 2017 through October 2017 at various monthly weighted-average pricing provisions averaging $2.43 per MCF, net of regional basis adjustments. Excess natural gas production above locked-in quantities is sold at a price tied to the then current monthly NYMEX settled price plus or minus a current regional basis adjustment.

The Company’s sales are significantly impacted by pricing instability in the crude oil and natural gas markets. One of the consequences of these pricing fluctuations is evident in the Company’s Standardized Measure of Discounted Future Net Cash Flows increasing from $49.7 million at December 31, 2009 to $61.2 million at December 31, 2010, decreasing to $60.6 million at December 31, 2011, decreasing to $33.5 million at December 31, 2012, increasing to $41.7 million at December 31, 2013, decreasing to $28.2 million at December 31, 2014, decreasing to $(8.2) million at December 31, 2015 and decreasing to $(9.9) million at December 31, 2016.

The Company’s Standardized Measure of Discounted Future Net Cash Flows decreased by $1.7 million from December 31, 2015 to December 31, 2016. A reconciliation of the Changes in the Standardized Measure of Discounted Future Net Cash Flows is included in the Company’s consolidated financial statements.

We have audited the accompanying consolidated balance sheets of Everflow Eastern Partners, L.P. and subsidiaries (the “Company”) as of December 31, 2016 and 2015, and the related consolidated statements of operations, partners' equity, and cash flows for the years then ended. Everflow Eastern Partners, L.P.’s management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, 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. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

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, 2016 and 2015, and the consolidated results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

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

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

The partnership agreement provides that Everflow will repurchase for cash up to 10% of the then outstanding Units, to the extent Unitholders offer Units to Everflow for repurchase pursuant to the Repurchase Right. The Repurchase Right entitles any Unitholder, between May 1 and June 30 of each year, to notify Everflow that the Unitholder elects to exercise the Repurchase Right and have Everflow acquire certain or all Units. The price to be paid for any such Units is calculated based upon the audited financial statements of the Company as of December 31 of the year prior to the year in which the Repurchase Right is to be effective and independently prepared reserve reports. The price per Unit equals 66% of the adjusted book value of the Company allocable to the Units, divided by the number of Units outstanding at the beginning of the year in which the applicable Repurchase Right is to be effective less all interim cash distributions received by a Unitholder. The adjusted book value is calculated by adding partners' equity, the standardized measure of discounted future net cash flows and the tax effect included in the standardized measure and subtracting from that sum the carrying value of oil and gas properties (net of undeveloped lease costs). If more than 10% of the then outstanding Units are tendered during any period during which the Repurchase Right is to be effective, the investors' Units tendered shall be prorated for purposes of calculating the actual number of Units to be acquired during any such period. The Company has determined that the price associated with the 2017 Repurchase Right, based upon the December 31, 2016 calculation, is negative, and as such the Company will not be offering to repurchase Units in 2017. The Company did not make a distribution in January 2017.

The Company has an Option Repurchase Plan (the "Option Plan") which permits the grant of options to repurchase certain Units to select officers and employees (the "Option Plan Participants"). The purpose of the Option Plan is to assist the Company in attracting and retaining officers and other key employees and to enable those individuals to acquire or increase their ownership interest in the Company in order to encourage them to promote the growth and profitability of the Company. The Option Plan is designed to align directly the financial interests of the Option Plan Participants with the financial interests of the Unitholders. The Company did not grant any options in 2016. In June 2015, the Company granted options to officers and an employee. All options granted were exercised on the same date. Compensation expense associated with these grants was not material to the financial statements.

The Company did not repurchase any Units pursuant to the Repurchase Right during 2016. Units repurchased pursuant to the Repurchase Right and Units issued through the exercise of options pursuant to the Option Plan (collectively the “Units Activity”) for the two years ended December 31, 2015, are as follows:

All Units repurchased pursuant to the Repurchase Right were retired except for those Units issued through the exercise of options pursuant to the Option Plan. There were no instruments outstanding at December 31, 2016 or 2015 that would potentially dilute net income per Unit.

~~A reconciliation between taxes computed at the Federal statutory rate and the effective tax rate in the statements of operations follows:~~

As referred to in Note 1, EEI accounts for deferred income taxes under the provisions of generally accepted accounting principles. Items giving rise to deferred taxes consist of temporary differences arising from differences in financial reporting and tax reporting methods for EEI's proved properties.

The Company has a defined contribution plan pursuant to Section 401(k) of the Internal Revenue Code for all employees who have reached defined minimum age and term of service requirements (the “Defined Contribution Plan”, or the “DC Plan”). The Company makes safe harbor contributions and matches employees' contributions to the Defined Contribution Plan as annually determined by EMC's Board of Directors. Additionally, the DC Plan has a profit sharing component which provides for contributions to the DC Plan at the discretion of EMC's Board of Directors. Amounts contributed to the DC Plan vest immediately. The Company's total contributions to the Defined Contribution Plan amounted to approximately $168,700 and $187,000 for the years ended December 31, 2016 and 2015, respectively.

The Company had a qualified non-contributory cash balance defined benefit retirement plan covering certain eligible employees (the “Pension Plan”, or the “Plan”) that was terminated in December 2015. Participants accumulated annual service credits as determined by their participation level according to the plan document and became fully vested after three years of service, including credits given for prior service. Interest was accrued on these accumulated amounts at an annual rate of 5%. All participants were fully vested upon the Plan’s termination.

~~Net periodic benefit cost recognized in the consolidated statements of operations consists of the following during the year ended December 31, 2015:~~

The projected benefit obligation (the “PBO”) and accumulated benefit obligation are determined as the actuarial present value of the vested benefits to which the employees are currently entitled but based on their expected date of separation or retirement. The change in the projected benefit obligation of the Pension Plan and the change in assets at fair value are as follows during the year ended December 31, 2015:

The Company’s funding policy for the Plan was to fund at least the amount actuarially determined necessary to comply with the minimum funding standards as defined by the Employee Retirement Income Security Act.

~~Assumptions used in accounting for the projected benefit obligation at January 1, 2015 included a discount rate of 5% and long-term asset return of 7%.~~

The Plan's investment policy reflected the long-term nature of the plan's funding obligations. The assets were invested to provide the opportunity for both income and growth of principal. This objective was pursued as a long-term goal designed to provide required benefits for participants without undue risk. It was expected that this objective would be achieved through a well-diversified asset portfolio. As such, the Plan’s assets, which were classified as Level I assets, were invested in a publicly traded mutual fund with a domestic blend of stocks and bonds at January 1, 2015. Upon the termination of the Plan in 2015, all Plan assets were distributed.

The Company's Officers, Directors, affiliates and certain employees have frequently participated, and will likely continue to participate in the future, as working interest owners in wells in which the Company has an interest. Frequently, the Company has loaned the funds necessary for certain employees to participate in the drilling and development of such wells. Initial terms of the unsecured loans call for repayment of all principal and accrued interest at the end of four years, however, the loan amounts are reduced as production proceeds attributable to the employees' working interests are not remitted to the employees but rather used to reduce the amounts owed by the employees to the Company. If an outstanding balance remains after the initial four-year term, the Company and employee shall, acting in good faith, agree upon further repayment terms.

Employees remain obligated for the entire loan amount regardless of a dry-hole event or otherwise insufficient production. The loans carry no loan forgiveness provisions, and no loans have ever been forgiven. The loans accrue interest at the prime rate, which was 3.75% at December 31, 2016.

In accordance with the Sarbanes-Oxley Act of 2002, the Company has not extended any loans to officers or directors since 2002. At December 31, 2016 and 2015, the Company has extended various loans, evidenced by notes, to two employees with origination dates ranging from December 2010 to December 2015. In addition, 3 subsequent addenda extending additional payment terms to certain notes are outstanding at December 31, 2016. Employee notes receivables, including accrued interest, amounted to $87,045 and $124,437 at December 31, 2016 and 2015, respectively.2018.

~~F-20~~

~~Table of Contents~~

This Amendment No. 1 to Form 10-K (this "Amendment No. 1") is being filed to amend the Annual Report originally filed 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.

~~The Company operates exclusively in Ohio and Pennsylvania of the United States in the acquisition, exploration, development and production of oil and gas.~~

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

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

Natural gas sales accounted for 61% and 65% of total crude oil and natural gas sales in 2016 and 2015, respectively. Approximately 76% and 69% of total crude oil and natural gas sales were derived from operated wells in 2016 and 2015, respectively. The Company had two significant purchasers of natural gas production from operated wells for the years ended December 31, 2016 and 2015. Natural gas sales to these significant purchasers as a percentage of consolidated crude oil and natural gas sales were as follows:

As of December 31, 2016, natural gas purchased by Dominion covers production from approximately 460 gross operated wells, while natural gas purchased by IGS covers production from approximately 200 gross operated wells. Production purchased by Dominion and IGS from operated wells comprised approximately 63% of the Company's consolidated natural gas sales in 2016 and 2015, respectively.

~~Substantially all of the Company’s crude oil production from operated wells is purchased by Ergon Oil Purchasing, Inc. (“Ergon Oil”).~~

~~F-21~~

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E-1

Table of Contents

The Company's production accounts receivable result from sales of natural gas and crude oil. A significant portion of the Company's production accounts receivable is due from the Company's major customers. The Company does not view such concentration as an unusual credit risk. However, the Company does not require collateral from its customers and could incur losses if its customers fail to pay. As a result of management's review of current and historical credit losses and economic activity, a valuation allowance was not deemed necessary at December 31, 2016 and 2015. The Company expects that Dominion, IGS and Ergon Oil will continue to be the only major customers for natural gas and crude oil production from its operated wells in 2017. Historically, the Company has not tracked the purchasers of natural gas and crude oil derived from third party operated wells which may have the same customers.

The Company has multiple contracts with Dominion and IGS (collectively, the “Gas Purchasers”) which obligate the Gas 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. The Company may elect to lock-in specific volumes of natural gas to be sold in specific months at a mutually agreeable price. The Company has elected to lock-in various monthly quantities of natural gas which total 510,000 MCF from January 2017 through October 2017 at various monthly weighted-average pricing provisions averaging $2.45 per MCF, net of regional basis adjustments. Pricing provisions with the Gas Purchasers apply to certain fixed quantities on a monthly basis with excess monthly quantities being priced based on the current spot market price, plus or minus a current regional basis adjustment. The impact of these contracts on the Company’s future oil and gas sales cannot fully be measured until actual production volumes and prices have been determined.

The Company has natural gas delivery commitments to the Gas Purchasers (see Note 7). Management believes the Company can meet its delivery commitments based on estimated production. If, however, the Company cannot meet its delivery commitments, it may be required to purchase natural gas at market prices to meet such commitments which may result in a gain or loss for the difference between the delivery commitment price and the price at which the Company is able to purchase the natural gas for redelivery (resale) to its customers.

In conjunction with the sale of approximately 28,800 acres of deep rights made in 2012, the Company agreed to perpetuate the producing leases for a minimum period of five years. If the Company fails to perpetuate the producing leases during such five-year period, it shall refund to the purchaser the portion of the purchase price attributable to the affected properties based on an allocated value of $1,250 per acre (the “Refund Price”), provided however, that should the Company revive or otherwise renew such expired leases within three months of their expiration, the purchaser shall have the right to acquire the deep rights on such revived or renewed leases for the Refund Price. The Company has assessed the shallow operations of all properties from which deep acreage was sold and does not believe a reserve for potential refunded acreage to be necessary at December 31, 2016.

The Company is party to various legal proceedings and claims in the ordinary course of its business. The Company believes certain of these matters will be covered by insurance and that the outcome of other matters will not have a material adverse effect on its consolidated financial position, results of operations, or liquidity.

~~Note 9.~~ ~~Supplemental Information Relating to Oil and Gas Producing Activities~~ ~~(Unaudited)~~

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

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

~~The Company had no purchases of producing oil and gas properties in 2016 or 2015.~~

~~Note 9~~~~. Supplemental Information Relating to Oil and Gas Producing Activities~~~~(Unaudited) (Continued)~~

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

~~Note 9~~~~. Supplemental Information Relating to Oil and Gas Producing Activities~~~~(Unaudited) (Continued)~~

The Company has not determined proved reserves associated with its proved and other undeveloped properties, including its deep property interests. At December 31, 2016 and 2015, the Company had 46 and 91 net proved undeveloped acres, respectively. The net carrying cost of the proved undeveloped acreage that is included in proved properties amounted to approximately $36,200 and $35,700 at December 31, 2016 and 2015, respectively.

~~Note 9~~~~. Supplemental Information Relating to Oil and Gas Producing Activities~~~~(Unaudited) (Continued)~~

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

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

Average adjusted natural gas prices used in the estimation of proved reserves were $1.41 and $1.37 per MCF at December 31, 2016 and 2015, respectively, and the average adjusted crude oil prices used in the estimation of proved reserves were $39.33 and $46.40 per BBL at December 31, 2016 and 2015, respectively.

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, 2016.

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, 2016 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 assessments, management has concluded that the Company’s internal controls over financial reporting were effective as of December 31, 2016.

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

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 2016 that have materially affected, or are reasonably likely to materially affect the Company’s internal control over financial reporting.

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, 2017 are EMC; two individuals who are officers and directors of EEI, William A. Siskovic and Brian A. Staebler; one individual who serves as the Chairman of the Board of EEI, Thomas L. Korner; one individual who is an employee of the Company, Richard M. Jones; and one New York limited liability company founded by an individual who is a director of EEI, Robert F. Sykes, and owned by the four adult children of Mr. Sykes.

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. Many personnel previously employed by EEI to conduct its operation, drilling and field supervisory functions are now employed directly by the Company and discharge the same functions on behalf of the Company. EEI has no employees as of March 10, 2017, and has had no employees for at least the past two years. 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, 2017 are as follows:~~

All directors of EEI are elected to serve by the Company, which is EEI’s sole shareholder. All officers of EEI serve at the pleasure of the Board of Directors. Directors and officers of EEI receive no compensation or fees for their services to EEI or their services on behalf of the Company.

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 has 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.

~~Robert F. Sykes~~ has been a director of EEI since March 1987 and was Chairman of the Board from May 1988 to January 2010. Mr. Sykes has been a director of EMC since its formation in September 1990 and was Chairman of the Board from September 1990 to January 2010. In these roles, Mr. Sykes’ has successfully led the Company since its formation. He was the Chairman of the Board of Sykes Datatronics, Inc., Rochester, New York, from its organization in 1968 until his resignation in January 1989. Sykes Datatronics, Inc. was a manufacturer of telephone switching equipment. Mr. Sykes also served as President and Chief Executive Officer of Sykes Datatronics, Inc. from 1968 until October 1983 and from January 1985 until October 1985. Mr. Sykes also has been a director of Voplex, Inc., Rochester, New York, a manufacturer of plastic products, a director of MOOG, Inc., a manufacturer of aerospace systems, and a director of ACC Corp., a long distance telephone company.

~~Peter H. Sykes~~ has been a director of EMC since November 2008. Mr. Sykes is President and founder of Sykes Wealth Strategies Inc., which provides financial advice to individuals, endowments, partnerships and corporations, since 2005. Mr. Sykes has also served as an account vice president with UBS Financial and Paine Webber, both financial services companies, from1984 until 2005. Mr. Sykes’ experience as a senior executive in financial consulting, with partnerships and corporations in particular, provides the Company with a valuable resource and qualifies him as a director. Peter H. Sykes is the son of Robert F. Sykes.

~~William A. Siskovic~~ was appointed to serve as President and Principal Executive Officer of EEI and EMC in January 2010. Prior to this appointment Mr. Siskovic had been a Vice President of EEI since January 1989 and a 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 now supervises and oversees all aspects of the Company and EEI’s business, including oil and gas property acquisition, development, operation and marketing. 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, is a current member of the Ohio Oil and Gas Association, and currently serves on the Board of Trustees of the Ohio Oil and Gas Energy Education Program and the Children's Mental Health Circle of Friends Foundation, a nonprofit organization that serves a counseling center providing behavioral health care services.

~~Brian A. Staebler~~ was appointed to serve as Vice President, Secretary-Treasurer, Principal Financial and Accounting Officer and director of EEI and EMC in January 2010. Mr. Staebler is responsible for the financial operations of the Company and EEI. 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 regulations.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, director and audit committee financial expert. Mr. Staebler has a Business Administration Degree in Accounting from the University of Toledo, is an active Certified Public Accountant licensed by the Accountancy Board of Ohio, and is a current member of the American Institute of Certified Public Accountants, the Ohio Society of Certified Public Accountants, and the Ohio Oil and Gas Association.

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. Brian A. Staebler, who is not independent, has been designated the Company’s audit committee financial expert.

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 public accountants of the Company, Maloney + Novotny LLC, the matters that are required to be discussed by Statement on Auditing Standards No. 61,~~~~Communication with Audit Committees~~, as amended, by the Auditing Standards Board of the American Institute of Certified Public Accountants, which includes a review of the findings of the independent accountants during its examination of the Company’s financial statements.

~~We have received and reviewed written disclosures and the letter from Maloney + Novotny LLC, which is required by Independence Standard No. 1,~~~~Independence Discussions with Audit Committee~~, as amended, by the Independence Standards Board, and we have discussed with Maloney + Novotny LLC their independence under such standards. We have concluded that the independent public accountants are independent from the Company and its management.

Based on our review and discussions referred to above, we have recommended to the Board of Directors that the audited financial statements of the Company be included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016, for filing with the Securities and Exchange Commission.

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

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

~~Based solely on the Company’s review of the copies of such forms furnished to the Company, the Company believes that all required Section 16(a) filings for fiscal year 2016 were timely made.~~

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

~~Components of executive compensation in the 2016 fiscal year for the executive officers of EMC and EEI include the following:~~

The base salary of the executive officers is intended to provide fixed compensation for the performance of core duties. In determining appropriate salary levels, consideration is given to the level and scope of responsibility, experience, and Company and individual performance. The base salaries paid during fiscal 2016 are shown in the Summary Compensation Table appearing further below in this Item 11.

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

Executive officers are provided an annual cash bonus each year based on the achievement of certain financial and non-financial performance objectives during the previous fiscal year. Annual cash bonuses are based on a percentage of the executive’s base salary. For 2016, the Board of Directors set a range of these bonuses between 90% and 150% of the executive’s base salary, based on the Company achieving specified financial and non-financial performance objectives. In 2016, the financial performance objectives that were used for determining financial performance-based cash awards were asset management, profitability and overall company stability. In 2016, the non-financial performance objectives that were used for determining non-financial performance based cash awards were corporate governance and adherence to policies and procedures as well as other factors that vary depending on responsibilities.

The 2017 target annual cash bonus awards for executive officers are established as a percentage of the executive’s base salary. These target amounts range between 90% and 150% of base salary. These target amounts were determined considering executive pay at companies of comparable size. The Board of Directors believes it is important that these target and maximum payout levels are aligned with the Company’s long-term strategic plan and the Company’s expectation of future financial performance.

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

The Company has an Option Repurchase Plan under which the Company may grant options to repurchase Units acquired by the Company as part of the Repurchase Right to eligible officers and employees. The Company did not grant any options to executive officers during 2016. During June 2015, the Company granted a total of 10,710 options to executive officers, of which all were exercised during the same month.

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

The following table sets forth information concerning the annual compensation for services in all capacities to the Company for the fiscal years ended December 31, 2016 and 2015, of those persons who were at December 31, 2016: (i) the Principal Executive Officer of EMC and EEI; and (ii) the Principal Financial Officer of EMC and EEI. The Principal Executive Officer and Principal Financial Officer are hereinafter referred to collectively as the “Named Executive Officers.”

~~No Named Executive Officer received personal benefits or perquisites during 2016 or 2015 in excess of $10,000.~~

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

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~~Outstanding Equity Awards~~

The Company did not grant any options to executive officers during 2016. During June 2015, the Company granted a total of 10,710 options, respectively, to executive officers. All options granted were exercised during the same month. There were no outstanding unexercised options as of December 31, 2016 or 2015.

~~Retirement Plans~~

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

The Company had a qualified cash balance defined benefit retirement plan covering certain eligible employees, including officers (the “Pension Plan”) that was terminated in December 2015. Participants accumulated annual service credits as determined by their participation level according to the plan document and became fully vested after three years of service, including credits given for prior service. Interest was accrued on these accumulated amounts at an annual rate of 5%. All participants, including officers, were fully vested upon the Pension Plan’s termination.

~~The Defined Contribution Plan and the Pension Plan are further described in Note 5 of the Company’s consolidated financial statements included herein.~~

~~Director Compensation~~

Thomas L. Korner, William A. Siskovic, Brian A. Staebler, Robert F. Sykes and Peter H. Sykes did not receive any additional compensation for their service as Directors during the 2016 or 2015 fiscal years.

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

The General Partner is a limited liability company of which EMC, an Ohio corporation, is the managing member. The members of the General Partner as of March 10, 2017 are EMC; two individuals who are officers and directors of EEI, William A. Siskovic and Brian A. Staebler; one individual who serves as the Chairman of the Board of EEI, Thomas L. Korner; one individual who is an employee of the Company, Richard M. Jones; and one New York limited liability company founded by an individual who is a director of EEI, Robert F. Sykes, and owned by the four adult children of Mr. Sykes.The General Partner of the Company owns a 1.19% interest in the Company.

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The following table sets forth certain information with respect to the number of Units beneficially owned as of March 10, 2017 by each person known to the management of the Company to own beneficially more than 5% of the outstanding Units; and by each director and officer of EMC. The table also sets forth (i) the ownership interests of the General Partner and (ii) the ownership of EMC.

~~BENEFICIAL OWNERSHIP OF UNITS IN THE COMPANY,~~

~~EVERFLOW MANAGEMENT LIMITED, LLC AND EMC~~

Percentage

Interest in

Percentage

Everflow

Percentage

Units in

of Units in

Management

Interest in

Name of Holder

Company

Company⁽¹⁾

Limited, LLC⁽²⁾

EMC

Directors and Executive Officers

Robert F. Sykes⁽³⁾(director of EMC)
158,634 2.84 * *
William A. Siskovic (officer and director of EMC)
86,329 1.55 16.6667 16.6667
Thomas L. Korner (Chairman of the Board & director of EMC)
64,476 1.15 16.6667 16.6667
Peter H. Sykes⁽⁴⁾(director of EMC)
41,244 0.74 * *
Brian A. Staebler (officer and director of EMC)
15,462 0.28 8.3333 8.3333
366,145 6.56 41.6667 41.6667

Other Beneficial Owners of >5% of the Company

David F. Sykes⁽⁵⁾
774,099 13.85 50.0000 50.0000
1,140,244 20.41 91.6667 91.6667

*Represents less than one percent.

~~(1)~~

Does not include the interest in the Company owned indirectly by such individuals as a result of their ownership in (i) the General Partner (based on its 1.19% interest in the Company) or (ii) EMC (based on EMC’s 1% managing member’s interest in the General Partner).

~~(2)~~

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

~~(3)~~

~~Includes 79,639 Units held directly by Robert F. Sykes and 78,995 Units held by the Sykes Family Trust, of which Robert F. Sykes serves as the Trustee.~~

~~(4)~~

~~Includes 41,244 Units held by PHS Associates, a New York limited partnership owned by the family of Peter H. Sykes.~~

~~(5)~~

Includes 732,855 Units, or 13.11% of the Company’s outstanding Units, held by Sykes Associates, LLC, a New York limited liability company located at 27 Wexford Glen, Pittsford, NY 14535 and owned by the four adult children of Robert F. Sykes as members, and 41,244 Units of the Company held by DFS Associates, a New York limited partnership owned by the family of David F. Sykes,~~who manages Sykes Associates, LLC. David F. Sykes is the son of Robert F. Sykes and is not an officer or director of EMC.~~

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~~Table of Contents~~

~~Item 13. Certain Relationships and Related Transactions, AND~~ ~~DIRECTOR INDEPENDENCE~~

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

Certain officers and directors of EMC own crude oil and natural gas properties and, as such, contract with the Company to provide field operations on such properties. These ownership interests are charged per well fees for such services on the same basis as all other working interest owners. William A. Siskovic made investments in crude oil and natural gas properties during 2015 in the amount of $9,210. Brian A. Staebler made investments in crude oil and natural gas properties during 2016 and 2015 in the amount of $1,600 and $9,210, respectively. Thomas L. Korner made investments in crude oil and natural gas properties during 2015 in the amount of $9,210.

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

~~-40-~~

~~Table of Contents~~

~~ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES~~

Maloney + Novotny LLC served as the Company’s independent auditor for the years ended December 31, 2016 and 2015. The following is a summary of the fees billed to the Company by Maloney + Novotny LLC for professional services rendered during the years ended December 31, 2016 and 2015, respectively.

December 31,

2016

2015

Audit fees
$ 162,073 $ 161,222
Audit related fees
- -
Tax fees
1,196 855
All other fees
- -

Total
$ 163,269 $ 162,077

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

The Company has a policy to assure the independence of its registered public accounting firm. Prior to each fiscal year, the audit committee receives a written report from its independent auditor describing the elements expected to be performed in the course of its audit of the Company’s financial statements for the coming year. All audit related and other services were pre-approved for 2016 by the audit committee.

~~-41-~~

~~Table of Contents~~

~~PART IV~~

I~~tem 15.~~ ~~EXHIBITS AND FINANCIAL STATEMENT SCHEDULES~~

~~(a) (1)~~ ~~Financial Statements~~

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

	~~Page(s)~~
~~Report of Independent Registered Public Accounting Firm~~	~~F-3~~
~~Consolidated Balance Sheets~~	~~F-4 - F-5~~
~~Consolidated Statements of Operations~~	~~F-6~~
~~Consolidated Statements of Partners’ Equity~~	~~F-7~~
~~Consolidated Statements of Cash Flows~~	~~F-8~~
~~Notes to Consolidated Financial Statements~~	~~F-9 - F-27~~

~~(a) (2)~~ ~~Financial Statements Schedules~~

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

~~(a) (3)~~ ~~Exhibits~~

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

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

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

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

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

~~ITEM 16. FORM 10-K SUMMARY~~

~~None.~~

~~-42-~~

~~Table of Contents~~

SIGNATURES

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

EVERFLOW EASTERN PARTNERS, L.P.
~~By:~~
~~EVERFLOW MANAGEMENT LIMITED, LLC~~
~~General Partner~~

By:
EVERFLOW MANAGEMENT LIMITED, LLC
General Partner
By: EVERFLOW MANAGEMENT CORPORATION
Managing Member

By:
/s/ ~~Robert F.~~Peter H. Sykes

Director

March ~~28, 2017~~
29, 2019
~~Robert F.~~Peter H. Sykes

~~By:~~
~~/s/ Peter H. Sykes~~

~~Director~~

~~March 28, 2017~~
By:
~~Peter H. Sykes~~
/s/ Thomas L. Korner
Director
March 29, 2019
Thomas L. Korner

By:
/s/ William A. Siskovic President, Principal March 29, 2019
William A. Siskovic
~~/s/ Thomas L. Korner~~Executive Officer and Director

~~Director~~
~~March 28, 2017~~
~~Thomas L. Korner~~

~~By:~~
~~/s/ William A. Siskovic~~
~~President, Principal Executive Officer and Director~~
~~March 28, 2017~~
~~William A. Siskovic~~

By:
~~By:~~
/s/ Brian A. Staebler

Vice President, ~~Secretary- Treasurer,~~ Secretary-Treasurer,
March 29, 2019
Brian A. Staebler Principal Financial and Accounting Officer and Director
~~March 28, 2017~~
~~Brian A. Staebler~~
~~Table of Contents~~
~~EXHIBIT INDEX~~
Exhibit No. Description

3.1

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

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

3.3 General Partnership Agreement of Everflow Management Company (1)

3.4 Articles of Incorporation of Everflow Management Corporation (1)

3.5 Code of Regulations of Everflow Management Corporation (1)

3.6
Articles of Organization of Everflow ManagementLimited LLC
(3)

3.7
Amended and Restated Operating Agreement of Everflow Management Limited, LLC dated December 31, 2008
(4)

10.1
Shareholders Agreement for Everflow Management Corporation
(1)

10.2
Operating facility lease dated October 3, 1995 between Everflow Eastern Partners, L.P. and A-1 Storage ofCanfield, Ltd.
(5)

14.1 Code of Ethics

21.1 Subsidiaries of the Registrant (6)

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

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

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

99.1 Report of Wright & Company, Inc. dated February 14, 2017 concerning evaluation of oil and gas reserves.

99.2 Audit Committee Charter of Everflow Management Corporation (7)

101.INS Instance Document

101.SCH XBRL Taxonomy Extension Schema Document

101.CAL XBRL Taxonomy Extension Calculation Linkbase Document
~~E-1~~
~~Table of Contents~~
~~Exhibit No.~~ ~~Description~~
~~101.DEF~~ ~~XBRL Taxonomy Extension Definition Document~~
~~101.LAB~~ ~~XBRL Taxonomy Extension Label Linkbase Document~~
~~101.PRE~~ ~~XBRL Taxonomy Extension Presentation Linkbase Document~~
~~(1)~~
~~Incorporated herein by reference to the appropriate exhibit to Registrant's Registration Statement onForm S-1 (Reg. No. 33-36919).~~
~~(2)~~
~~Incorporated herein by reference to the appropriate exhibit to the Registrant’s Current Report on Form 8-K dated February 12, 2010 (File No. 0-19279).~~
~~(3)~~
~~Incorporated herein by reference to the appropriate exhibit to the Registrant’s Quarterly Report onForm 10-Q for the first quarter ended March 31, 1999 (File No. 0-19279).~~
~~(4)~~
~~Incorporated herein by reference to the appropriate exhibit to the Registrant's Annual Report onForm 10-K for the year ended December 31, 2008 (File No. 0-19279).~~
~~(5)~~
~~Incorporated herein by reference to the appropriate exhibit to the Registrant's Quarterly Report onForm 10-Q for the third quarter ended September 30, 1995 (File No. 0-19279).~~
~~(6)~~
~~Incorporated herein by reference to the appropriate exhibit to the Registrant's Annual Report onForm 10-K for the year ended December 31, 1995 (File No. 0-19279).~~
~~(7)~~
~~Incorporated herein by reference to the appropriate exhibit to the Registrant's Annual Report onForm 10-K for the year ended December 31, 2014 (File No. 0-19279).~~
~~E-2~~

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

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

Large accelerated filer	~~_________~~	Accelerated filer	~~_________~~
Non-accelerated filer	~~_________ (Do not check if a smaller reporting company)~~
Smaller reporting company	X	Emerging growth company

	~~DESCRIPTION~~		~~PAGE NO.~~

~~Part I.~~

	~~Item 1.~~	~~Business~~	1

	~~Item 1A.~~	~~Risk Factors~~	10

	~~Item 1B.~~	~~Unresolved Staff Comments~~	10

	~~Item 2.~~	~~Properties~~	11

	~~Item 3.~~	~~Legal Proceedings~~	14

	~~Item 4.~~	~~Mine Safety Disclosures~~	14

	~~Supplemental Item - Executive Officers of the Registrant~~		15

~~Part II.~~

	~~Item 5.~~	~~Market for Registrant’s Common Equity, Related~~ ~~Stockholder Matters and Issuer Purchases of Equity Securities~~	16

	~~Item 6.~~	~~Selected Financial Data~~	17

	~~Item 7.~~	~~Management’s Discussion and Analysis of Financial~~ ~~Condition and Results of Operations~~	17

	~~Item 7A.~~	~~Quantitative and Qualitative Disclosures About MarketRisk~~	28

	~~Item 8.~~	~~Financial Statements and Supplementary Data~~	28

		~~Report of Independent Registered Public Accounting Firm~~	~~F-3~~

		~~Consolidated Balance Sheets~~	~~F-4~~

		~~Consolidated Statements of Operations~~	~~F-6~~

	~~DESCRIPTION~~		~~PAGE NO.~~

		~~Consolidated Statements of Partners’ Equity~~	~~F-7~~

		~~Consolidated Statements of Cash Flows~~	~~F-8~~

		~~Notes to Consolidated Financial Statements~~	~~F-9~~

	~~Item 9.~~	~~Changes in and Disagreements with Accountants onAccounting and Financial Disclosure~~	29

	~~Item 9A.~~	~~Controls and Procedures~~	29

	~~Item 9B.~~	~~Other Information~~	30

~~Part III.~~

	~~Item 10.~~	~~Directors, Executive Officers and Corporate~~ ~~Governance~~	31

	~~Item 11.~~	~~Executive Compensation~~	35

	~~Item 12.~~	~~Security Ownership of Certain Beneficial Owners and~~ ~~Management and Related Stockholder Matters~~	38

	~~Item 13.~~	~~Certain Relationships and Related Transactions, and~~ ~~Director Independence~~	40

	~~Item 14.~~	~~Principal Accounting Fees and Services~~	41

~~Part IV.~~

	~~Item 15.~~	~~Exhibits and Financial Statement Schedules~~	42

	~~Item 16.~~	~~Form 10-K Summary~~	42

~~Exhibit Index~~			~~E-1~~

	Oil (BBLS)		Gas (MCF)

Proved Developed		244,000		5,280,000
Proved Undeveloped		-		-
Total		244,000		5,280,000

		Name of each exchange
	Title of each class	on which registered

~~_________________~~
~~(1)~~								The Company has not determined proved reserves associated with its proved and other undeveloped properties, including its deep property interests, at December 31, 2016. A reconciliation of the Company’s proved reserves is included in the Notes to the Consolidated Financial Statements

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

2016		34,000		1,157,000	$	39.67	$	1.81	$	1.59
2015		44,000		1,616,000	$	46.61	$	2.29	$	1.46

Gross Wells					Net Wells
(1)	(1)				(1)		(1)
Oil	Gas		Total		Oil		Gas		Total
288		1,158		1,446		161		721		882

	(Thousands)

Future cash inflows from sales of oil and gas	$	17,014
Future production and development costs		(10,853	)
Future asset retirement obligations, net of salvage		(16,451	)
Future income tax expense		(95	)

Future net cash flows		(10,385	)
Effect of discounting future net cash flowsat 10% per annum		461
Standardized measure of discounted futurenet cash flows	$	(9,924	)

	Development Wells⁽¹⁾
	Productive				Dry
	Gross		Net		Gross		Net

2016		1.00		0.28		-		-
2015		1.00		0.11		-		-

	December 31, 2016					December 31, 2015
	Amount		%			Amount		%
	(Amounts in Thousands)					(Amounts in Thousands)

Working capital	$	19,577		65	%	$	20,421		57	%
Property and equipment (net)		10,266		34			14,946		42
Other		223		1			266		1
Total	$	30,066		100	%	$	35,633		100	%

Deferred income taxes	$	74		-	%	$	74		-	%
Long-term liabilities		17,794		59			17,399		49
Partners' equity		12,198		41			18,160		51
Total	$	30,066		100	%	$	35,633		100	%

	2016						2015
	Dollars			%			Dollars			%
	(Amounts in Thousands)
Operating Activities:
Net loss before adjustments	$	(5,963	)		(52	)%	$	(21,530	)		(535	)%
Adjustments		5,372			47			22,289			554
Cash flow from operations beforeworking capital changes		(591	)		(5	)		759			19
Changes in working capital		(626	)		(6	)		464			11
Net cash provided by (used in)operating activities		(1,217	)		(11	)		1,223			30

Investing Activities:
Purchase of investments		(10,080	)		(87	)		-			-
Payments received on notesreceivables from employees		37			-			30			1
Advances disbursed to employees		-			-			(14	)		-
Purchase of property and equipment		(249	)		(2	)		(101	)		(2	)
Proceeds from sale of propertyand equipment		-			-			17			-
Proceeds from sale of other assets		-			-			250			6
Net cash provided by (used in)investing activities		(10,292	)		(89	)		182			5

Financing Activities:
Distributions		-			-			(3,963	)		(98	)
Repurchase of Units		-			-			(122	)		(3	)
Proceeds from options exercised		-			-			61			1
Net cash used in financing activities		-			-			(4,024	)		(100	)

Net change in cash and equivalents	$	(11,509	)		(100	)%	$	(2,619	)		(65	)%

	Year Ended December 31,

	2016			2015

Revenues:
Crude oil and natural gas sales		89	%		90	%
Well management and operating		10			8
Other		1			2
Total revenues		100			100

Expenses:
Production costs		56			43
Well management and operating		6			5
Depreciation, depletion and amortization		123			195
Accretion expense		10			10
Write down/impairment and abandonment ofcrude oil and natural gas properties		2			151
General and administrative expense		60			42
Total expenses		257			446

Other income		2			4

Income tax benefit		1			2

Net loss		(154	)%		(340	)%

	2016		2015
ASSETS

CURRENT ASSETS
Cash and equivalents	$	11,224,865	$	22,734,047
Investments		10,080,608		-
Accounts receivable:
Production		1,014,946		572,502
Joint venture partners		3,366		4,151
Employees' notes receivable		41,000		35,000
Other		52,831		45,838
Total current assets		22,417,616		23,391,538

PROPERTY AND EQUIPMENT
Proved properties (successful efforts accounting method)		181,447,571		181,293,110
Pipeline and support equipment		682,135		631,757
Corporate and other		2,116,482		2,114,844
Gross property and equipment		184,246,188		184,039,711
Less accumulated depreciation, depletion, amortizationand write down		173,979,881		169,093,931
Net property and equipment		10,266,307		14,945,780

OTHER ASSETS
Employees' notes receivable		46,045		89,437
Other		176,558		176,442
Total other assets		222,603		265,879

TOTAL ASSETS	$	32,906,526	$	38,603,197

	2016		2015
LIABILITIES AND PARTNERS' EQUITY

CURRENT LIABILITIES
Accounts payable	$	1,703,441	$	1,839,816
Accrued expenses		1,137,290		1,130,772
Total current liabilities		2,840,731		2,970,588

DEFERRED INCOME TAXES		74,000		74,000

JOINT VENTURE PARTNER ADVANCES		1,053,582		1,004,953

ASSET RETIREMENT OBLIGATIONS		16,740,630		16,393,560

COMMITMENTS AND CONTINGENCIES

LIMITED PARTNERS' EQUITY, SUBJECT TOREPURCHASE RIGHT
Authorized - 8,000,000 UnitsIssued and outstanding - 5,587,616		12,052,848		17,944,611

GENERAL PARTNER'S EQUITY		144,735		215,485
Total partners' equity		12,197,583		18,160,096


TOTAL LIABILITIES AND PARTNERS' EQUITY	$	32,906,526	$	38,603,197

	2016			2015

PARTNERS' EQUITY – BEGINNING OF YEAR	$	18,160,096		$	43,714,129


Net loss		(5,962,513	)		(21,529,661	)


Cash distributions ($0.70 per unit in 2015)		-			(3,963,328	)


Repurchase of Units		-			(122,089	)


Options exercised		-			61,045


PARTNERS' EQUITY – END OF YEAR	$	12,197,583		$	18,160,096

	2016			2015

Beginning of period	$	16,736,560		$	11,108,044
Liabilities incurred		1,144			432
Liabilities settled		(6,609	)		(79,620	)
Accretion expense		393,535			583,792
Revisions in estimated cash flows		-			5,123,912

End of period	$	17,124,630		$	16,736,560


		~~Page~~

~~REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM~~		~~F-3~~

~~FINANCIAL STATEMENTS~~
	~~Consolidated balance sheets~~	~~F-4 - F-5~~
	~~Consolidated statements of operations~~	~~F-6~~
	~~Consolidated statements of partners' equity~~	~~F-7~~
	~~Consolidated statements of cash flows~~	~~F-8~~
	~~Notes to consolidated financial statements~~	~~F-9 - F-27~~

	2016			2015
REVENUES
Crude oil and natural gas sales	$	3,439,081		$	5,728,206
Well management and operating		409,454			499,898
Other		32,719			109,408
Total revenues		3,881,254			6,337,512

DIRECT COST OF REVENUES
Production costs		2,164,682			2,734,789
Well management and operating		239,815			296,712
Depreciation, depletion and amortization		4,753,321			12,363,647
Accretion expense		393,535			583,792
Write down/impairment and abandonment ofcrude oil and natural gas properties		88,329			9,575,275
Total direct cost of revenues		7,639,682			25,554,215

GENERAL AND ADMINISTRATIVE EXPENSE		2,315,882			2,709,530
Total cost of revenues		9,955,564			28,263,745


LOSS FROM OPERATIONS		(6,074,310	)		(21,926,233	)

OTHER INCOME
Interest and dividend income		92,216			34,222
Gain on sale of property and equipment		-			13,298
Gain on sale of other assets		-			239,652
Total other income		92,216			287,172

LOSS BEFORE INCOME TAXES		(5,982,094	)		(21,639,061	)

INCOME TAX EXPENSE (BENEFIT)
Current		(19,581	)		10,600
Deferred		-			(120,000	)
Total income tax benefit		(19,581	)		(109,400	)

NET LOSS	$	(5,962,513	)	$	(21,529,661	)


Allocation of Partnership Net Loss:
Limited Partners	$	(5,891,763	)	$	(21,274,495	)
General Partner		(70,750	)		(255,166	)

	$	(5,962,513	)	$	(21,529,661	)


Net loss per unit	$	(1.05	)	$	(3.80	)

	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(5,962,513	)	$	(21,529,661	)
Adjustments to reconcile net loss to net cash providedby (used in) operating activities:
Depreciation, depletion and amortization		4,840,987			12,452,899
Accretion expense		393,535			583,792
Write down/impairment and abandonment ofcrude oil and natural gas properties		88,329			9,575,275
Gain on sale of property and equipment		-			(13,298	)
Gain on sale of other assets		-			(239,652	)
Deferred income taxes		-			(120,000	)
Changes in assets and liabilities:
Accounts receivable		(441,659	)		892,004
Other current assets		(6,993	)		10,600
Other assets		(116	)		860
Accounts payable		(136,375	)		19,884
Accrued expenses		(41,091	)		(458,779	)
Joint venture partner advances		48,629			48,881
Total adjustments		4,745,246			22,752,466
Net cash provided by (used in) operating activities		(1,217,267	)		1,222,805

CASH FLOWS FROM INVESTING ACTIVITIES
Purchase of investments		(10,080,608	)		-
Payments received on notes receivables from employees		37,392			30,283
Advances disbursed to employees		-			(14,171	)
Purchase of property and equipment		(248,699	)		(101,084	)
Proceeds from sale of property and equipment		-			17,355
Proceeds from sale of other assets		-			249,652
Net cash provided by (used in) investing activities		(10,291,915	)		182,035

CASH FLOWS FROM FINANCING ACTIVITIES
Distributions		-			(3,963,328	)
Repurchase of Units		-			(122,089	)
Proceeds from options exercised		-			61,045
Net cash used in financing activities		-			(4,024,372	)

NET CHANGE IN CASH AND EQUIVALENTS		(11,509,182	)		(2,619,532	)

CASH AND EQUIVALENTS AT BEGINNING OF YEAR		22,734,047			25,353,579

CASH AND EQUIVALENTS AT END OF YEAR	$	11,224,865		$	22,734,047

Supplemental disclosures of cash flow information:
Cash paid during the year for:
Income taxes	$	390		$	12,270

	2016		2015
Accounts Payable:
Production and related other	$	1,364,131	$	1,501,647
Other		292,076		290,935
Joint venture partner deposits		47,234		47,234

	$	1,703,441	$	1,839,816

Accrued Expenses:
Payroll and retirement plan contributions	$	641,326	$	679,934
Current portion of asset retirement obligations		384,000		343,000
Other		79,500		75,300
Federal, state and local taxes		32,464		32,538

	$	1,137,290	$	1,130,772

	Per Unit
	Calculated										Units
	Price for		Less								Outstanding
	Repurchase		Interim		Net		Units		Units		Following
Year	Right		Distributions		Price Paid		Repurchased		Issued		Units Activity

2014	$	7.010	$	0.500	$	6.51		11,964		5,982		5,601,003

2015	$	4.935	$	0.375	$	4.56		26,774		13,387		5,587,616

Service cost	$	100,000
Interest cost		49,500
Expected return on plan assets		(64,800	)
Settlements		40,900

Net periodic benefit cost	$	125,600

Change in PBO:

PBO, beginning of year	$	990,700
Service cost		100,000
Interest cost		49,500
Actuarial (gain) loss		(24,700	)
Settlements		(1,115,500	)
Benefits paid		-

PBO, end of year	$	-

Change in Plan assets:

Fair value, beginning of year		640,600
Actual return on plan assets		(800	)
Company contributions		475,700
Benefits paid		(1,115,500	)

Fair value, end of year	$	-

Funded status at December 31, 2015	$	-

Natural Gas Purchaser	2016		2015
Dominion Field Services, Inc. ("Dominion")	25	%	27	%
Interstate Gas Supply, Inc. ("IGS")	13		14

	38	%	41	%

Exhibit No.	Description


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



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


3.3	General Partnership Agreement of Everflow Management Company	(1)


3.4	Articles of Incorporation of Everflow Management Corporation	(1)


3.5	Code of Regulations of Everflow Management Corporation	(1)


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


3.7	Amended and Restated Operating Agreement of Everflow Management Limited, LLC dated December 31, 2008	(4)


3.8	Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Everflow Eastern Partners, L.P.	(8)


10.1	Shareholders Agreement for Everflow Management Corporation	(1)


10.2	Operating facility lease dated October 3, 1995 between Everflow Eastern Partners, L.P. and A-1 Storage of Canfield, Ltd.	(5)



14.1	Code of Ethics	(9)

21.1	Subsidiaries of the Registrant	(6)

31.1	Certification of CEO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	(9)


31.2	Certification of CFO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	(9)


32.1	Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	(9)


99.1	Report of Wright & Company, Inc. dated February 1, 2019 concerning evaluation of oil and gas reserves.	(9)


99.2	Audit Committee Charter of Everflow Management Corporation	(7)

CAPITALIZED COSTS RELATING TO OIL AND GAS
PRODUCING ACTIVITIES

	Years ended December 31,
	2016		2015

Proved oil and gas properties	$	181,447,571	$	181,293,110

Pipeline and support equipment		682,135		631,757

Gross capitalized costs		182,129,706		181,924,867

Accumulated depreciation, depletion, amortization and write down		172,885,338		168,088,105

Net capitalized costs	$	9,244,368	$	13,836,762

COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES

	Years ended December 31,
	2016		2015

Property acquisition costs	$	20,363	$	29,037
Development costs		136,274		72,047

RESULTS OF OPERATIONS FOR OIL AND
GAS PRODUCING ACTIVITIES

	Years ended December 31,
	2016			2015

Crude oil and natural gas sales	$	3,439,081		$	5,728,206
Production costs		(2,164,682	)		(2,734,789	)
Depreciation, depletion and amortization		(4,753,321	)		(12,363,647	)
Accretion expense		(393,535	)		(583,792	)
Write down/impairment and abandonment of crude oil and natural gas properties		(88,329	)		(9,575,275	)

Results of operations before income tax expense (benefit)		(3,960,786	)		(19,529,297	)

Income tax expense (benefit)		(20,000	)		11,000

Results of operations for oil and gas producing activities (excluding corporate overhead and financing costs)	$	(3,940,786	)	$	(19,540,297	)

ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES

	Oil			Gas
	(BBLS)			(MCF)

Balance, January 1, 2015		511,000			23,724,000
Extensions, discoveries and other additions		2,000			5,000
Production		(44,000	)		(1,616,000	)
Revision of previous estimates		(192,000	)		(14,122,000	)

Balance, December 31, 2015		277,000			7,991,000
Extensions, discoveries and other additions		5,000			13,000
Production		(34,000	)		(1,157,000	)
Revision of previous estimates		(4,000	)		(1,567,000	)

Balance, December 31, 2016		244,000			5,280,000

PROVED DEVELOPED RESERVES:

December 31, 2014		511,000			23,724,000
December 31, 2015		277,000			7,991,000
December 31, 2016		244,000			5,280,000

STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS


	December 31,
	2016			2015
	(Thousands of Dollars)
Future cash inflows from sales of oil and gas	$	17,014		$	23,821
Future production and development costs		(10,853	)		(15,446	)
Future asset retirement obligations, net of salvage		(16,451	)		(16,443	)
Future income tax expense		(95	)		(144	)

Future net cash flows		(10,385	)		(8,212	)
Effect of discounting future net cash flows at 10% per annum		461			1

Standardized measure of discounted future net cash flows	$	(9,924	)	$	(8,211	)

CHANGES IN THE STANDARDIZED MEASURE OF
DISCOUNTED FUTURE NET CASH FLOWS


	Years Ended December 31,
	2016			2015
	(Thousands of Dollars)

Balance, beginning of year	$	(8,211	)	$	28,157
Extensions, discoveries and other additions		85			30
Revision of quantity estimates		(184	)		(2,562	)
Sales of crude oil and natural gas, net of production costs		(1,274	)		(2,993	)
Net change in income taxes		32			573
Net changes in prices and production costs		(1,080	)		(31,254	)
Accretion of discount		(821	)		2,816
Other		1,529			(2,978	)

Balance, end of year	$	(9,924	)	$	(8,211	)

~~Name~~		~~Age~~	~~Positions and Offices with EEI~~	~~Positions andOffices with EMC~~
~~Thomas L. Korner~~101.INS		63	~~Chairman of the Board and director~~	~~Chairman of the Board and director~~Instance Document

101.SCH	XBRL Taxonomy Extension Schema Document

~~Robert F. Sykes~~101.CAL		93	~~Director~~	~~Director~~XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF	XBRL Taxonomy Extension Definition Document

~~Peter H. Sykes~~101.LAB		60	~~None~~	~~Director~~XBRL Taxonomy Extension Label Linkbase Document

~~William A. Siskovic~~		61	~~President, Principal Executive Officer and director~~	~~President, Principal Executive Officer and director~~

~~Brian A. Staebler~~		42	~~Vice President, Secretary- Treasurer, Principal Financial and Accounting Officer and director~~	~~Vice President, Secretary- Treasurer, Principal Financial and Accounting Officer and director~~

	SUMMARY COMPENSATION TABLE

	Annual Compensation

						Options		Other
Name and Principal Position	Year	Salary		Bonus		Awards⁽¹⁾		Compensation⁽²⁾			Total

William A. Siskovic,	2016	$	125,200	$	183,000	$	-	$	40,800	(3)	$	349,000
President and Principal Executive Officer	2015	$	125,200	$	175,000	$	-	$	83,220	(3)	$	383,420

Brian A. Staebler,	2016	$	115,400	$	135,000	$	-	$	35,200	(4)	$	285,600
Vice President and Principal Financial and Accounting Officer	2015	$	113,000	$	130,000	$	-	$	76,090	(4)	$	319,090


(4)	~~During fiscal years~~Incorporated herein by reference to the appropriate exhibit to the Registrant's Annual Report on Form 10-K for the year ended December 31, ~~2016 and 2015, includes $15,600 and $24,360, respectively, contributed as profit sharing~~2008 (File No. 0-19279).

(5)	Incorporated herein by reference to the ~~Defined Contribution Plan, $15,100 and $7,310, respectively, contributed as matching contributions~~appropriate exhibit to the ~~Defined Contribution Plan, $0 and $40,500, respectively, awarded as benefits~~Registrant's Quarterly Report on Form 10-Q for the third quarter ended September 30, 1995 (File No. 0-19279).

(6)	Incorporated herein by reference to the ~~Pension Plan, $3,200 and $2,590, respectively, considered taxable wages with respect to personal use of a Company vehicle, and $1,300 and $1,330 considered taxable wages with respect~~appropriate exhibit to the ~~Company’s Group Term Life Insurance Plan and additional supplemental life insurance.~~Registrant's Annual Report on Form 10-K for the year ended December 31, 1995 (File No. 0-19279).

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

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

(9)	Incorporated herein by reference to the appropriate exhibit to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2018 (File No. 0-19279).

					Percentage
					Interest in
			Percentage		Everflow		Percentage
	Units in		of Units in		Management		Interest in
Name of Holder	Company		Company⁽¹⁾		Limited, LLC⁽²⁾		EMC

Directors and Executive Officers
Robert F. Sykes⁽³⁾(director of EMC)		158,634		2.84		*		*
William A. Siskovic (officer and director of EMC)		86,329		1.55		16.6667		16.6667
Thomas L. Korner (Chairman of the Board & director of EMC)		64,476		1.15		16.6667		16.6667
Peter H. Sykes⁽⁴⁾(director of EMC)		41,244		0.74		*		*
Brian A. Staebler (officer and director of EMC)		15,462		0.28		8.3333		8.3333
		366,145		6.56		41.6667		41.6667

Other Beneficial Owners of >5% of the Company
David F. Sykes⁽⁵⁾		774,099		13.85		50.0000		50.0000
		1,140,244		20.41		91.6667		91.6667

~~Positions and~~

~~Positions and~~

~~Offices with EEI~~

~~Offices with EMC~~

~~William A. Siskovic~~

~~President, Principal Executive Officer and director~~

~~President, Principal Executive Officer and director~~

~~Brian A. Staebler~~

~~Vice President, Secretary- Treasurer, Principal Financial and Accounting Officer and director~~

~~Vice President, Secretary- Treasurer, Principal Financial and Accounting Officer and director~~