EVERFLOW EASTERN PARTNERS LP - FORM 10-K

EVERFLOW EASTERN PARTNERS LP - FORM 10-K - March 26, 2014

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EX-31.2 - EX-31.2 - EVERFLOW EASTERN PARTNERS LP	d659150dex312.htm
EX-14.1 - EX-14.1 - EVERFLOW EASTERN PARTNERS LP	d659150dex141.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the Fiscal Year Ended December 31, 2013

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

Commission File No. 0-19279

EVERFLOW EASTERN PARTNERS, L.P.

(Exact name of registrant as specified in its charter)


Delaware		34-1659910
(State or other jurisdiction of 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)

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

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


Title of each class		Name of each exchange on which registered

None

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

Units of Limited Partnership Interest

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) 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. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 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 4,482,626 Units of Limited Partnership Interest held by non-affiliates of the Registrant as of June 30, 2013. At June 30, 2013, there was no public market for the Registrant’s Units of Limited Partnership Interest. 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, 2013.

PART I

ITEM 1. BUSINESS

Introduction

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

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

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

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

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

Description of the Business

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

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

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

Current Operations. The properties of the Company consist in large part of fractional undivided working interests in properties containing proved reserves of oil and gas located in the Appalachian Basin region of Ohio and Pennsylvania. Approximately 63% of the estimated total future cash inflows related to the Company’s crude oil and natural gas reserves as of December 31, 2013 are attributable to natural gas reserves. The majority of such properties are located in Ohio and consist primarily of proved producing properties with established production histories.

The Company’s operations since February 1991 primarily involve the production and sale of oil and gas and the drilling and development of approximately 442 (net) wells. The Company serves as the operator of approximately 59% of the gross wells and 75% 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 of Deep Rights. In recent years, the Company had agreed to sell 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, resulting in a Gain on Sales of Deep Rights of approximately $39.1 million.

Included in the acreage sold as part of one of the Dispositions in 2012, the Company sold approximately 2,200 acres with leases that contained terms and conditions which would have required the Company to repurchase the acreage if certain claims were made by February 2013 (the “Contingent Leases”). The Company recognized Gain on Sales of Deep Rights of $2.7 million during 2013 in conjunction with the Contingent Leases once the claim period had expired, with no claims having been made. The Company had no other sales of deep rights in 2013.

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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, 2013, the Company’s current leasehold inventory consists of approximately 40 prospects in various stages of maturity representing approximately 498 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 2013 or 2012.

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. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Results of Operations.”

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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 2013 or 2012 and no principal indebtedness was outstanding as of March 10, 2014. 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. The Company expects that borrowings may be necessary to enable it to repurchase Units tendered in connection with the Repurchase Right (as defined under ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES). 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, 2013, which aggregate $41,661,000 (Standardized Measure of Discounted Future Net Cash Flows).

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

Crude Oil. Any crude oil produced from the properties can be sold at the prevailing field price to one or more of a number of unaffiliated purchasers in the area. Generally, purchase contracts for the sale of crude oil are cancelable on 30 days notice. The price paid by these purchasers is generally an established or “posted” price which is offered to all producers. Historically, all posted prices in the areas where the Company’s properties are located have generally been somewhat lower than the spot market prices. In recent years, however, including 2013, the spread between posted prices in the areas where the Company’s properties are located and spot market prices has significantly decreased, and in some months has even reversed. There have been substantial fluctuations in crude oil prices in recent years, including 2013.

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, 2014, $97.12 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.

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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 2013, 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 numerous annual contracts with Dominion, which obligate Dominion to purchase, and the Company to sell and deliver, certain quantities of natural gas production from the Company’s oil and gas properties throughout the contract periods. The Company may elect to lock-in specific volumes of natural gas to be sold in specific months at a mutually agreeable price. The Company has elected to lock-in various monthly quantities of natural gas which total 1.40 BCF through October 2015 at various monthly prices with a weighted average of $3.70 per MCF.

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The Company also has multiple 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. The Company has elected to lock-in various monthly quantities of natural gas which total .84 BCF through October 2015 at various monthly prices with a weighted average of $3.73 per MCF.

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 prices 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. As of December 31, 2013, natural gas purchased by Dominion covers production from approximately 480 gross operated wells, while natural gas purchased by IGS covers production from approximately 200 gross operated wells. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Inflation and Changes in Prices.”

The market price for natural gas in the Appalachian Basin experienced a decline relative to the price at Henry Hub in the second half of 2013 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 2013, no one natural gas purchaser accounted for more than 10% of the Company’s natural gas sales other than Dominion and IGS, who’s purchases of natural gas from operated wells accounted for approximately 47% and 20%, 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 2014.

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 generally 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.

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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 2013, 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” above.

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

Regulation of Oil and Gas Industry. The exploration, production and sale of oil and natural gas are subject to numerous state and federal laws and regulations. Such laws and regulations govern a wide variety of matters, including the drilling and spacing of wells, allowable rates of production, marketing, pricing and protection of the environment. Such regulations may restrict the rate at which the Company’s wells produce crude oil and natural gas below the rate at which such wells could produce in the absence of such regulations. In addition,

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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.

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

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

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

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

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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, 2014, the Company had 18 full-time and 3 part-time employees. These employees primarily are engaged in the following areas of business operations: six each in accounting and administration, five in field operations and four in land and lease acquisition.

ITEM 1A. RISK FACTORS

Not a required disclosure for a Smaller Reporting Company.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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ITEM 2. PROPERTIES

Set forth below is certain information regarding the oil and gas properties of the Company which are located in the Appalachian Basin of Ohio and Western 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 Western 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, excluding the effect of contractual obligations, were $3.43 and $2.73 at December 31, 2013 and 2012, respectively, and the crude oil prices used in the estimation of proved reserves were $94.49 and $92.25 at December 31, 2013 and 2012, 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, 2013, 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

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regulations applicable as of December 31, 2013. 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 2013 or 2012.

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, 2013.


	Oil (BBLS)		Gas (MCF)
Proved Developed		586,000		27,653,000
Proved Undeveloped		—		—

Total		586,000		27,653,000

(1)	The Company has not determined proved reserves associated with its proved and other undeveloped properties, including its deep property interests, at December 31, 2013. A reconciliation of the Company’s proved reserves is included in the Notes to the Consolidated Financial Statements.

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 2013 and 2012.


	Production				Average Sales Price				Average Lifting Cost
	Oil (BBLS)		Gas (MCFS)		per BBL		per MCF		per Equivalent MCF⁽¹⁾
2013		62,000		2,846,000	$	94.92	$	3.84	$	1.25
2012		65,000		2,666,000	$	92.54	$	3.63	$	1.33

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

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Productive Wells. The following table sets forth the gross and net oil and gas wells of the Company as of December 31, 2013.


Gross Wells					Net Wells
Oil (1)	Gas (1)		Total		Oil (1)	Gas (1)		Total
368		1,077		1,445	205		677		882

(1)	Oil wells are those wells which generated the majority of their revenues from crude oil production during 2013; gas wells are those wells which generated the majority of their revenues from natural gas production during 2013.

Standardized Measure of Discounted Future Net Cash Flows.(1) The following table summarizes, as of December 31, 2013, 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, 2013, discounted to present value at 10%.


	(Thousands)
Future cash inflows from sales of oil and gas	$	150,370
Future production and development costs		(67,947	)
Future asset retirement obligations, net of salvage		(11,668	)
Future income tax expense		(1,570	)

Future net cash flows		69,185
Effect of discounting future net cash flows at 10% per annum		(27,524	)

Standardized measure of discounted future net cash flows	$	41,661

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

Acreage. The Company had approximately 58,900 gross developed acres and 38,000 net developed acres as of December 31, 2013. Developed acreage is that acreage assignable to productive wells. The Company had approximately 498 gross and net proved undeveloped acres as of December 31, 2013.

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Drilling Activity. The following table sets forth the results of drilling activities during 2013 and 2012 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.


	Development Wells⁽¹⁾
	Productive				Dry
	Gross		Net		Gross		Net
2013		6.00		1.86		—		—
2012		—		—		—		—

⁽¹⁾	All wells are located in the United States. All wells are development wells.

No exploratory wells were drilled.

Present Activities. The Company has not drilled any wells since December 31, 2013, nor are there any wells in process of being drilled as of March 10, 2014.

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 67% of the Company’s consolidated natural gas sales during 2013. In addition, the Company has entered into various short-term contracts which obligate the purchasers to purchase and the Company to sell and deliver undetermined quantities of natural gas production on a monthly basis throughout the term of the contracts.

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

ITEM 3. LEGAL PROCEEDINGS

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

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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SUPPLEMENTAL ITEM — EXECUTIVE OFFICERS OF THE REGISTRANT

The executive officers of EEI and EMC as of March 10, 2014 are as follows:


Name	Age	Positions and Offices with EEI	Positions and Offices with EMC
William A. Siskovic	58	President, Principal Executive Officer and director	President, Principal Executive Officer and director
Brian A. Staebler	39	Vice President, Secretary-Treasurer, Principal Financial and Accounting Officer and director	Vice President, Secretary-Treasurer, Principal Financial and Accounting Officer and director

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.

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PART II

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

Market

There is currently no established public trading market for the Units. At the present time, the Company does not intend to list any of the Units for trading on any exchange or otherwise take any action to establish any market for the Units. As of March 10, 2014, there were 5,606,985 Units held by 1,402 holders of record.

Distribution History

The Company commenced operations with the consummation of the Exchange Offer in February 1991. Management’s stated intention was to make quarterly cash distributions equal to $0.125 per Unit (or $0.50 per Unit on an annualized basis) for the first eight quarters following the closing date of the Exchange Offer. The Company has paid a quarterly distribution every quarter since July 1991. The Company paid total quarterly cash distributions of $1.75 per Unit during each of 2013 and 2012, respectively. Based upon the current number of Units outstanding, the aggregate value of a quarterly distribution of $0.25 per Unit made to our holders of record (“Holders”) would amount to approximately $1,419,000. The Company made a quarterly distribution of $0.25 per Unit in January 2014 and currently intends to make a distribution of $0.25 per Unit in April 2014 and additional quarterly distributions in July and October 2014. In association with the proceeds received from the Dispositions, the Company also paid special cash distributions during 2012 of $6.15 per Unit, totaling approximately $34.9 million.

Repurchase Right

The Partnership Agreement provides that beginning in 1992 and annually thereafter the Company offers to repurchase for cash up to 10% of the then outstanding Units, to the extent Holders offer Units to the Company for repurchase (the “Repurchase Right”). The Repurchase Right entitles any Holder(s), between May 1 and June 30 of each year, to notify the Company that the Holder(s) elects to exercise the Repurchase Right and have the Company acquire certain or all Units. The 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 9,460 and 9,414 of its Units of limited partnership interest at a price of $4.92 and $8.29 per Unit pursuant to the terms of the Company’s Offers to Purchase dated April 30, 2013 and 2012, respectively. See Note 3 in the Company’s consolidated financial statements for additional information on the Repurchase Right.

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ITEM 6. SELECTED FINANCIAL DATA

Not a required disclosure for a Smaller Reporting Company.

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

General

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

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

The General Partner is a limited liability company. 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.

Sales of Deep Rights

In recent years, the Company agreed to sell 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, resulting in a Gain on Sales of Deep Rights of approximately $39.1 million.

Included in the acreage sold as part of one of the Dispositions in 2012, the Company sold approximately 2,200 acres with leases that contained terms and conditions which would have required the Company to repurchase the acreage if certain claims were made by February 2013 (the “Contingent Leases”). Deferred revenue of $2.7 million was recognized in the Company’s consolidated balance sheet at December 31, 2012 in association with the funds

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held for Contingent Leases. The Company did not recognize gain on the sale of the Contingent Leases until the claim period ending February 2013 had expired, with no such claims having been made. Deferred income tax expense of $509,000 was also recognized during 2013 in conjunction with revenue recognized from expired contingencies. The Company had no other sales of deep rights in 2013.

In association with the proceeds received from the Dispositions, the Company paid special cash distributions during 2012 of $6.15 per unit to the unitholders (the “Special Distributions”), totaling approximately $34.9 million. There were no special cash distributions paid during 2013.

The Company’s Sales of Deep Rights are further described in Note 9 of the Company’s consolidated financial statements included herein.

Liquidity and Capital Resources

Financial Position

The following table summarizes the Company’s financial position at December 31, 2013 and December 31, 2012:


	December 31, 2013					December 31, 2012
	Amount		%			Amount		%
	(Amounts in Thousands)					(Amounts in Thousands)
Working capital	$	23,853		42	%	$	22,048		39	%
Property and equipment (net)		32,011		57			34,573		61
Other		284		1			336		—

Total	$	56,148		100	%	$	56,957		100	%

Deferred income taxes	$	214		—	%	$	234		—	%
Long-term liabilities		7,976		14			7,419		13
Partners’ equity		47,958		86			49,304		87

Total	$	56,148		100	%	$	56,957		100	%

Working capital surplus of $23.9 million as of December 31, 2013 represented a $1.8 million increase from December 31, 2012 due primarily to decreases in accounts payable and deferred revenue, offset somewhat by decreases in cash and equivalents and deferred income taxes. Accounts payable decreased $442,000 primarily due to less payables due for production and related other expenses and less payables due to outside working interest parties in association with proceeds held for their share of Contingent Leases, which were paid after the February 2013 claim period had expired. Deferred revenue decreased $2.7 million due to recognition of revenue associated with the Contingent Leases. Deferred income tax assets decreased $509,000 as the result of temporary book-to-tax differences expiring in relation to the recognition of revenues derived from EEI’s share of the Contingent Leases.

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Property and equipment of $32.0 million as of December 31, 2013 represented a $2.6 million decrease from December 31, 2012 due primarily to $3.6 million of depreciation, depletion and amortization recognized in 2013, offset somewhat by $1.1 million of purchases of property and equipment made in 2013.

Long-term liabilities of $8.0 million as of December 31, 2013 represented an increase of $557,000 million from December 31, 2012 due primarily to $155,000 of advances collected from joint venture partners in 2013 for their share of future plugging expenses and an increase of $403,000 in asset retirement obligations resulting primarily from accretion recognized in 2013 to adjust the liabilities to their present value at December 31, 2013.

The Company had a revolving credit facility with Bank One, N.A. that expired in 2003, and has had no borrowings since that time. The Company expects to have more than $4 million of cash available to fund the Repurchase Right in 2014. As a result, additional financing will not likely be required in the event the Repurchase Right is fully subscribed. In the event that additional financing is necessary to fund the Repurchase Right, the Company would likely enter into a commitment for a new line of credit. We cannot provide any assurance as to the availability of any such line of credit under current market conditions. The Company repurchased 9,460 Units at a price of $4.92 per Unit in June 2013.

Cash Flows from Operating, Investing and Financing Activities

The Company generated the majority of its cash sources from operating activities during 2013, while the majority of its cash sources in 2012 were generated by investing activities. During 2013, cash provided by operations was used primarily to fund the development of additional oil and gas properties and distributions to Unitholders. During 2012, cash provided by operations and investing activities was used primarily to fund distributions to Unitholders.

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The following table summarizes the Company’s Consolidated Statements of Cash Flows for the years ended December 31, 2013 and 2012:


	2013						2012
	Dollars			%			Dollars			%
	(Amounts in Thousands)
Operating Activities:
Net income before adjustments	$	8,612			75	%	$	38,074			78	%
Adjustments		1,954			17			(31,638	)		(65	)

Cash flow from operations before working capital changes		10,566			92			6,436			13
Changes in working capital		(499	)		(4	)		1,801			4

Net cash provided by operating activities		10,067			88			8,237			17
Investing Activities:
Proceeds received from employees’ notes receivables		92			1			188			—
Advances disbursed to employees		(34	)		—			(12	)		—
Proceeds from deferred revenue		—			—			2,705			6
Purchase of property and equipment		(1,141	)		(10	)		(400	)		(1	)
Proceeds from sales of deep rights and property and equipment		39			—			38,351			78

Net cash (used) provided by investing activities		(1,044	)		(9	)		40,832			83
Financing Activities:
Distributions		(9,934	)		(87	)		(44,890	)		(92	)
Repurchase and retirement of Units		(47	)		—			(78	)		—
Options exercised		23			—			39			—

Net cash used by financing activities		(9,958	)		(87	)		(44,929	)		(92	)

Net change in cash and equivalents	$	(935	)		(8	)%	$	4,140			8	%

Note:

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

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As the above table indicates, the Company’s cash flow from operations before working capital changes during 2013 and 2012 represented 92% and 13% of total cash sources, respectively. The increase in cash flow from operations as a percentage of total cash sources before working capital changes in 2013, as compared to the prior comparable period, was primarily due to the significant effect $39.1 million of gain on sales of deep rights had on total cash sources during 2012 as compared to 2013. Changes in working capital other than cash and equivalents decreased cash by $499,000 during 2013 and increased cash by $1.8 million during 2012. The $499,000 decrease in 2013 was primarily the result of decreases in accounts payable and accrued expenses, offset somewhat by the effect of a decrease in accounts receivable from production. Accounts payable decreased primarily due to less payables due for production and related other expenses and less payables due to outside working interest parties in association with proceeds held for their share of Contingent Leases at December 31, 2013, as compared to the prior period. Accrued expenses decreased primarily due to less expenses accrued in association with payroll and retirement plan contributions and federal taxes at December 31, 2013, as compared to the prior comparable period. Accounts receivable from production decreased primarily due to less natural gas volumes produced during the fourth quarter of 2013 as compared to the prior comparable period. The $1.8 million increase in 2012 was primarily the result of a decrease in accounts receivable from production as well as increases in accounts payable and accrued expenses. The decrease in accounts receivable from production was primarily the result of less natural gas and crude oil volumes produced and lower natural gas and crude oil prices received during the fourth quarter of 2012 as compared to the prior comparable period. The increase in accounts payable was primarily due to proceeds received during 2012, and held at December 31, 2012, in association with unaffiliated working interest parties’ share of Contingent Leases. Accrued expenses increased primarily as the result of expenses incurred in association with the Company’s retirement plans during the fourth quarter of 2012 that were not incurred during the prior comparable period.

The Company’s cash flows used by investing activities were $1.0 million in 2013, whereas the Company’s cash flows provided by investing activities were $40.8 million in 2012. The variance from 2012 was primarily the result of proceeds received from sales of deep rights and deferred revenue of $38.4 million and $2.7 million, respectively, in 2012, whereas there were no proceeds received from such activities during 2013. In addition, there were additional property and equipment purchases of $741,000 in 2013, as compared to the prior period.

The Company’s cash flows used by financing activities decreased $35.0 million, or 78%, during 2013 as compared with the prior comparable period, which was primarily the result of less distributions made to Unitholders. The majority of 2012 distributions were Special Distributions.

The Company’s ending cash and equivalents balance of $24.5 million at December 31, 2013, as well as on-going monthly operating cash flows, should be adequate to meet short-term cash requirements. The Company has established a quarterly distribution and management believes the payment of such quarterly distributions will continue at least through 2014. The Company has paid a quarterly distribution every quarter since July 1991. The Company made a distribution of $1.4 million in January 2014 and currently intends to distribute an additional $1.4 million in April 2014 from existing cash and equivalents.

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Capital expenditures for the development of oil and gas properties increased during 2013 as compared to the prior comparable period, as the Company participated in the drilling of six new oil and gas properties during 2013. The Company’s share of proved gas reserves increased by 2.0 BCF, or 8%, between December 31, 2013 and December 31, 2012, while proved oil reserves increased by 7,000 barrels, or 1%, between December 31, 2013 and December 31, 2012. The Standardized Measure of Discounted Future Net Cash Flows of the Company’s reserves increased by $8.1 million between December 31, 2013 and December 31, 2012. The primary reasons for this increase were due increases in natural gas and crude oil prices and the related upward revisions in quantities of natural gas and crude oil reserves between December 31, 2013 and 2012, in addition to accretion of the December 31, 2012 discount. These factors were offset somewhat by 2013 sales of crude oil and natural gas. Management believes the Company will likely drill or participate in the drilling of less than 10 net wells during 2014.

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 repurchased 9,460 and 9,414 Units during 2013 and 2012 pursuant to the Repurchase Right at a price of $4.92 and $8.29 per Unit, respectively. The Repurchase Right to be conducted in 2014 is expected to result in Unitholders being offered a price of $6.51 per Unit. The Company believes existing cash flows will be sufficient to fund the 2014 offering pursuant to the Repurchase Right if fully subscribed.

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Results of Operations

The following table and discussion is a review of the results of operations of the Company for the years ended December 31, 2013 and 2012. All items in the table are calculated as a percentage of total revenues. This table should be read in conjunction with the discussions of each item below:


	Year Ended December 31,
	2013			2012
Revenues:
Oil and gas sales		96	%		96	%
Well management and operating		4			4

Total Revenues		100			100
Expenses:
Production costs		23			25
Well management and operating		2			2
Depreciation, depletion and amortization		21			34
Accretion expense		2			5
Write down/impairment and abandonment of oil and gas properties		—			6
General and administrative expense		16			18

Total Expenses		64			90
Gain on sales of deep rights		16			241
Income taxes		(3	)		(17	)

Net income		49	%		234	%

Revenues for the year ended December 31, 2013 increased $1.2 million, or 7%, compared to prior comparable period. This increase was due primarily to an increase in oil and gas sales during 2013 as compared with 2012.

Oil and gas sales increased $1.2 million, or 7%, from 2012 to 2013. This increase was primarily the result of higher average natural gas and crude oil prices received as well as higher natural gas volumes produced, offset somewhat by less crude oil volumes produced during 2013, as compared to the prior comparable period. The average price received per MCF of natural gas increased from $3.63 in 2012 to $3.84 in 2013. The average price received per BBL of crude oil increased from $92.54 in 2012 to $94.92 in 2013. The Company’s natural gas production increased by 180,000 MCF, or 7%, while crude oil production decreased by 3,000 BBLS, or 4%, from 2012 to 2013. Natural gas sales accounted for 65% and 62% of total crude oil and natural gas sales in 2013 and 2012, respectively. Higher natural gas production volumes were primarily the result of less operated properties being voluntarily shut-in during 2013 as compared to the prior comparable period.

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Production costs decreased $50,000, or 1%, from 2012 to 2013. This decrease was primarily due a one-time charge from a third party operator that was recognized in 2012 in association with cumulative costs incurred relative to their operations of various oil and gas properties of which the Company participates as a joint venture partner. No such charge was recognized in 2013. The effect of this was offset somewhat by an increase in production costs incurred relative to additional operated properties producing during 2013 due to less shut-ins, as compared to the prior year.

Depreciation, depletion and amortization (“DD&A”) decreased $1.9 million, or 35%, from 2012 to 2013. One reason for this decrease is the result of higher natural gas and crude oil reserves as of the most recent valuation date, December 31, 2013, as compared to the prior valuation date, December 31, 2012. The increase in natural gas and crude oil reserves was primarily the result of higher natural gas and crude oil prices used to value reserves at December 31, 2013 as compared to the prior comparable valuation date. The higher natural gas and crude oil prices contributed to increasing the average economic life of the Company’s oil and gas properties as compared to their prior valuation date. An additional reason for the significant decrease in 2013 DD&A, as compared to the prior year, relates to the significant DD&A and write downs/impairment on the Company’s western Pennsylvania oil and gas properties recognized from 2008-2012, which significantly reduced the net capitalized costs (depletable bases) for such properties. The overall decrease in DD&A was offset somewhat by higher natural gas production volumes in 2013 as compared to the prior year.

Accretion expense decreased $479,000, or 54%, from 2012 to 2013. The primary reason for this decrease was due to many liabilities on certain properties being fully accreted as of December 31, 2012.

Write down/impairment and abandonment of oil and gas properties decreased $945,000, or 96%, from 2012 to 2013. In recent years, the Company had expanded its drilling and development geographically into western Pennsylvania, an area in which it previously had only minimal activity. The drilling and development in this area was conducted through a joint venture with another oil and gas operator with which the Company had previous experience. During 2007 and 2008, the Company invested more than $15 million in western Pennsylvania through this venture. The results were less than expected and since 2008 the Company has ceased investing in this venture. The combination of development costs exceeding estimates and disappointing results in this venture had caused the Company to record $779,000 of non-cash impairment write downs during 2012 that were directly attributable to these western Pennsylvania properties, which represents 80% of the total write down/impairment and abandonment of oil and gas properties incurred during 2012.

General and administrative expenses decreased $207,000, or 7%, from 2012 to 2013. The primary reasons for this decrease are due to less administrative costs associated with sales of deep rights, such as recording fees and contract labor. In addition, payroll and employee benefits expenses decreased primarily as the result of a decrease in workforce in 2013 as compared to 2012.

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The Company recognized gain on sales of deep rights of $2.8 million and $39.1 million during 2013 and 2012, respectively, in association with the Dispositions as further described under “Sales of Deep Rights”, herein.

The Company recognized income taxes of $514,000 during 2013, a decrease of $2.2 million from the prior comparable period. The primary reason for the substantial decrease is the result of less federal income taxes in relation to EEI’s interest in the Dispositions recognized during 2013 as compared to the prior comparable period. The Company is not a tax paying entity, and the net taxable income or loss, other than the taxable income or loss attributable to EEI, is allocated directly to its respective partners.

The Company reported net income of $8.6 million during 2013, a decrease of $29.5 million, or 77%, from the prior comparable period. The primary reason for the decrease is the result of the decrease in gain on sales of deep rights, offset somewhat by the increase in oil and gas sales, decreases to various costs of revenues such as DD&A, accretion expense and write down/impairment and abandonment of oil and gas properties, and the decrease in income taxes. Net income represented 49% and 234% of total revenues during the years ended December 31, 2013 and 2012, respectively.

Application of Critical Accounting Policies

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

Capitalized costs of proved properties, after considering estimated dismantlement and abandonment costs and estimated salvage values, are amortized by the unit-of-production method based upon estimated proved developed reserves. Depletion, depreciation and amortization on proved properties amounted to $3.5 million and $5.5 million for the years ended December 31, 2013 and 2012, 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.

-25-

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

Crude oil and natural gas reserve estimates are prepared annually based on existing contractual arrangements and current market conditions. Any increases in estimated future cash flows would have no impact on the reported value of the Company’s crude oil and natural gas properties. In contrast, decreases in estimated future cash flows could require the recognition of an impairment loss equal to the difference between the estimated fair value of the crude oil and natural gas properties (determined by calculating the discounted value of the estimated future cash flows) and the carrying amount of the crude oil and natural gas properties. Any impairment loss would reduce property and equipment as well as total assets of the Company. An impairment loss would also decrease net income.

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

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

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

-26-

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, 2013 or 2012. Other revenue is 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 property(ies). 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 not yet incurred. The Company earns and receives monthly management and operating fees from certain joint venture partners and employees after the properties are completed and placed into production.

Commodity Pricing, Risk Management Activities and Inflation

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

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.

-27-

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, 2014, $97.12 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 2013 was $3.84, an increase of $0.21 as compared to 2012. The Company’s average price of natural gas during 2012 was $3.63, a decrease of $1.67 as compared to 2011. The Company’s average price of natural gas during 2011 was $5.30, a decrease of $1.62 as compared to 2010. 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 2014 at $4.86 per MCF and the regional basis adjustment settled for the month of March 2014 at $(0.29) per MCF, resulting in a net regional market price of $4.57. The majority of the Company’s natural gas from operated wells is currently sold under short-term contracts where the price is determined using current NYMEX prices plus or minus a regional basis adjustment. The Company at times will lock-in a monthly price for certain volume commitments over certain time periods. 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 decreasing from $88.6 million at December 31, 2008 to $49.7 million at December 31, 2009, increasing 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, and increasing to $41.6 million at December 31, 2013.

The Company’s Standardized Measure of Discounted Future Net Cash Flows increased by $8.1 million from December 31, 2012 to December 31, 2013. A reconciliation of the Changes in the Standardized Measure of Discounted Future Net Cash Flows is included in the Company’s consolidated financial statements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not a required disclosure for a Smaller Reporting Company.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

See attached pages F-1 to F-26.

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

None.

-28-

EVERFLOW EASTERN PARTNERS, L. P.

2013 CONSOLIDATED FINANCIAL REPORT

F-1

EVERFLOW EASTERN PARTNERS, L. P.

CONTENTS


		Page
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM		F-3
FINANCIAL STATEMENTS
	Consolidated balance sheets	F-4 - F-5
	Consolidated statements of income	F-6
	Consolidated statements of partners’ equity	F-7
	Consolidated statements of cash flows	F-8
	Notes to consolidated financial statements	F-9 - F-26

F-2

Report of Independent Registered Public Accounting Firm

To the Partners

Everflow Eastern Partners, L.P.

Canfield, Ohio

We have audited the accompanying consolidated balance sheets of Everflow Eastern Partners, L.P. and subsidiaries (the “Company”) as of December 31, 2013 and 2012, and the related consolidated statements of income, 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, 2013 and 2012, 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.

/s/ Maloney + Novotny LLC

Cleveland, Ohio

March 26, 2014

F-3

EVERFLOW EASTERN PARTNERS, L. P.

CONSOLIDATED BALANCE SHEETS

December 31, 2013 and 2012


	2013		2012
ASSETS
CURRENT ASSETS
Cash and equivalents	$	24,461,680	$	25,397,117
Accounts receivable:
Production		2,195,519		2,260,340
Joint venture partners		10,623		22,150
Deferred income taxes		—		509,000
Employees’ notes receivable		95,000		95,349
Other		139,681		126,531

Total current assets		26,902,503		28,410,487
PROPERTY AND EQUIPMENT
Proved properties (successful efforts accounting method)		174,811,480		174,044,579
Pipeline and support equipment		666,667		666,667
Corporate and other		2,092,582		2,049,315

		177,570,729		176,760,561
Less accumulated depreciation, depletion, amortization and write down		145,560,225		142,187,705

		32,010,504		34,572,856
OTHER ASSETS
Employees’ notes receivable		118,262		176,118
Other		165,279		159,599

		283,541		335,717

	$	59,196,548	$	63,319,060

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

F-4

EVERFLOW EASTERN PARTNERS, L. P.

CONSOLIDATED BALANCE SHEETS

December 31, 2013 and 2012


	2013		2012
LIABILITIES AND PARTNERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	1,684,610	$	2,126,433
Accrued expenses		1,364,183		1,531,232
Deferred revenue		—		2,705,135

Total current liabilities		3,048,793		6,362,800
DEFERRED INCOME TAXES		214,000		234,000
JOINT VENTURE PARTNER ADVANCES		880,270		725,760
ASSET RETIREMENT OBLIGATIONS		7,095,841		6,692,744
COMMITMENTS AND CONTINGENCIES
LIMITED PARTNERS’ EQUITY, SUBJECT TO REPURCHASE RIGHT
Authorized—8,000,000 Units
Issued and outstanding—5,606,985 and 5,611,715 Units, respectively		47,390,528		48,721,208
GENERAL PARTNER’S EQUITY		567,116		582,548

Total partners’ equity		47,957,644		49,303,756

	$	59,196,548	$	63,319,060

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

F-5

EVERFLOW EASTERN PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

Years Ended December 31, 2013 and 2012


	2013			2012
REVENUES
Crude oil and natural gas sales	$	16,804,745		$	15,654,740
Well management and operating		620,583			573,183
Other		12,426			15,230

Total revenues		17,437,754			16,243,153
DIRECT COST OF REVENUES
Production costs		4,018,918			4,068,909
Well management and operating		371,109			318,426
Depreciation, depletion and amortization		3,546,003			5,471,203
Accretion expense		406,479			885,623
Write down/impairment and abandonment of crude oil and natural gas properties		34,385			980,021

Total direct cost of revenues		8,376,894			11,724,182
GENERAL AND ADMINISTRATIVE EXPENSE		2,745,658			2,953,042

Total cost of revenues		11,122,552			14,677,224

INCOME FROM OPERATIONS BEFORE GAIN ON SALES OF DEEP RIGHTS		6,315,202			1,565,929
GAIN ON SALES OF DEEP RIGHTS		2,761,705			39,148,059

INCOME FROM OPERATIONS		9,076,907			40,713,988
OTHER INCOME
Interest income		50,246			98,625
(Loss) gain on sale of property and equipment		(1,599	)		21,868

		48,647			120,493

INCOME BEFORE INCOME TAXES		9,125,554			40,834,481
INCOME TAX EXPENSE (BENEFIT)
Current		25,020			3,294,901
Deferred		489,000			(534,000	)

		514,020			2,760,901

NET INCOME	$	8,611,534		$	38,073,580

Allocation of Partnership Net Income
Limited Partners	$	8,509,742		$	37,623,908
General Partner		101,792			449,672

	$	8,611,534		$	38,073,580

Net income per unit	$	1.52		$	6.70

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

F-6

EVERFLOW EASTERN PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

Years Ended December 31, 2013 and 2012


	2013			2012
PARTNERS’ EQUITY – JANUARY 1	$	49,303,756		$	56,159,497
Net income		8,611,534			38,073,580
Quarterly cash distributions ($1.75 per unit in 2013 and 2012)		(9,934,375	)		(9,942,065	)
Special Distributions (see Note 9)		—			(34,948,235	)
Repurchase and retirement of Units		(46,543	)		(78,042	)
Options exercised		23,272			39,021

PARTNERS’ EQUITY – DECEMBER 31	$	47,957,644		$	49,303,756

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

F-7

EVERFLOW EASTERN PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

Years Ended December 31, 2013 and 2012


	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	8,611,534		$	38,073,580
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		3,635,345			5,556,571
Accretion expense		406,479			885,623
Write down/impairment and abandonment of crude oil and natural gas properties		34,385			980,021
Gain on sales of deep rights		(2,761,705	)		(39,148,059	)
Loss (gain) on sale of property and equipment		1,599			(21,868	)
Deferred income taxes		489,000			(534,000	)
Changes in assets and liabilities:
Accounts receivable		76,348			1,058,566
Other current assets		(13,150	)		—
Other assets		(5,680	)		(82,053	)
Accounts payable		(385,253	)		332,895
Accrued expenses		(176,726	)		409,654
Joint venture partner advances		154,510			725,760

Total adjustments		1,455,152			(29,836,890	)

Net cash provided by operating activities		10,066,686			8,236,690
CASH FLOWS FROM INVESTING ACTIVITIES
Payments received on notes receivables from employees		92,080			187,846
Advances disbursed to employees		(33,875	)		(11,487	)
Proceeds from deferred revenue		—			2,705,135
Purchase of property and equipment		(1,141,182	)		(400,427	)
Proceeds from sales of deep rights and property and equipment		38,500			38,351,231

Net cash (used) provided by investing activities		(1,044,477	)		40,832,298
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions		(9,934,375	)		(44,890,300	)
Repurchase and retirement of Units		(46,543	)		(78,042	)
Proceeds from options exercised		23,272			39,021

Net cash used by financing activities		(9,957,646	)		(44,929,321	)

NET CHANGE IN CASH AND EQUIVALENTS		(935,437	)		4,139,667
CASH AND EQUIVALENTS – JANUARY 1		25,397,117			21,257,450

CASH AND EQUIVALENTS – DECEMBER 31	$	24,461,680		$	25,397,117

Supplemental disclosures of cash flow information:
Cash paid during the year for:
Income taxes	$	247,932		$	3,292,536

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

F-8

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Organization and Summary of Significant Accounting Policies

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

Everflow Management Limited, LLC (“EML”), an Ohio limited liability company, is the general partner of Everflow and, as such, is authorized to perform all acts necessary or desirable to carry out the purposes and conduct of the business of Everflow. The members of EML are Everflow Management Corporation (“EMC”); two individuals who are officers and directors of EEI and employees of Everflow; one individual who is the Chairman of the Board of EEI; one individual who is an employee of Everflow; and one private limited liability company founded by an individual who is a director of EEI. EMC is an Ohio corporation formed in September 1990 and is the managing member of EML. EML holds no assets other than its general partner’s interest in Everflow, nor does it have any liabilities. In addition, EML has no separate operations or role apart from its role as the Company’s general partner.

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

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

F-9

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1.

Organization and Summary of Significant Accounting Policies (Continued)

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

Cash and Equivalents – The Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. The Company maintains, at various financial institutions, cash and equivalents which may exceed federally insured amounts and which may, at times, significantly exceed balance sheet amounts due to float. Cash and equivalents include $880,270 and $725,760 of joint venture partner advances at December 31, 2013 and 2012, respectively, which are funds collected and held on behalf of joint venture partners for their anticipated share of future plugging and abandonment costs, including interest earned.

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

Capitalized costs of proved properties, after considering estimated dismantlement and abandonment costs and estimated salvage values, are amortized by the unit-of-production method based upon estimated proved developed reserves. Depletion, depreciation and amortization on proved properties amounted to $3,493,540 and $5,416,318 during 2013 and 2012, respectively.

Generally accepted accounting principles require that long-lived assets (including oil and gas properties) and certain identifiable intangibles be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The Company, at least annually, reviews its proved crude oil and natural gas properties (on a field by field basis) for impairment by comparing the carrying value of its properties to the properties’ undiscounted estimated future net cash flows. Estimates of future crude oil and natural gas prices, operating costs, and production are utilized in determining

F-10

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1.

Organization and Summary of Significant Accounting Policies (Continued)

Property and Equipment (Continued)

undiscounted future net cash flows. The estimated future production of oil and gas reserves is based upon the Company’s independent reserve engineer’s estimate of proved reserves which includes assumptions regarding field decline rates and future prices and costs. For properties where the carrying value exceeds undiscounted future net cash flows, the Company recognizes as impairment the difference between the carrying value and fair market value of the properties. The Company determines fair market value as the properties’ discounted estimated future net cash flows. The Company wrote down crude oil and natural gas properties by $34,385 and $980,021 during 2013 and 2012, respectively, to provide for impairment and abandonment on certain of its crude oil and natural gas properties.

Additions to proved properties include changes to asset retirement obligations (see Note 1.G).

Pipeline and support equipment and other corporate property and equipment are recorded at cost and depreciated principally on the straight-line method over their estimated useful lives (pipeline and support equipment—10 to 15 years, other corporate equipment—3 to 7 years, other corporate property—building and improvements with a cost of $1,527,888 – 39 to 40 years). Depreciation on pipeline and support equipment amounted to $52,463 and $54,885 for the years ended December 31, 2013 and 2012, respectively. Depreciation on other corporate property and equipment, included in general and administrative expense, amounted to $89,342 and $85,368 for the years ended December 31, 2013 and 2012, respectively.

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

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

F-11

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1.

Organization and Summary of Significant Accounting Policies (Continued)

Asset Retirement Obligations (Continued)

will likely occur due to: changes in estimates of dismantlement, plugging and abandonment costs; changes in estimated remaining lives of the wells; changes in federal or state regulations regarding plugging and abandonment requirements; and other factors.

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

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


	2013			2012
Beginning of period	$	6,996,744		$	6,116,467
Liabilities incurred		6,295			45,235
Liabilities settled		(13,677	)		(50,581	)
Accretion expense		406,479			885,623

End of period	$	7,395,841		$	6,996,744

The current portion of asset retirement obligations of $300,000 and $304,000 at December 31, 2013 and 2012, respectively, is included in accrued expenses in the Company’s consolidated balance sheets.

Revenue Recognition – The Company recognizes oil and 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 collectibility 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, 2013 or 2012. Other revenue is recognized at the time services are rendered, the Company has a contractual right to such revenue and collection is reasonably assured.

F-12

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1.

Organization and Summary of Significant Accounting Policies (Continued)

Revenue Recognition (Continued)

incurred on behalf of joint venture partners and employees (see Note 6). Accounts payable to joint venture partners consist principally of advances received from joint venture partners for drilling and development costs not yet incurred. 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.

Income Taxes – Everflow is not a tax-paying entity and the net taxable income or loss, other than the taxable income or loss allocable to EEI, which is a C corporation owned by Everflow, will be allocated directly to its respective partners. The Company is not able to determine the net difference between the tax bases and the reported amounts of Everflow’s assets and liabilities due to separate elections that were made by owners of the working interests and limited partnership interests that comprised Programs.

As referred to in Note 4, EEI accounts for income taxes under generally accepted accounting principles, which require income taxes be provided for all items (as they relate to EEI) in the consolidated statements of income regardless of the period when such items are reported for income tax purposes. Therefore, deferred tax assets and liabilities are recognized for temporary differences between the financial reporting basis and tax basis of certain of EEI’s assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to be recovered or settled. The impact on deferred taxes of changes in tax rates and laws, if any, is reflected in the financial statements in the period of enactment.

The Company believes that it has appropriate support for any tax positions taken and, as such, does not have any uncertain tax positions that are material to the financial statements. The Company’s tax returns are subject to examination by the Internal Revenue Service, as well as various state and local taxing authorities, generally for three years after they are filed.

Allocation of Income and Per Unit Data – Under the terms of the limited partnership agreement, initially, 99% of revenues and costs were allocated to the unitholders (the limited partners) and 1% of revenues and costs were allocated to the general partner. The allocation changes as unitholders elect to exercise the repurchase right and select officers and employees elect to exercise options (see Note 3).

Earnings per limited partner Unit have been computed based on the weighted average number of Units outstanding during the year for each year presented. Average outstanding Units for earnings per Unit calculations amount to 5,609,350 and 5,614,069 in 2013 and 2012, respectively.

Subsequent Events—Everflow paid a dividend in January 2014 of $0.25 per Unit. The distribution amounted to approximately $1,419,000.

F-13

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Organization and Summary of Significant Accounting Policies (Continued)

New Accounting Standards – The Company has reviewed all other recently issued accounting standards in order to determine their effects, if any, on the consolidated financial statements. Based on that review, the Company believes that none of these standards will have a significant effect on current or future earnings or operations.

Reclassifications – Certain prior year amounts have been reclassified to conform with the current year’s presentation.

Note 2. Current Liabilities

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


	2013		2012
Accounts Payable:
Production and related other	$	1,274,763	$	1,434,657
Other		287,460		286,495
Joint venture partner deposits		122,387		44,407
Outside Working Interests (see Note 9)		—		360,874

	$	1,684,610	$	2,126,433

Accrued Expenses:
Payroll and retirement plan contributions	$	963,783	$	1,019,532
Current portion of asset retirement obligations		300,000		304,000
Other		72,200		99,000
Federal, state and local taxes		28,200		108,700

	$	1,364,183	$	1,531,232

The Company recognized $2,705,135 as deferred revenue in the consolidated balance sheet at December 31, 2012 in association with funds held for Contingent Leases as further described in Note 9.

F-14

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 3. Partners’ Equity

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

The partnership agreement provides that Everflow will repurchase for cash up to 10% of the then outstanding Units, to the extent unitholders offer Units to Everflow for repurchase pursuant to the repurchase right. The repurchase right entitles any unitholder, between May 1 and June 30 of each year, to notify Everflow that the unitholder elects to exercise the repurchase right and have Everflow acquire certain or all Units. The price to be paid for any such Units is calculated based upon the audited financial statements of the Company as of December 31 of the year prior to the year in which the repurchase right is to be effective and independently prepared reserve reports. The price per Unit equals 66% of the adjusted book value of the Company allocable to the Units, divided by the number of Units outstanding at the beginning of the year in which the applicable repurchase right is to be effective less all interim cash distributions received by a unitholder. The adjusted book value is calculated by adding partners’ equity, the standardized measure of discounted future net cash flows and the tax effect included in the standardized measure and subtracting from that sum the carrying value of oil and gas properties (net of undeveloped lease costs). If more than 10% of the then outstanding Units are tendered during any period during which the repurchase right is to be effective, the investors’ Units tendered shall be prorated for purposes of calculating the actual number of Units to be acquired during any such period. The price associated with the 2014 repurchase right, based upon the December 31, 2013 calculation, is estimated to be $6.51 per Unit, net of the distributions made in January 2014 ($0.25 per Unit) and expected to be made in April 2014 ($0.25 per Unit).

The Company has an Option Repurchase Plan (the “Plan”) which permits the grant of options to repurchase certain Units to select officers and employees (the “Participants”). The purpose of the Plan is to assist the Company to attract and retain 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 Plan is designed to align directly the financial interests of the Participants with the financial interests of the Unitholders. On June 28, 2013 and June 29, 2012, the Company granted a total of 4,730 and 4,707 options to two officers and one employee, all of which were exercised on the same date. Compensation expense associated with these grants was not material to the financial statements.

F-15

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 3. Partners’ Equity (Continued)

Units repurchased pursuant to the repurchase right and Units issued through the exercise of options pursuant to the Option Repurchase Plan (collectively the “Units Activity”) for the three years ended December 31, 2013, are as follows:


Year	Price for Repurchase Right		Less Interim Distributions		Net Price Paid		Units Repurchased		Units Issued		Units Outstanding Following Units Activity
2011	$	9.23	$	1.00	$	8.23		4,890		2,445		5,616,422
2012	$	9.17	$	0.88	$	8.29		9,414		4,707		5,611,715
2013	$	5.92	$	1.00	$	4.92		9,460		4,730		5,606,985

There were no instruments outstanding at December 31, 2013 or 2012 that would potentially dilute net income per Unit.

Note 4. Provision for Income Taxes

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


	Year Ended December 31,
	2013						2012
	Amount			%			Amount			%
Provision based on the statutory rate	$	3,103,000			34.0		$	13,884,000			34.0
Tax effect of:
Non-taxable status of the Programs and Everflow		(2,517,000	)		(27.6	)		(11,136,000	)		(27.3	)
Excess statutory depletion		(55,000	)		(0.6	)		(60,000	)		(0.1	)
Graduated tax rates, permanent differences between book and tax items, tax credits and other - net		(16,980	)		(0.2	)		72,901			0.2

Total	$	514,020			5.6		$	2,760,901			6.8

F-16

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 4. Provision for Income Taxes (Continued)

As referred to in Note 1, EEI accounts for current and 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 and deferred revenue. At December 31, 2013 and 2012, these deferred tax items resulted in deferred tax assets of $0 and $509,000, respectively, and deferred tax liabilities of $214,000 and $234,000, respectively. The Company did not believe a valuation allowance for deferred tax assets to be necessary at December 31, 2012.

Note 5. Retirement Plans

The Company has a defined contribution plan pursuant to Section 401(k) of the Internal Revenue Code for all employees 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’s total contributions to the Defined Contribution Plan amounted to approximately $224,000 and $260,000 for the years ended December 31, 2013 and 2012, respectively.

The Company has a qualified non-contributory cash balance defined benefit retirement plan covering certain eligible employees (the “Pension Plan”, or the “Plan”). Participants accumulate annual service credits as determined by their participation level according to the plan document and become 100% vested after three years of service, including credits given for prior service. Interest is accrued on these accumulated amounts at an annual rate of 5%. The Pension Plan’s net periodic benefit cost was $304,500 and $290,500 in 2013 and 2012, respectively, resulting in a projected and accumulated benefit obligation of $620,000 and $290,500 at December 31, 2013 and 2012, respectively. The vested benefit obligation is determined as the actuarial present value of the vested benefits to which the employee is currently entitled but based on the employee’s expected date of separation or retirement. After Company contributions of $289,000 and $1,000 in 2013 and 2012, respectively, the Pension Plan has a remaining accrued pension liability of $318,500 and $289,500 at December 31, 2013 and 2012, respectively. The entire underfunded amounts, which are recognized as accrued expenses in the consolidated balance sheets at December 31, 2013 and 2012, were funded in March 2014 and January 2013, respectively. Plan assets of $301,500 were primarily invested in a publicly traded mutual fund with a domestic blend of stocks and bonds at December 31, 2013. Plan assets of $1,000 were invested in cash equivalents at December 31, 2012. Benefits of $2,000 and $0 were paid to participants during 2013 and 2012. Benefits of approximately $35,000 are estimated to be paid over the next five years, and benefits of approximately $1,505,000 are estimated to be paid in the aggregate over the next five years thereafter. Assumptions used in accounting for the net periodic benefit cost include a discount rate of 5% and long-term asset return of 7%.

F-17

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 6. Related Party Transactions

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 3.25% at December 31, 2013.

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, 2013 and 2012, the Company has extended various loans, evidenced by notes, to two employees with origination dates ranging from December 2009 to December 2013. One subsequent addendum extending an additional two-year payment term to a certain note is outstanding at December 31, 2013. Employee notes receivables, including accrued interest, amounted to $213,262 and $271,467 at December 31, 2013 and 2012, respectively.

Note 7. Business Segments, Risks and Major Customers

The Company operates exclusively in the United States, almost entirely in Ohio and Pennsylvania, 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.

F-18

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 7.

Business Segments, Risks and Major Customers (Continued)

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 65% and 62% of total crude oil and natural gas sales in 2013 and 2012, respectively. Approximately 72% and 68% of total crude oil and natural gas sales were derived from operated wells in 2013 and 2012, respectively. The Company had two significant purchasers of natural gas production from operated wells for the years ended December 31, 2013 and 2012. Natural gas sales to these significant purchasers as a percentage of consolidated crude oil and natural gas sales were as follows:


Natural Gas Purchaser	2013			2012
Dominion Field Services, Inc. (“Dominion”)		31	%		29	%
Interstate Gas Supply, Inc. (“IGS”)		13			13

		44	%		42	%

As of December 31, 2013, natural gas purchased by Dominion covers production from approximately 480 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 67% and 68% of the Company’s consolidated natural gas sales in 2013 and 2012, respectively.

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

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, 2013 and 2012. 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 2014. 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.

F-19

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 7. Business Segments, Risks and Major Customers (Continued)

The Company has multiple annual contracts with Dominion and IGS (the “Major Gas Purchasers”), which obligate the Major 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 2.24 BCF through October 2015 at various monthly weighted-average pricing provisions averaging approximately $3.71 per MCF.

Note 8. Commitments and Contingencies

As referred to in Note 7, the Company has natural gas delivery commitments to Dominion and IGS, two of its major customers. Management believes the Company can meet its delivery commitments based on estimated production. If, however, the Company cannot meet its delivery commitments, it will purchase natural gas at market prices to meet such commitments which will 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 gas for redelivery (resale) to its customers.

The Company held funds at December 31, 2012 in conjunction with Contingent Leases as further described in Note 9.

Note 9. Sales of Deep Rights

In recent years, the Company had agreed to sell its deep rights in certain Ohio and Pennsylvania properties for cash consideration as part of various agreements with multiple purchasers that closed at various times throughout 2012 (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, resulting in a Gain on Sales of Deep Rights of $39,148,059.

Included in the acreage sold as part of one of the Dispositions, the Company sold approximately 2,200 acres with leases that contained terms and conditions which would have required the Company to repurchase the acreage if certain claims were made by February 2013 (the “Contingent Leases”). Deferred revenue of $2,705,135 was recognized in the Company’s consolidated balance sheet at December 31, 2012 in association with the funds held for Contingent Leases. The Company did not recognize gain on sale of the Contingent Leases until the claim period ending February 2013 had expired, with no claims having been made. Deferred income tax expense of $509,000 was also recognized during 2013 in conjunction with revenues recognized from expired contingencies.

Of the total gains on sales of deep rights recognized during 2013 and 2012, $2,705,135 and $1,000,000, respectively, represent funds previously recognized as deferred revenue.

F-20

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9.

Sales of Deep Rights (Continued)

A condition of one of the Dispositions is that the Company perpetuate the producing leases, for a minimum period of five years, from which approximately 28,800 acres of the total acreage was sold. 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, 2013.

The Company also served as an agent for the sale of deep rights acreage owned by other affiliated and non-affiliated parties (the “Working Interest Parties”). Generally, the Working Interest Parties sold their acreage to the purchasers under the same terms and conditions as the Company’s Dispositions. The Company recognized accounts payable to outside working interests of $360,874 at December 31, 2012 in association with the funds held for the Working Interest Parties (see Note 2).

F-21

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 10. Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited)

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

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

CAPITALIZED COSTS RELATING TO OIL AND GAS

PRODUCING ACTIVITIES


	Years ended December 31,
	2013		2012
Proved oil and gas properties	$	174,811,480	$	174,044,579
Pipeline and support equipment		666,667		666,667

		175,478,147		174,711,246
Accumulated depreciation, depletion, amortization and write down		144,715,506		141,380,981

Net capitalized costs	$	30,762,641	$	33,330,265

COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES


	Years ended December 31,
	2013		2012
Property acquisition costs	$	42,846	$	137,105
Development costs		956,611		97,864

The Company had no purchases of producing oil and gas properties in 2013 or 2012.

F-22

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 10.

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

RESULTS OF OPERATIONS FOR OIL AND

GAS PRODUCING ACTIVITIES


	Years ended December 31,
	2013			2012
Crude oil and natural gas sales	$	16,804,745		$	15,654,740
Production costs		(4,018,918	)		(4,068,909	)
Depreciation, depletion and amortization		(3,546,003	)		(5,471,203	)
Accretion expense		(406,479	)		(885,623	)
Write down/impairment and abandonment of crude oil and natural gas properties		(34,385	)		(980,021	)

		8,798,960			4,248,984
Income tax expense		25,000			60,000

Results of operations for oil and gas producing activities (excluding corporate overhead and financing costs)	$	8,773,960		$	4,188,984

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.

F-23

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 10.

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

ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES


	Oil (BBLS)			Gas (MCFS)
Balance, January 1, 2012		645,000			33,159,000
Production		(65,000	)		(2,666,000	)
Revision of previous estimates		(1,000	)		(4,849,000	)

Balance, December 31, 2012		579,000			25,644,000
Extensions, discoveries and other additions		25,000			177,000
Production		(62,000	)		(2,846,000	)
Revision of previous estimates		44,000			4,678,000

Balance, December 31, 2013		586,000			27,653,000

PROVED DEVELOPED RESERVES:
December 31, 2011		645,000			33,159,000
December 31, 2012		579,000			25,644,000
December 31, 2013		586,000			27,653,000

The Company has not determined proved reserves associated with its proved and other undeveloped properties, including its deep property interests. At December 31, 2013 and 2012, the Company had 498 and 724 net proved undeveloped acres, respectively. The net carrying cost of the proved undeveloped acreage that is included in proved properties amounted to approximately $341,600 and $440,200 at December 31, 2013 and 2012, respectively.

F-24

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 10.

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

STANDARDIZED MEASURE OF DISCOUNTED FUTURE

NET CASH FLOWS


	December 31,
	2013			2012
	(Thousands of Dollars)
Future cash inflows from sales of oil and gas	$	150,370		$	123,438
Future production and development costs		(67,947	)		(55,855	)
Future asset retirement obligations, net of salvage		(11,668	)		(11,661	)
Future income tax expense		(1,570	)		(1,353	)

Future net cash flows		69,185			54,569
Effect of discounting future net cash flows at 10% per annum		(27,524	)		(21,026	)

Standardized measure of discounted future net cash flows	$	41,661		$	33,543

CHANGES IN THE STANDARDIZED MEASURE OF

DISCOUNTED FUTURE NET CASH FLOWS


	Years Ended December 31,
	2013			2012
	(Thousands of Dollars)
Balance, beginning of year	$	33,543		$	60,562
Extensions, discoveries and other additions		1,401			—
Development costs incurred		—			165
Revision of quantity estimates		5,335			(1,569	)
Sales of crude oil and natural gas, net of production costs		(12,786	)		(11,586	)
Net change in income taxes		(118	)		489
Net changes in prices and production costs		5,670			(16,234	)
Accretion of discount		3,354			6,056
Other		5,262			(4,340	)

Balance, end of year	$	41,661		$	33,543

F-25

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 10.

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 $3.43 and $2.73 at December 31, 2013 and 2012, respectively, and the average adjusted crude oil prices used in the estimation of proved reserves were $94.49 and $92.25 at December 31, 2013 and 2012, respectively.

F-26

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

As of the end of the period covered by this report, management performed, with the participation of our Chief Executive Officer and Chief Financial Officer, an evaluation of the effectiveness of our disclosure controls and procedures as defined in Exchange Act Rules 13a-15. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures. Based on the evaluation, management concluded that our disclosure controls and procedures were effective for the year ended December 31, 2013.

Management’s Report on Internal Control Over Financial Reporting

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

Management was responsible for assessing the effectiveness of our internal controls over financial reporting (the “assessment”) beginning with the year ending December 31, 2006 (the “initial assessment”) and annually thereafter as required under Section 404 of the Sarbanes-Oxley Act of 2002 (“Section 404”). Management’s assessment efforts undertaken since and including the initial assessment have been conducted using the framework established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).

Management utilized internal and external resources to assist in the various aspects of its assessment and compliance efforts. As a result of its assessment and compliance efforts, management has concluded that our internal controls over financial reporting were effective as of December 31, 2013, based on the Internal Control — Integrated Framework issued by COSO.

-29-

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

Changes in Internal Control Over Financial Reporting

Management, including its Chief Executive Officer and Chief Financial Officer, has concluded that during 2013 there were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect the Company’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

-30-

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The Company, as a limited partnership, does not have any directors or executive officers. The General Partner of the Company is Everflow Management Limited, LLC, an Ohio limited liability company formed in March 1999, as the successor to the Company’s original general partner. The members of the General Partner as of March 10, 2014 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, 2014, 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, 2014 are as follows:


Name	Age		Positions and Offices with EEI	Positions and Offices with EMC
Thomas L. Korner		60	Chairman of the Board and director	Chairman of the Board and director
Robert F. Sykes		90	Director	Director
Peter H. Sykes		57	None	Director
William A. Siskovic		58	President, Principal Executive Officer and director	President, Principal Executive Officer and director
Brian A. Staebler		39	Vice President, Secretary-Treasurer, Principal Financial and Accounting Officer and director	Vice President, Secretary-Treasurer, Principal Financial and Accounting Officer and director

-31-

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, from 1984 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.

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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.

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Audit Committee

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

REPORT OF THE AUDIT COMMITTEE

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

We have discussed with the independent 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, 2013, for filing with the Securities and Exchange Commission.

Respectfully submitted by the members of the Audit Committee:

Thomas L. Korner (Chairman)

Robert F. Sykes

Peter H. Sykes

William A. Siskovic

Brian A. Staebler

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Code of Ethics

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

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

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

Based solely on the Company’s review of the copies of such forms furnished to the Company, the Company believes that all required Section 16(a) filings for fiscal year 2013 were timely made.

ITEM 11. EXECUTIVE COMPENSATION

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

Overview of 2013 Executive Compensation Components

Components of executive compensation in the 2013 fiscal year for the executive officers of EMC and EEI include the following:

•

base salary

•

annual cash bonuses

•

retirement and other benefits

Base Salary

The base salary of the executive officers is intended to provide fixed compensation for the performance of core duties. In determining appropriate salary levels, consideration is given to the level and scope of responsibility, experience, and Company and individual performance. The base salaries paid during fiscal 2013 are shown in the Summary Compensation Table below.

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Annual Cash Bonuses

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

Executive officers are provided an annual cash bonus each year based on the achievement of certain financial and non-financial performance objectives during the previous fiscal year. Annual cash bonuses are based on a percentage of the executive’s base salary. For 2013, the Board of Directors set a range of these bonuses between 80% and 150% of the executive’s base salary, based on the Company achieving specified financial and non-financial performance objectives. In 2013, the financial performance objectives that were used for determining financial performance-based cash awards were asset management, profitability and overall company stability. In 2013, 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. In addition, cash bonuses in 2012 included an amount for the successful completion of the Dispositions described in the section entitled “Sales of Deep Rights” appearing on page 2 herein.

The 2014 target annual cash bonus awards for executive officers are established as a percentage of the executive’s base salary. These target amounts range between 80% 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.

Retirement and Other Benefits

The executive officers are entitled to the same benefits coverage as other employees such as health insurance, life and disability insurance, participation in the Company’s 401(k) plan and 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. During June 2013 and 2012, the Company granted a total of 3,784 and 3,766 options, respectively, to executive officers. All options granted 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.

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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, 2013 and 2012, of those persons who were at December 31, 2013: (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.”

SUMMARY COMPENSATION TABLE


	Annual Compensation
Name and Principal Position	Year		Salary		Bonus			Options Awards⁽¹⁾		All Other Compen- sation⁽²⁾			Total
William A. Siskovic		2013	$	120,300	$	160,000		$	—	$	244,171	⁽⁴⁾	$	524,471
President and Principal		2012	$	120,300	$	340,000	⁽³⁾	$	—	$	235,868	⁽⁴⁾	$	696,168
Executive Officer
Brian A. Staebler		2013	$	108,200	$	97,000		$	—	$	115,263	⁽⁶⁾	$	320,463
Vice President and Principal Financial and Accounting Officer		2012	$	108,100	$	198,000	⁽⁵⁾	$	—	$	115,166	⁽⁶⁾	$	421,266

No Named Executive Officer received personal benefits or perquisites during 2013 or 2012 in excess of $10,000.

(1)

In June 2013 and 2012, the Company issued William A. Siskovic and Brian A. Staebler each 1,892 and 1,883 options, respectively, to repurchase certain Units at exercise prices of $4.92 per Unit and $8.29 per Unit, respectively. All options granted were exercised on the same date. The value of the options were deemed immaterial and no compensation cost was recognized under FASB ASC Topic 718 for fiscal years 2013 and 2012.

(2)

Includes amounts contributed under the Company’s Defined Contribution Plan in the form of employer-matched contributions and profit sharing contributions, amounts contributed to the Company’s Pension Plan on behalf of the executive officers, and amounts considered taxable wages with respect to personal use of a Company vehicle, the Company’s Group Term Life Insurance Plan, and additional supplemental life insurance. Additional terms of the Defined Contribution Plan and Pension Plan are described in the section entitled “Retirement Plans” appearing on page 38 herein.

(3)	Includes a special cash bonus of $185,000 awarded for the successful completion of the Dispositions as further described in the section entitled “Sales of Deep Rights” appearing on page 2 herein.

(4)

During fiscal years ended December 31, 2013 and 2012, includes $26,550 and $20,000, respectively, contributed as profit sharing to the Defined Contribution Plan, $7,650 and $15,000, respectively, contributed as matching contributions to the Defined Contribution Plan, $202,100 and $192,053, respectively, awarded as benefits to the Pension Plan, $1,306 and $2,250, respectively, considered taxable wages with respect to personal use of a Company vehicle, and $6,565 considered taxable wages with respect to the Company’s Group Term Life Insurance Plan and additional supplemental life insurance.

(5)	Includes a special cash bonus of $105,000 awarded for the successful completion of the Dispositions as further described in the section entitled “Sales of Deep Rights” appearing on page 2 herein.

(6)

During fiscal years ended December 31, 2013 and 2012, includes $24,807 and $19,640, respectively, contributed as profit sharing to the Defined Contribution Plan, $6,156 and $15,000, respectively, contributed as matching contributions to the Defined Contribution Plan, $80,200 and $76,821, respectively, awarded as benefits to the Pension Plan, $2,990 and $2,505, respectively, considered taxable wages with respect to personal use of a Company vehicle, and $1,110 and $1,200, respectively, considered taxable wages with respect to the Company’s Group Term Life Insurance Plan and additional supplemental life insurance.

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

Outstanding Equity Awards

During June 2013 and 2012, the Company granted a total of 3,784 and 3,766 options, respectively, to executive officers. All options granted were exercised on the same date. There were no outstanding unexercised options as of December 31, 2013 or 2012.

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 has a qualified cash balance defined benefit retirement plan covering certain eligible employees, including officers (the “Pension Plan”). Participants accumulate annual service credits as determined by their participation level according to the plan document and become 100% vested after three years of service, including credits given for prior service. Interest is accrued on these accumulated amounts at an annual rate of 5%.

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 2013 or 2012 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, 2014 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 1.18% 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, 2014 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


Name of Holder	Units in Company		Percentage of Units in Company ⁽¹⁾		Percentage Interest in Everflow Management Limited, LLC ⁽²⁾		Percentage Interest in EMC
Directors and Executive Officers
Robert F. Sykes⁽³⁾(director of EMC)		158,634		2.83		*		*
William A. Siskovic (officer and director of EMC)		77,678		1.39		16.6667		16.6667
Thomas L. Korner (Chairman of the Board & director of EMC)		63,696		1.14		16.6667		16.6667
Peter H. Sykes⁽⁴⁾(director of EMC)		41,244		0.73		*		*
Brian A. Staebler (officer and director of EMC)		6,266		0.11		8.3333		8.3333

		347,518		6.20		41.6667		41.6667
Other Beneficial Owners of >5% of the Company
David F. Sykes⁽⁵⁾		774,099		13.80		50.0000		50.0000

		1,121,617		20.00		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 1.18% 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 by the Robert F. Sykes 2009 Grantor Retained Annuity Trust and 78,995 Units held in the Catherine H. Sykes 2009 Grantor Retained Annuity Trust.

(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 13.07% of the Company’s outstanding Units, held by Sykes Associates, LLC, a New York limited liability company located at 60 Brookside Drive, Rochester, NY, 14618 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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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 2013 and 2012 in the amount of $23,580 and $2,689, respectively. Brian A. Staebler made investments in crude oil and natural gas properties during 2013 and 2012 in the amount of $11,790 and $1,345, respectively. Thomas L. Korner made investments in crude oil and natural gas properties during 2013 and 2012 in the amount of $23,580 and $2,689, respectively.

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

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Maloney + Novotny LLC served as the Company’s independent auditor for the years ended December 31, 2013 and 2012. 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, 2013 and 2012, respectively.


	December 31,
	2013		2012
Audit fees	$	206,748	$	207,986
Audit related fees		—		—
Tax fees		6,658		9,018
All other fees		—		—

Total	$	213,406	$	217,004

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 2013 by the audit committee.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) (1) Financial Statements

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


		Page(s)
Report of Independent Registered Public Accounting Firm		F-3
Consolidated Balance Sheets		F-4 – F-5
Consolidated Statements of Income		F-6
Consolidated Statements of Partners’ Equity		F-7
Consolidated Statements of Cash Flows		F-8
Notes to Consolidated Financial Statements		F-9 – F-26

(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).

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.

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SIGNATURES

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


EVERFLOW EASTERN PARTNERS, L.P.

By:	EVERFLOW MANAGEMENT LIMITED, LLC
	General Partner

By:	EVERFLOW MANAGEMENT CORPORATION
	Managing Member

By:	/s/ Robert F. Sykes	Director	March 26, 2014
	Robert F. Sykes

By:	/s/ Peter H. Sykes	Director	March 26, 2014
	Peter H. Sykes

By:	/s/ Thomas L. Korner	Director	March 26, 2014
	Thomas L. Korner

By:	/s/ William A. Siskovic	President, Principal	March 26, 2014
	William A. Siskovic	Executive Officer and Director

By:	/s/ Brian A. Staebler	Vice President, Secretary-	March 26, 2014
	Brian A. Staebler	Treasurer, Principal Financial and Accounting Officer and Director

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 Management Limited LLC	(3	)

3.7	Amended and Restated Operating Agreement of Everflow Management Limited, LLC dated December 31, 2009	(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 of Canfield, Ltd.	(5	)

14.1	Code of Ethics

21.1	Subsidiaries of the Registrant	(6	)

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

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

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

99.1	Report of Wright & Company, Inc. dated February 12, 2014 concerning evaluation of oil and gas reserves.

101.INS	Instance Document

101.SCH	XBRL Taxonomy Extension Schema Document

101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB	XBRL Taxonomy Extension Label Linkbase Document

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

E-1

Exhibit Index

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

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

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

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

E-2

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company