EVERFLOW EASTERN PARTNERS LP - FORM 10-K

EVERFLOW EASTERN PARTNERS LP - FORM 10-K - March 25, 2016

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EX-31.2 - EX-31.2 - EVERFLOW EASTERN PARTNERS LP	d112296dex312.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, 2015

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

Commission File No. 0-19279

EVERFLOW EASTERN PARTNERS, L.P.

(Exact name of registrant as specified in its charter)


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


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

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

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

Title of each class

Name of each exchange

on which registered

None

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 4,440,157 Units of limited partnership interest held by non-affiliates of the Registrant as of June 30, 2015. At June 30, 2015, there was no public market for the Registrant’s Units of limited partnership interest. There were 5,587,616 Units of limited partnership interest of the Registrant as of March 10, 2016. 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, 2015.

EVERFLOW EASTERN PARTNERS, L.P.

INDEX


	DESCRIPTION		PAGE NO.

Part I.

	Item 1.	Business		1

	Item 1A.	Risk Factors		10

	Item 1B.	Unresolved Staff Comments		10

	Item 2.	Properties		11

	Item 3.	Legal Proceedings		14

	Item 4.	Mine Safety Disclosures		14

	Supplemental Item - Executive Officers of the Registrant			15

Part II.

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

	Item 6.	Selected Financial Data		17

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

	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		28

	Item 8.	Financial Statements and Supplementary Data		28

		Report of Independent Registered Public Accounting Firm		F-3

		Consolidated Balance Sheets		F-4

		Consolidated Statements of Operations		F-6


	DESCRIPTION		PAGE NO.

		Consolidated Statements of Partners’ Equity		F-7

		Consolidated Statements of Cash Flows		F-8

		Notes to Consolidated Financial Statements		F-9

	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		29

	Item 9A.	Controls and Procedures		29

	Item 9B.	Other Information		30

Part III.

	Item 10.	Directors, Executive Officers and Corporate Governance		31

	Item 11.	Executive Compensation		35

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

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

	Item 14.	Principal Accounting Fees and Services		41

Part IV.

	Item 15.	Exhibits and Financial Statement Schedules		42

Exhibit Index				E-1

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 54% of the estimated total future cash inflows related to the Company’s crude oil and natural gas reserves as of December 31, 2015 are attributable to crude oil reserves. The majority of such properties are located in Ohio and consist primarily of proved producing properties with established production histories.

The Company’s operations since February 1991 primarily involve the production and sale of oil and gas and the drilling and development of approximately 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 has sold its deep rights in certain Ohio and Pennsylvania properties for cash consideration as part of various agreements with multiple purchasers (the “Dispositions”). The Dispositions included no producing reserves, and the Company retained the rights to the shallow portion of all acreage sold in addition to some of the rights to a portion of the deep acreage sold, subject to the agreements. During 2012, the Company sold approximately 30,600 acres in conjunction with the Dispositions.

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

Acquisition of Prospects. The Company maintains a leasehold inventory from which the General Partner will select oil and gas prospects for development by the Company. The Company makes additions to such leasehold inventory on an on-going basis. The Company may also acquire leases from third parties. Prior to 2000, EEI generated approximately 90% of the prospects which were drilled. Beginning in 2000, the Company began generating fewer prospects

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and has participated in more joint ventures with other operators. As of December 31, 2015, the Company’s current leasehold inventory consists of approximately 33 prospects in various stages of maturity representing approximately 91 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 2015 or 2014.

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.”

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 2015 or 2014 and no principal indebtedness was outstanding as of March 10, 2016. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Liquidity and Capital Resources.”

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

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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, 2015, net of asset retirement obligations, which aggregate a net liability of $8,211,000 (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 2015, 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 2015.

The price of crude oil in the Appalachian Basin has ranged from a low of $8.50 per barrel in December 1998 to a high of $138.00 in July 2008. As of March 10, 2016, $33.84 per barrel was the posted field price in the Appalachian Basin area, the Company’s principal area of operation. There can be no assurance that prices will not be subject to continual fluctuations. Future crude oil prices are difficult to predict because of the impact of worldwide economic trends, supply and demand variables, and such non-economic factors as the political impact on pricing policies by the Organization of Petroleum Exporting Countries (“OPEC”), governmental instability in foreign oil producing countries, energy and environmental policy of federal, state and local governments, and the possibility of supply interruptions. To the extent the prices that the Company receives for its crude oil production decline, the Company’s revenues from crude oil production will be reduced accordingly.

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

Natural Gas. The deliverability and price of natural gas is subject to various factors affecting the supply and demand of natural gas as well as the effect of federal regulations. Prior to 2000, there had been a surplus of natural gas available for delivery to pipelines and other purchasers. During 2000, decreases in worldwide energy production capability and increases in

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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 2015, excess natural gas supplies resulted from the combination of increased production from integrated and independent producers and decreased industrial and commercial energy consumption resulting from the global and United States financial crises and recession. From time to time, especially in summer months, seasonal restrictions on natural gas production have occurred as a result of distribution system restrictions.

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

Since 2002, the Company has had and continues to have multiple annual 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. As of March 10, 2016, the Company has not elected to lock-in any monthly quantities of natural gas with Dominion.

The Company also has had and continues to have multiple annual contracts with Interstate Gas Supply, Inc. (“IGS”), which obligates IGS to purchase, and the Company to sell and deliver, certain quantities of natural gas production from the Company’s oil and gas properties throughout the contract periods. The Company may elect to lock-in specific volumes of natural gas to be sold in specific months at a mutually agreeable price. As of March 10, 2016, the Company has not elected to lock-in any monthly quantities of natural gas with IGS.

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, 2015, natural gas purchased by Dominion covers production from approximately 460 gross operated wells, while natural gas purchased by IGS covers production from approximately 200 gross operated wells. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Commodity Pricing, Risk Management Activities and Inflation.”

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

During 2015, no one natural gas purchaser accounted for more than 10% of the Company’s natural gas sales other than Dominion and IGS, whose purchases of natural gas from operated wells accounted for approximately 42% and 21%, 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 2016.

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

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

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

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

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times, including 2015, resulted in a curtailment in exploration for and development of oil and gas properties.

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

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

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

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

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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.

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.

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

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

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

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

Conflicts of Interest. The Partnership Agreement grants the General Partner broad discretionary authority to make decisions on matters such as the Company’s acquisition of or participation in a drilling prospect or a producing property. To limit the General Partner’s management discretion might prevent it from managing the Company properly. However, because

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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, 2016, the Company had 16 full-time and 3 part-time employees. These employees primarily are engaged in the following areas of business operations: six in accounting, seven in administration, four in field operations and two in land and lease acquisition.

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 were $1.37 and $3.28 at December 31, 2015 and 2014 respectively, and the crude oil prices used in the estimation of proved reserves were $46.40 and $90.53 at December 31, 2015 and 2014, 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, 2015, the Company retained Wright & Company, Inc. (“Wright & Company”), a third-party, independent petroleum engineering firm, to prepare a report of proved reserves. The reserves report included a detailed review of all of the Company’s crude oil and natural gas properties. Wright & Company’s evaluation was based on more than 35 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations applicable as of December 31, 2015. The Wright & Company report, including the

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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 2015 or 2014.

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, 2015.


	Oil (BBLS)		Gas (MCF)
Proved Developed		277,000		7,991,000
Proved Undeveloped		—		—

Total		277,000		7,991,000

(1)	The Company has not determined proved reserves associated with its proved and other undeveloped properties, including its deep property interests, at December 31, 2015. 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 2015 and 2014.


					Average
	Production				Sales Price				Average Lifting Cost
	Oil (BBLS)		Gas (MCFS)		per BBL		per MCF		per Equivalent MCF⁽¹⁾
2015		44,000		1,616,000	$	46.61	$	2.29	$	1.46
2014		53,000		2,269,000	$	90.91	$	3.73	$	1.41

⁽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, 2015.


Gross Wells			Net Wells
(1)	(1)		(1)	(1)
Oil	Gas	Total	Oil	Gas	Total
340	1,106	1,446	196	686	882

(1)	Oil wells are those wells which generated the majority of their revenues from crude oil production during 2015; gas wells are those wells which generated the majority of their revenues from natural gas production during 2015.

Standardized Measure of Discounted Future Net Cash Flows.⁽¹⁾ The following table summarizes, as of December 31, 2015, 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, 2015, discounted to present value at 10%.


	(Thousands)
Future cash inflows from sales of oil and gas	$	23,821
Future production and development costs		(15,446	)
Future asset retirement obligations, net of salvage		(16,443	)
Future income tax expense		(144	)

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

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

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

Acreage. The Company had approximately 58,500 gross developed acres and 37,900 net developed acres as of December 31, 2015. Developed acreage is that acreage assignable to productive wells. The Company had approximately 91 gross and net proved undeveloped acres as of December 31, 2015.

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Drilling Activity. The following table sets forth the results of drilling activities during 2015 and 2014 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
2015		1.00		0.11		—		—
2014		1.00		0.18		—		—

⁽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 participated in the drilling of any wells since December 31, 2015.

Delivery Commitments. The Company has entered into various contracts with Dominion and IGS which, subject to certain restrictions and adjustments, obligate Dominion and IGS to purchase and the Company to sell all natural gas production from certain operated contract wells. The operated contract wells comprised approximately 63% of the Company’s consolidated natural gas sales during 2015. In addition, the Company has entered into other various short-term contracts which obligate the purchasers to purchase and the Company to sell and deliver undetermined quantities of natural gas production on a monthly basis throughout the term of the contracts.

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

ITEM 3.

LEGAL PROCEEDINGS

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

ITEM 4.

MINE SAFETY DISCLOSURES

Not applicable.

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SUPPLEMENTAL ITEM — EXECUTIVE OFFICERS OF THE REGISTRANT

The executive officers of EEI and EMC as of March 10, 2016 are as follows:

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 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, 2016, there were 5,587,616 Units held by 1,367 holders of record.

Distribution History

The Company commenced operations with the consummation of the Exchange Offer in February 1991. Management’s stated intention was to make quarterly cash distributions equal to $0.125 per Unit (or $0.50 per Unit on an annualized basis) for the first eight quarters following the closing date of the Exchange Offer. The Company paid a quarterly distribution every quarter from July 1991 through October 2015. The Company paid total quarterly cash distributions of $0.70 and $1.25 per Unit during 2015 and 2014, respectively. The Company did not pay a quarterly distribution in January 2016, nor does it anticipate paying a quarterly distribution in April 2016. At this time, the Company does not intend to resume paying quarterly distributions during 2016, though no assurances can be provided that the Company’s intentions won’t change based upon unforeseen changes in the national and/or regional oil and gas markets and their related effect on cash flows.

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 26,774 and 11,964 of its Units of limited partnership interest at a price of $4.56 and $6.51 per Unit pursuant to the terms of the Company’s Offers to Purchase dated April 30, 2015 and 2014, respectively. The Company has determined that the price associated with the 2016 Repurchase Right, based upon the December 31, 2015 calculation, is negative, and as such the Company will not be offering to repurchase Units in 2016. 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.

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Liquidity and Capital Resources

Financial Position

The following table summarizes the Company’s financial position at December 31, 2015 and December 31, 2014:


	December 31, 2015				December 31, 2014
	Amount %				Amount %
	(Amounts in Thousands)				(Amounts in Thousands)
Working capital	$	20,421	57	%	$	23,661	43	%
Property and equipment (net)		14,946	42			31,753	57
Other		266	1			258	—

Total	$	35,633	100	%	$	55,672	100	%

Deferred income taxes	$	74	—	%	$	194	—	%
Long-term liabilities		17,399	49			11,764	21
Partners’ equity		18,160	51			43,714	79

Total	$	35,633	100	%	$	55,672	100	%

Working capital surplus of $20.4 million as of December 31, 2015 represented a $3.2 million decrease from December 31, 2014 due primarily to decreases in cash and equivalents and accounts receivable from production, offset somewhat by a decrease in accrued expenses. The decrease in accounts receivable from production is the combined result of decreases in crude oil and natural gas volumes produced and lower crude oil and natural gas prices received during the current receivable production period as compared to the prior comparable receivable production period. The primary reason for the decrease in crude oil and natural gas volumes produced during the current receivable production period as compared to the prior comparable receivable production period is the result of additional operated oil and gas properties being voluntarily shut-in. The decrease in accrued expenses is primarily the result of less payroll and retirement plan contributions accrued during the fourth quarter of 2015 as compared to the prior comparable accrual period. In response to the current environment of depressed crude oil and natural gas prices within the national and regional oil and gas industries and its related effects on the Company’s sales, operational cash flows and working capital, the Company has taken various cost-cutting measures that include reducing payroll and retirement plan contributions, including the termination of an employee benefit plan during the fourth quarter of 2015 altogether.

Property and equipment of $14.9 million as of December 31, 2015 represented a $16.8 million decrease from December 31, 2014 due primarily to $12.4 million of depreciation, depletion and amortization (“DD&A”) and $9.6 million of write down/impairment and abandonment of crude oil and natural gas properties (“Impairment and Abandonment”) recognized in 2015, offset somewhat by $5.2 million of additions to property and equipment, $5.1 million of which resulted from revisions in estimated cash flows related to asset retirement obligations as measured at December 31, 2015. As further discussed below, DD&A and Impairment and Abandonment increased substantially in 2015 as compared to the prior comparable period. The

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primary reason for these increases as well as for the revisions in estimated cash flows related to asset retirement obligations is the substantial decrease in natural gas and crude oil reserves as of the most recent valuation date, December 31, 2015, as compared to the prior valuation date, December 31, 2014. The decrease in natural gas and crude oil reserves was primarily the result of significantly lower natural gas and crude oil prices used to value reserves at December 31, 2015 as compared to the prior comparable valuation date. The lower natural gas and crude oil prices contributed to decreasing the average economic life of the Company’s oil and gas properties as compared to their prior valuation date.

Deferred income taxes of $74,000 as of December 31, 2015 represented a decrease of $120,000 from December 31, 2014 due entirely to income tax benefits recognized during 2015. Income tax benefits recognized during 2015 were the result of a decrease in temporary differences arising from differences in financial reporting and tax reporting methods for EEI’s proved properties.

Long-term liabilities of $17.4 million as of December 31, 2015 represented an increase of $5.6 million from December 31, 2014 due almost entirely to an increase in asset retirement obligations. The increase in asset retirement obligations is primarily attributed to $584,000 of accretion expense recognized in 2015 to adjust the liabilities to their present value and $5.1 million of revisions in estimated cash flows as measured at December 31, 2015, the effects of which were offset somewhat by $80,000 of asset retirement obligations that were settled during 2015.

The Company has not held a credit facility with a bank since 2003, nor has it had any borrowings since that time. The Company will not be offering to repurchase Units in 2016. As further discussed below, the Company expects existing cash and equivalents and cash flows from ongoing operations to meet short-term cash requirements.

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Cash Flows from Operating, Investing and Financing Activities

The Company generated the majority of its cash sources from operating activities during 2015 and 2014. During 2015, existing cash and equivalents and cash provided by operations was used primarily to fund distributions to Unitholders. During 2014, cash provided by operations was used primarily to fund distributions to Unitholders.

The following table summarizes the Company’s Consolidated Statements of Cash Flows for the years ended December 31, 2015 and 2014:


	2015					2014
	Dollars %					Dollars %
	(Amounts in Thousands)
Operating Activities:
Net income (loss) before adjustments	$	(21,530	)	(535	)%	$	2,884		35	%
Adjustments		22,289		554			4,274		53

Cash flow from operations before working capital changes		759		19			7,158		88
Changes in working capital		464		11			1,004		12

Net cash provided by operating activities		1,223		30			8,162		100
Investing Activities:
Payments received on notes receivables from employees		30		1			83		1
Advances disbursed to employees		(14	)	—			(10	)	—
Purchase of property and equipment		(101	)	(2	)		(234	)	(3	)
Proceeds from sale of property and equipment		17		—			18		—
Proceeds from sale of other assets		250		6			—		—

Net cash provided by (used in) investing activities		182		5			(143	)	(2	)
Financing Activities:
Distributions		(3,963	)	(98	)		(7,088	)	(87	)
Repurchase of Units		(122	)	(3	)		(78	)	—
Proceeds from options exercised		61		1			39		—

Net cash used in financing activities		(4,024	)	(100	)		(7,127	)	(87	)

Net change in cash and equivalents	$	(2,619	)	(65	)%	$	892		11	%

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

As the above table indicates, the Company’s cash flow from operations before working capital changes during 2015 and 2014 represented 19% and 88% of total cash sources, respectively. The decrease in cash flow from operations before working capital changes as a percentage of total cash sources in 2015, as compared to the prior comparable period, was primarily due to less crude oil and natural gas sales, net of decreased production costs incurred, during 2015 as compared to 2014. Changes in working capital other than cash and equivalents increased cash by $464,000 and $1.0 million during 2015 and 2014, respectively. The $464,000 increase in cash resulting from changes in working capital other than cash and equivalents in 2015 was primarily the result of a decrease in accounts receivable from production, offset by a decrease in accrued expenses. The decrease in accounts receivable from production is the combined result of decreases in crude oil and natural gas volumes produced and lower crude oil and natural gas prices received during the current receivable production period as compared to the prior comparable receivable production period. The decrease in accrued expenses is primarily the result of less payroll and retirement plan contributions accrued during the fourth quarter of 2015 as compared to the prior comparable accrual period. The $1.0 million increase in cash resulting from changes in working capital other than cash and equivalents in 2014 was primarily the result of a decrease in accounts receivable from production and an increase in accounts payable. The decrease in accounts receivable from production is the combined result of decreases in crude oil and natural gas volumes produced and lower crude oil and natural gas prices received during the current receivable production period as compared to the prior comparable receivable production period. The increase in accounts payable is primarily due to an increase in production and other related payables at December 31, 2014, as compared to the prior comparable period.

The Company’s cash flows provided by investing activities were $182,000 in 2015, and the Company’s cash flows used in investing activities were $143,000 in 2014. The variance was primarily the result of proceeds received during 2015 for the sale of other assets and less purchases of property and equipment in 2015 as compared to 2014.

The Company’s cash flows used in financing activities were $4.0 million and $7.1 million in 2015 and 2014, respectively. The variance was primarily the result of less quarterly distributions paid to Unitholders in 2015 as compared to 2014.

The Company’s ending cash and equivalents balance of $22.7 million at December 31, 2015, as well as on-going monthly operating cash flows, should be adequate to meet short-term cash requirements. The Company has ceased making quarterly distributions effective January 2016 and management does not provide any assurances as to when quarterly distributions will resume, if ever.

Capital expenditures for the development of oil and gas properties decreased during 2015 as compared to the prior comparable period, as the Company participated in the drilling of

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only one new oil and gas property during 2015. The Company’s share of proved gas reserves decreased by 15.7 BCF, or 66%, between December 31, 2015 and December 31, 2014, while proved oil reserves decreased by 234,000 barrels, or 46%, between December 31, 2015 and December 31, 2014. The Standardized Measure of Discounted Future Net Cash Flows of the Company’s reserves decreased by $36.4 million between December 31, 2015 and December 31, 2014. The primary reasons for this decrease were due to sales of crude oil and natural gas during 2015, and decreases in crude oil and natural gas prices and the related downward revisions in quantities of natural gas reserves between December 31, 2015 and 2014. These factors were offset somewhat by the effect of accretion of the December 31, 2014 discount. Management considers it doubtful at this point that the Company will drill or participate in the drilling of any new wells during 2016.

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 26,774 and 11,964 Units during 2015 and 2014 pursuant to the Repurchase Right at prices of $4.56 and $6.51 per Unit, respectively. The Company has determined that the price associated with the 2016 Repurchase Right, based upon the December 31, 2015 calculation, is negative, and as such the Company will not be offering to repurchase Units in 2016.

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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, 2015 and 2014. 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,
	2015			2014
Revenues:
Crude oil and natural gas sales		90	%		96	%
Well management and operating		8			4
Other		2			—

Total revenues		100			100
Expenses:
Production costs		43			26
Well management and operating		5			2
Depreciation, depletion and amortization		195			25
Accretion expense		10			5
Write down/impairment and abandonment of crude oil and natural gas properties		151			—
General and administrative expense		42			21

Total expenses		446			79
Other income		4			—
Income tax benefit		(2	)		—

Net income (loss)		(340	)%		21	%

Revenues for the year ended December 31, 2015 decreased $7.5 million, or 54%, compared to the prior comparable period. This decrease was due primarily to a decrease in crude oil and natural gas sales during 2015 as compared with 2014.

Crude oil and natural gas sales decreased $7.5 million, or 57%, from 2014 to 2015. This decrease was the combined result of decreases in crude oil and natural gas volumes produced and lower crude oil and natural gas prices received during 2015 as compared to 2014. The average price received per MCF of natural gas decreased from $3.73 in 2014 to $2.29 in 2015. The average price received per BBL of crude oil decreased from $90.91 in 2014 to $46.61 in 2015. The Company’s natural gas production decreased by 653,000 MCF, or 29%, while crude oil production

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decreased by 9,000 BBLS, or 17%, from 2014 to 2015. The primary reason for the decrease in crude oil and natural gas volumes produced during 2015 as compared to 2014 is the result of additional operated oil and gas properties being voluntarily shut-in that weren’t otherwise shut-in during the prior comparable period. Natural gas sales accounted for 65% and 64% of total crude oil and natural gas sales in 2015 and 2014, respectively.

The Company recognized $109,000 of other revenues during 2015 primarily as the result of a sale of deep mineral interests associated with 80 acres held by a lease owned by the Company. The Company retained the rights to the shallow portion of the acreage sold.

Production costs decreased $921,000, or 25%, from 2014 to 2015. This decrease was primarily due to less operating fees incurred relative to additional properties being voluntarily shut-in during 2015 that were producing during the prior comparable period. Other various production costs that decreased in 2015 relative to the prior comparable period include water hauling expenses, ad valorem taxes, solvent, repairs and maintenance expenses associated with tank batteries, flow lines, sales lines, pump jacks, valves, wellheads and meters, and chart integration.

Depreciation, depletion and amortization increased $9.0 million, or 263%, from 2014 to 2015. Write down/impairment and abandonment of crude oil and natural gas properties was $9.6 million during 2015, an increase of $9.5 million over the amount recognized in the prior comparable period. As discussed earlier, the primary reason for the increase in both DD&A and Impairment and Abandonment in 2015 as compared to the prior comparable period is due to a substantial decrease in natural gas and crude oil reserves as of the most recent valuation date, December 31, 2015, as compared to the prior valuation date, December 31, 2014. The decrease in natural gas and crude oil reserves was primarily the result of significantly lower natural gas and crude oil prices used to value reserves at December 31, 2015 as compared to the prior comparable valuation date. The lower natural gas and crude oil prices contributed to decreasing the average economic life of the Company’s oil and gas properties as compared to their prior valuation date. In conjunction with the substantial declines in prices and decreases in average economic lives of properties, projected future cash flows associated with the natural gas and crude oil reserves as of December 31, 2015 decreased significantly as compared to the prior valuation date. Another factor that contributed to the increase in DD&A and Impairment and Abandonment from 2014 to 2015 is that there were additional oil and gas properties being depleted and assessed for impairment in 2015 as compared to the amount of properties being depleted and assessed for impairment in the prior comparable period. This was primarily the result of $3.1 million of additions to proved properties at December 31, 2014 in association with revisions made to estimates of plugging costs and remaining lives of wells associated with asset retirement obligations. The effect of the decreased natural gas and crude oil reserves and additional oil and gas properties on DD&A was offset somewhat by a decline in crude oil and natural gas volumes produced during 2015 as compared to the prior comparable period.

General and administrative expense decreased $197,000, or 7%, from 2014 to 2015. The primary reason for this decrease is the result of cost-cutting measures management has implemented in response to the current environment of depressed crude oil and natural gas prices within the national and regional oil and gas industries and its related effects on the Company’s

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sales, operational cash flows and working capital. The primary expenses that have decreased during 2015 as compared to the prior comparable period are payroll and employee benefits.

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

All current income tax expenses incurred by the Company during 2015 and 2014 were offset in their entirety by deferred income tax benefits. The Company recognized net income tax benefits of $109,000 during 2015, an increase of $108,000 over the amount recognized in the prior comparable period. The primary reason for the increase in income tax benefits is the result of a decrease in temporary differences arising from differences in financial reporting and tax reporting methods for EEI’s proved properties.

The Company reported a net loss of $21.5 million during 2015, as compared to net income of $2.9 million recognized in the prior comparable period. The primary reasons for the decrease are decreases in crude oil and natural gas sales and increases in DD&A and Impairment and Abandonment, offset somewhat by decreases in production costs and general and administrative expense and an increase in other income. The net loss represented 340% of total revenues during the year ended December 31, 2015, whereas net income represented 21% of total revenues during the year ended December 31, 2014.

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 $12.4 million and $3.4 million during 2015 and 2014, 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

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not be recoverable. The Company utilizes a field by field basis for assessing impairment of its oil and gas properties.

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

Crude oil and natural gas reserve estimates are prepared annually based on existing contractual arrangements and current market conditions. Any increases in estimated future cash flows would have no impact on the reported value of the Company’s crude oil and natural gas properties. In contrast, decreases in estimated future cash flows could require the recognition of an impairment loss equal to the difference between the estimated fair value of the crude oil and natural gas properties (determined by calculating the discounted value of the estimated future cash flows) and the carrying amount of the crude oil and natural gas properties. Any impairment loss would reduce property and equipment as well as total assets of the Company. An impairment loss would also decrease net income. The Company wrote down crude oil and natural gas properties by $9.6 million and $107,000 during 2015 and 2014, respectively, to provide for impairment and abandonment on certain of its crude oil and natural gas properties.

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

The estimated liability is based on historical experience in dismantling, plugging and abandoning wells, estimated remaining lives of those wells based on reserves estimates, estimates of the external cost to dismantle, plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability will likely occur due to: changes in estimates of dismantlement, plugging and abandonment costs; changes in estimated remaining lives of the wells; changes in federal or state regulations regarding dismantlement, plugging and abandonment requirements; and other factors. At December 31, 2015, the Company made revisions in estimates of remaining lives of wells. At December 31, 2014, the Company made revisions in estimates of plugging costs and remaining lives of wells.

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

-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, 2015 or 2014. Other revenues consist of gain on sale of deep rights and other miscellaneous revenues. Gain on sale of deep rights is recognized when title to deep mineral interests has been transferred and all terms and conditions to the sale have been met. Other miscellaneous revenues are recognized at the time services are rendered, the Company has a contractual right to such revenue and collection is reasonably assured.

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

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, increase depletion, depreciation and amortization and could potentially trigger impairment under generally accepted accounting principles, as they have significantly in 2015.

The majority of the Company’s production is sold at market responsive prices. Generally, if the related commodity index falls, the price received for the Company’s production will also decline. Therefore, the amount of revenue the Company realizes is partially determined by factors beyond the Company’s control. However, management has in recent years and may in the future mitigate this price risk on a portion of the Company’s anticipated production by shutting-

-27-

in wells during certain periods of depressed natural gas prices in an attempt to hold production for the future when natural gas prices have recovered. Under this arrangement, there is also a risk that natural gas prices will not recover and that the production of future volumes will be sold at the same depressed or potentially further depressed natural gas prices.

While the cost of operations is affected by inflation, crude oil and natural gas prices have fluctuated in recent years and generally have not matched inflation. The price of crude oil in the Appalachian Basin has ranged from a low of $8.50 per barrel in December 1998 to a high of $138.00 in July 2008. As of March 10, 2016, $33.84 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 2015 was $2.29 per MCF, a decrease of $1.44 per MCF as compared to 2014. The Company’s average price of natural gas during 2014 was $3.73 per MCF, a decrease of $0.11 per MCF as compared to 2013. The Company’s average price of natural gas during 2013 was $3.84 per MCF, an increase of $0.21 per MCF as compared to 2012. 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 2016 at $1.71 per MCF and the regional basis adjustment settled for the month of March 2016 at $(0.71) per MCF, resulting in a net regional market price of $1.00 per MCF. 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. As of March 10, 2016, the Company has not elected to lock in any monthly prices associated with volume commitments.

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

The Company’s Standardized Measure of Discounted Future Net Cash Flows decreased by $36.4 million from December 31, 2014 to December 31, 2015. 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.

-28-

EVERFLOW EASTERN PARTNERS, L. P.

2015 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 operations		F-6
Consolidated statements of partners’ equity		F-7
Consolidated statements of cash flows		F-8
Notes to consolidated financial statements		F-9 - F-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, 2015 and 2014, and the related consolidated statements of operations, partners’ equity, and cash flows for the years then ended. Everflow Eastern Partners, L.P.’s management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Everflow Eastern Partners, L.P. and subsidiaries as of December 31, 2015 and 2014, 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 25, 2016

F-3

EVERFLOW EASTERN PARTNERS, L. P.

CONSOLIDATED BALANCE SHEETS

December 31, 2015 and 2014


	2015		2014
ASSETS

CURRENT ASSETS
Cash and equivalents	$	22,734,047	$	25,353,579
Accounts receivable:
Production		572,502		1,461,882
Joint venture partners		4,151		6,775
Employees’ notes receivable		35,000		70,000
Other		45,838		56,438

Total current assets		23,391,538		26,948,674

PROPERTY AND EQUIPMENT
Proved properties (successful efforts accounting method)		181,293,110		177,223,180
Pipeline and support equipment		631,757		631,757
Corporate and other		2,114,844		2,114,844

		184,039,711		179,969,781
Less accumulated depreciation, depletion, amortization and write down		169,093,931		148,217,198

		14,945,780		31,752,583
OTHER ASSETS
Employees’ notes receivable		89,437		70,549
Other		176,442		187,302

		265,879		257,851

	$	38,603,197	$	58,959,108

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

F-4

EVERFLOW EASTERN PARTNERS, L. P.

CONSOLIDATED BALANCE SHEETS

December 31, 2015 and 2014


	2015		2014
LIABILITIES AND PARTNERS’ EQUITY

CURRENT LIABILITIES
Accounts payable	$	1,839,816	$	1,819,932
Accrued expenses		1,130,772		1,466,931

Total current liabilities		2,970,588		3,286,863

DEFERRED INCOME TAXES		74,000		194,000

JOINT VENTURE PARTNER ADVANCES		1,004,953		956,072

ASSET RETIREMENT OBLIGATIONS		16,393,560		10,808,044

COMMITMENTS AND CONTINGENCIES

LIMITED PARTNERS’ EQUITY, SUBJECT TO REPURCHASE RIGHT
Authorized - 8,000,000 Units Issued and outstanding - 5,587,616 and 5,601,003 Units, respectively		17,944,611		43,196,649

GENERAL PARTNER’S EQUITY		215,485		517,480

Total partners’ equity		18,160,096		43,714,129

	$	38,603,197	$	58,959,108

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

F-5

EVERFLOW EASTERN PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

Years Ended December 31, 2015 and 2014


	2015			2014
REVENUES
Crude oil and natural gas sales	$	5,728,206		$	13,247,538
Well management and operating		499,898			582,134
Other		109,408			10,531

Total revenues		6,337,512			13,840,203

DIRECT COST OF REVENUES
Production costs		2,734,789			3,655,764
Well management and operating		296,712			287,419
Depreciation, depletion and amortization		12,363,647			3,405,318
Accretion expense		583,792			642,799
Write down/impairment and abandonment of crude oil and natural gas properties		9,575,275			107,018

Total direct cost of revenues		25,554,215			8,098,318

GENERAL AND ADMINISTRATIVE EXPENSE		2,709,530			2,906,989

Total cost of revenues		28,263,745			11,005,307


INCOME (LOSS) FROM OPERATIONS		(21,926,233	)		2,834,896

OTHER INCOME
Interest income		34,222			42,821
Gain on sale of property and equipment		13,298			4,791
Gain on sale of other assets		239,652			—

Total other income		287,172			47,612


INCOME (LOSS) BEFORE INCOME TAXES		(21,639,061	)		2,882,508

INCOME TAX EXPENSE (BENEFIT)
Current		10,600			18,963
Deferred		(120,000	)		(20,000	)

Total income tax benefit		(109,400	)		(1,037	)


NET INCOME (LOSS)	$	(21,529,661	)	$	2,883,545


Allocation of Partnership Net Income (Loss)
Limited Partners	$	(21,274,495	)	$	2,849,428
General Partner		(255,166	)		34,117

	$	(21,529,661	)	$	2,883,545


Net income (loss) per unit	$	(3.80	)	$	0.51

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, 2015 and 2014


	2015			2014
PARTNERS’ EQUITY – JANUARY 1	$	43,714,129		$	47,957,644
Net income (loss)		(21,529,661	)		2,883,545
Cash distributions ($0.70 per unit in 2015 and $1.25 per unit in 2014)		(3,963,328	)		(7,088,117	)
Repurchase of Units		(122,089	)		(77,886	)
Options exercised		61,045			38,943

PARTNERS’ EQUITY – DECEMBER 31	$	18,160,096		$	43,714,129

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, 2015 and 2014


	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(21,529,661	)	$	2,883,545
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		12,452,899			3,495,201
Accretion expense		583,792			642,799
Write down/impairment and abandonment of crude oil and natural gas properties		9,575,275			107,018
Gain on sale of property and equipment		(13,298	)		(4,791	)
Gain on sale of other assets		(239,652	)		—
Deferred income taxes		(120,000	)		(20,000	)
Changes in assets and liabilities:
Accounts receivable		892,004			737,485
Other current assets		10,600			83,243
Other assets		860			(22,023	)
Accounts payable		19,884			135,322
Accrued expenses		(458,779	)		48,703
Joint venture partner advances		48,881			75,802

Total adjustments		22,752,466			5,278,759

Net cash provided by operating activities		1,222,805			8,162,304

CASH FLOWS FROM INVESTING ACTIVITIES
Payments received on notes receivables from employees		30,283			82,778
Advances disbursed to employees		(14,171	)		(10,065	)
Purchase of property and equipment		(101,084	)		(234,058	)
Proceeds from sale of property and equipment		17,355			18,000
Proceeds from sale of other assets		249,652			—

Net cash provided by (used in) investing activities		182,035			(143,345	)

CASH FLOWS FROM FINANCING ACTIVITIES
Distributions		(3,963,328	)		(7,088,117	)
Repurchase of Units		(122,089	)		(77,886	)
Proceeds from options exercised		61,045			38,943

Net cash used in financing activities		(4,024,372	)		(7,127,060	)

NET CHANGE IN CASH AND EQUIVALENTS		(2,619,532	)		891,899

CASH AND EQUIVALENTS AT BEGINNING OF PERIOD		25,353,579			24,461,680


CASH AND EQUIVALENTS AT END OF PERIOD	$	22,734,047		$	25,353,579

Supplemental disclosures of cash flow information:
Cash paid during the year for:
Income taxes	$	12,270		$	11,131

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 properties and also impact the timing and costs associated with asset retirement obligations. The Company’s estimates, especially those related to oil and gas reserves, could change in the near term and could significantly impact the Company’s results of operations and financial position.

F-9

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1.

Organization and Summary of Significant Accounting Policies

Fair Value of Financial Instruments – The fair values of cash and equivalents, accounts 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 because they are considered to be at current market rates. In accordance with generally accepted accounting principles, rates available to the Company at the balance sheet dates are used to estimate the fair value of existing obligations.

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 $1,004,953 and $956,072 of joint venture partner advances at December 31, 2015 and 2014, 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 $12,318,335 and $3,362,240 during 2015 and 2014, respectively.

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

F-10

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1.

Organization and Summary of Significant Accounting Policies

Property and Equipment (Continued)

future net cash flows. The estimated future production of oil and gas reserves is based upon the Company’s independent reserve engineer’s estimate of proved reserves which includes assumptions regarding field decline rates and future prices and costs. For properties where the carrying value exceeds undiscounted future net cash flows, the Company recognizes as impairment the difference between the carrying value and fair market value of the properties. The Company determines fair market value, using the income approach, as the properties’ discounted estimated future net cash flows. The key assumptions above are not observable in the market and therefore the fair value of the oil and gas properties is classified as Level 3. The Company wrote down crude oil and natural gas properties by $9,575,275 and $107,018 during 2015 and 2014, 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 $1,536,288 – 39 to 40 years). Depreciation on pipeline and support equipment amounted to $45,312 and $43,078 for the years ended December 31, 2015 and 2014, respectively. Depreciation on other corporate property and equipment, included in general and administrative expense, amounted to $89,252 and $89,883 for the years ended December 31, 2015 and 2014, 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

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. At December 31, 2015, the Company made revisions in estimates of remaining lives of wells. At December 31, 2014, the Company made revisions in estimates of plugging costs and remaining lives of wells.

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:


	2015			2014
Beginning of period	$	11,108,044		$	7,395,841
Liabilities incurred		432			819
Liabilities settled		(79,620	)		(54,045	)
Accretion expense		583,792			642,799
Revisions in estimated cash flows		5,123,912			3,122,630


End of period	$	16,736,560		$	11,108,044

The current portion of asset retirement obligations of $343,000 and $300,000 at December 31, 2015 and 2014, respectively, is included in accrued expenses in the Company’s consolidated balance sheets.

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, 2015 or 2014. Other revenues consist of gain on sale of deep rights and other miscellaneous revenues. Gain on sale of deep rights is recognized when title to deep mineral interests has been transferred and all terms and conditions to the sale have been met. Other miscellaneous revenues are recognized at the time services are rendered, the Company has a contractual right to such revenue and collection is reasonably assured.

F-12

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1.

Organization and Summary of Significant Accounting Policies

Revenue Recognition (Continued)

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. 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 (see Note 6). Accounts payable to joint venture partners consist principally of deposits received from joint venture partners for drilling and development costs (see Note 2). 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 the 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 operations regardless of the period when such items are reported for income tax purposes. Therefore, deferred tax assets and liabilities are recognized for temporary differences between the financial reporting basis and tax basis of certain EEI assets and liabilities. Deferred tax assets 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. Such allocation has changed and will likely change in the future 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 each year presented. Average outstanding Units for earnings per Unit calculations amount to 5,594,310 and 5,603,994 in 2015 and 2014, respectively.

F-13

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1.

Organization and Summary of Significant Accounting Policies

New Accounting Standards – In May 2014, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update No. 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASU 2014-09”). ASU 2014-09 is intended to improve the financial reporting requirements for revenue from contracts with customers by providing a principle based approach. The core principle of ASU 2014-09 is that revenue should be recognized when the transfer of promised goods or services is made in an amount that the entity expects to be entitled to in exchange for the transfer of goods and services. ASU 2014-09 also requires disclosures enabling users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The original effective date for financial statements issued by public companies was for annual reporting periods beginning after December 15, 2016. In July 2015, through issuance of ASU 2014-15, the FASB deferred the effective date for annual reporting periods beginning after December 15, 2017 (including interim reporting periods within those periods). Early adoption is permitted prior to the original effective date. The Company is currently evaluating the potential impact of these standards on the financial statements.

In November 2015, the FASB issued Accounting Standards Update No. 2015-17 “Balance Sheet Classification of Deferred Taxes (Topic 740)” (“ASU 2015-17”). ASU 2015-17 requires deferred tax liabilities and assets to be classified as noncurrent in the consolidated balance sheet. ASU 2015-17 is to be effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for financial statements that have not been previously issued. ASU 2015-17 may be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. The Company adopted ASU 2015-17 on a prospective basis during the fourth quarter of 2015. Adoption of ASU 2015-17 did not have a material impact on the Company’s financial statements.

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 results of operations.

F-14

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 2.

Current Liabilities

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


	2015		2014
Accounts Payable:
Production and related other	$	1,501,647	$	1,420,238
Other		290,935		288,521
Joint venture partner deposits		47,234		111,173

	$	1,839,816	$	1,819,932

Accrued Expenses:
Payroll and retirement plan contributions	$	679,934	$	1,055,255
Current portion of asset retirement obligations		343,000		300,000
Other		75,300		80,300
Federal, state and local taxes		32,538		31,376

	$	1,130,772	$	1,466,931

Note 3.

Partners’ Equity

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

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

F-15

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 3.

Partners’ Equity (Continued)

investors’ Units tendered shall be prorated for purposes of calculating the actual number of Units to be acquired during any such period. The Company has determined that the price associated with the 2016 Repurchase Right, based upon the December 31, 2015 calculation, is negative, and as such the Company will not be offering to repurchase Units in 2016. The Company did not make a distribution in January 2016.

The Company has an Option Repurchase Plan (the “Option Plan”) which permits the grant of options to repurchase certain Units to select officers and employees (the “Option Plan Participants”). The purpose of the Option Plan is to assist the Company in attracting and retaining officers and other key employees and to enable those individuals to acquire or increase their ownership interest in the Company in order to encourage them to promote the growth and profitability of the Company. The Option Plan is designed to align directly the financial interests of the Option Plan Participants with the financial interests of the Unitholders. In June 2015 and 2014, the Company granted options to officers and an employee. All options granted were exercised on the same date. Compensation expense associated with these grants was not material to the financial statements.

Units repurchased pursuant to the Repurchase Right and Units issued through the exercise of options pursuant to the Option Plan (collectively the “Units Activity”) for the three years ended December 31, 2015, are as follows:


	Per Unit
Year	Calculated Price for Repurchase Right		Less Interim Distributions		Net Price Paid		Units Repurchased		Units Issued		Units Outstanding Following Units Activity
2013	$	5.920	$	1.000	$	4.92		9,460		4,730		5,606,985
2014	$	7.010	$	0.500	$	6.51		11,964		5,982		5,601,003
2015	$	4.935	$	0.375	$	4.56		26,774		13,387		5,587,616

All Units repurchased pursuant to the Repurchase Right were retired except for those Units issued through the exercise of options pursuant to the Option Plan. There were no instruments outstanding at December 31, 2015 or 2014 that would potentially dilute net income per Unit.

F-16

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 operations follows:


	Year Ended December 31,
	2015						2014
	Amount			%			Amount			%
Provision based on the statutory rate	$	(7,357,000	)		(34.0	)	$	980,000			34.0
Tax effect of:
Non-taxable status of the Programs and Everflow		7,130,000			32.9			(981,000	)		(34.0	)
Excess statutory depletion		(30,000	)		(0.1	)		(53,000	)		(1.8	)
Graduated tax rates, permanent differences between book and tax items, tax credits and other - net		147,600			0.7			52,963			1.8

Total	$	(109,400	)		(0.5	)	$	(1,037	)		—

As referred to in Note 1, EEI accounts for deferred income taxes under the provisions of generally accepted accounting principles. Items giving rise to deferred taxes consist of temporary differences arising from differences in financial reporting and tax reporting methods for EEI’s proved properties. The Company recognized $120,000 and $20,000 of deferred income tax benefit during 2015 and 2014, respectively, related to deferred tax liabilities recognized at December 31, 2014 and 2013, respectively. The Company recognized deferred tax liabilities of $74,000 and $194,000 at December 31, 2015 and 2014, respectively.

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 $187,000 and $212,000 for the years ended December 31, 2015 and 2014, respectively.

F-17

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 5.

Retirement Plans (Continued)

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

Net periodic benefit cost recognized in the consolidated statements of operations consists of the following during the years ended December 31:


	2015			2014
Service cost	$	100,000		$	323,900
Interest cost		49,500			30,700
Expected return on plan assets		(64,800	)		(27,300	)
Settlements		40,900			—

Net periodic benefit cost	$	125,600		$	327,300

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


	2015			2014
Change in PBO:

PBO, beginning of year	$	990,700		$	620,000
Service cost		100,000			323,900
Interest cost		49,500			30,700
Actuarial (gain) loss		(24,700	)		19,200
Settlements		(1,115,500	)		—
Benefits paid		—			(3,100	)

PBO, end of year		—			990,700

Change in Plan assets:

Fair value, beginning of year		640,600			301,500
Actual return on plan assets		(800	)		23,700
Company contributions		475,700			318,500
Benefits paid		(1,115,500	)		(3,100	)

Fair value, end of year	$	—		$	640,600

Funded status at December 31	$	—		$	(350,100	)

F-18

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 5.

Retirement Plans (Continued)

The Company’s funding policy for the Plan was to fund at least the amount actuarially determined necessary to comply with the minimum funding standards as defined by the Employee Retirement Income Security Act. The entire underfunded amount at December 31, 2014, which was recognized as an accrued expense in the consolidated balance sheet, was funded in March 2015.

Assumptions used in accounting for the projected benefit obligation at December 31, 2014 included a discount rate of 5% and long-term asset return of 7%.

The Plan’s investment policy reflected the long-term nature of the plan’s funding obligations. The assets were invested to provide the opportunity for both income and growth of principal. This objective was pursued as a long-term goal designed to provide required benefits for participants without undue risk. It was expected that this objective would be achieved through a well-diversified asset portfolio. As such, the Plan’s assets, which were classified as Level 1 assets, were invested in a publicly traded mutual fund with a domestic blend of stocks and bonds at December 31, 2014. Upon the termination of the Plan in 2015, all Plan assets were distributed.

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 3.50% at December 31, 2015.

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, 2015 and 2014, the Company has extended various loans, evidenced by notes, to two employees with origination dates ranging from December 2010 to December 2015. In addition, three subsequent addenda extending additional two-year payment terms to certain notes are outstanding at December 31, 2015. Employee notes receivables, including accrued interest, amounted to $124,437 and $140,549 at December 31, 2015 and 2014, respectively.

F-19

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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 64% of total crude oil and natural gas sales in 2015 and 2014, respectively. Approximately 69% and 72% of total crude oil and natural gas sales were derived from operated wells in 2015 and 2014, respectively. The Company had two significant purchasers of natural gas production from operated wells for the years ended December 31, 2015 and 2014. Natural gas sales to these significant purchasers as a percentage of consolidated crude oil and natural gas sales were as follows:


Natural Gas Purchaser	2015			2014
Dominion Field Services, Inc. (“Dominion”)		27	%		29	%
Interstate Gas Supply, Inc. (“IGS”)		14			13

		41	%		42	%

As of December 31, 2015, natural gas purchased by Dominion covers production from approximately 460 gross operated wells, while natural gas purchased by IGS covers production from approximately 200 gross operated wells. Production purchased by Dominion and IGS from operated wells comprised approximately 63% and 66% of the Company’s consolidated natural gas sales in 2015 and 2014, respectively.

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

F-20

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 7.

Business Segments, Risks and Major Customers (Continued)

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, 2015 and 2014. 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 2016. Historically, the Company has not tracked the purchasers of natural gas and crude oil derived from third party operated wells which may have the same customers.

Note 8.

Commitments and Contingencies

In conjunction with the sale of approximately 28,800 acres of deep rights made in 2012, the Company agreed to perpetuate the producing leases for a minimum period of five years. If the Company fails to perpetuate the producing leases during such five-year period, it shall refund to the purchaser the portion of the purchase price attributable to the affected properties based on an allocated value of $1,250 per acre (the “Refund Price”), provided however, that should the Company revive or otherwise renew such expired leases within three months of their expiration, the purchaser shall have the right to acquire the deep rights on such revived or renewed leases for the Refund Price. The Company has assessed the shallow operations of all properties from which deep acreage was sold and does not believe a reserve for potential refunded acreage to be necessary at December 31, 2015.

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

F-21

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9.

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

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

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

CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES


	Years ended December 31,
	2015		2014
Proved oil and gas properties	$	181,293,110	$	177,223,180
Pipeline and support equipment		631,757		631,757

		181,924,867		177,854,937
Accumulated depreciation, depletion, amortization and write down		168,088,105		147,304,820

Net capitalized costs	$	13,836,762	$	30,550,117

COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES


	Years ended December 31,
	2015		2014
Property acquisition costs	$	29,037	$	13,015
Development costs		72,047		149,405

The Company had no purchases of producing oil and gas properties in 2015 or 2014.

F-22

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9.

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

RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES


	Years ended December 31,
	2015			2014
Crude oil and natural gas sales	$	5,728,206		$	13,247,538
Production costs		(2,734,789	)		(3,655,764	)
Depreciation, depletion and amortization		(12,363,647	)		(3,405,318	)
Accretion expense		(583,792	)		(642,799	)
Write down/impairment and abandonment of crude oil and natural gas properties		(9,575,275	)		(107,018	)

		(19,529,297	)		5,436,639
Income tax expense		11,000			19,000

Results of operations for oil and gas producing activities (excluding corporate overhead and financing costs)	$	(19,540,297	)	$	5,417,639

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 9.

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, 2014		586,000			27,653,000
Extensions, discoveries and other additions		2,000			8,000
Production		(53,000	)		(2,269,000	)
Revision of previous estimates		(24,000	)		(1,668,000	)

Balance, December 31, 2014		511,000			23,724,000
Extensions, discoveries and other additions		2,000			5,000
Production		(44,000	)		(1,616,000	)
Revision of previous estimates		(192,000	)		(14,122,000	)

Balance, December 31, 2015		277,000			7,991,000

PROVED DEVELOPED RESERVES:
December 31, 2013		586,000			27,653,000
December 31, 2014		511,000			23,724,000
December 31, 2015		277,000			7,991,000

The Company has not determined proved reserves associated with its proved and other undeveloped properties, including its deep property interests. At December 31, 2015 and 2014, the Company had 91 and 394 net proved undeveloped acres, respectively. The net carrying cost of the proved undeveloped acreage that is included in proved properties amounted to approximately $35,700 and $214,600 at December 31, 2015 and 2014, respectively.

F-24

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9.

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


STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
	December 31,
	2015			2014
	(Thousands of Dollars)
Future cash inflows from sales of oil and gas	$	23,821		$	124,127
Future production and development costs		(15,446	)		(60,296	)
Future asset retirement obligations, net of salvage		(16,443	)		(16,506	)
Future income tax expense		(144	)		(1,159	)

Future net cash flows		(8,212	)		46,166
Effect of discounting future net cash flows at 10% per annum		1			(18,009	)

Standardized measure of discounted future net cash flows	$	(8,211	)	$	28,157

CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS


	Years Ended December 31,
	2015			2014
	(Thousands of Dollars)
Balance, beginning of year	$	28,157		$	41,661
Extensions, discoveries and other additions		30			29
Development costs incurred		—			42
Revision of quantity estimates		(2,562	)		(1,538	)
Sales of crude oil and natural gas, net of production costs		(2,993	)		(9,592	)
Net change in income taxes		573			226
Net changes in prices and production costs		(31,254	)		(3,912	)
Accretion of discount		2,816			4,166
Other		(2,978	)		(2,925	)

Balance, end of year	$	(8,211	)	$	28,157

F-25

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9.

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

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

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

Average adjusted natural gas prices used in the estimation of proved reserves were $1.37 and $3.28 at December 31, 2015 and 2014, respectively, and the average adjusted crude oil prices used in the estimation of proved reserves were $46.40 and $90.53 at December 31, 2015 and 2014, respectively.

F-26

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.

CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

As of the end of the period covered by this report, management performed, with the participation of our Chief Executive Officer and Chief Financial Officer, an evaluation of the effectiveness of our disclosure controls and procedures as defined in Exchange Act Rules 13a-15. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures. Based on the evaluation, management concluded that our disclosure controls and procedures were effective for the year ended December 31, 2015.

Management’s Report on Internal Control Over Financial Reporting

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

Management is responsible for assessing the effectiveness of our internal controls over financial reporting. The Company’s management, including the Chief Executive Officer and the Chief Financial Officer, conducted an evaluation of the effectiveness of internal control over financial reporting as of December 31, 2015 based on the guidelines established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) (2013 Framework).

-29-

Management utilized internal and external resources to assist in the various aspects of its assessment and compliance efforts. As a result of its assessments, management has concluded that the Company’s internal controls over financial reporting were effective as of December 31, 2015.

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

Changes in Internal Control Over Financial Reporting

Management, including its Chief Executive Officer and Chief Financial Officer, has concluded that there were no changes in the Company’s internal control over financial reporting during 2015 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, 2016 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, 2016, 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, 2016 are as follows:


Name	Age		Positions and Offices with EEI	Positions and Offices with EMC

Thomas L. Korner		62	Chairman of the Board and director	Chairman of the Board and director

Robert F. Sykes		92	Director	Director

Peter H. Sykes		59	None	Director

William A. Siskovic		60	President, Principal Executive Officer and director	President, Principal Executive Officer and director

Brian A. Staebler		41	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

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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.

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, 2015, for filing with the Securities and Exchange Commission.

Respectfully submitted by the members of the Audit Committee:

William A. Siskovic (Chairman)

Thomas L. Korner

Robert F. Sykes

Peter H. Sykes

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 2015 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 2015 Executive Compensation Components

Components of executive compensation in the 2015 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 2015 are shown in the Summary Compensation Table appearing on page 37 herein.

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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 2015, the Board of Directors set a range of these bonuses between 90% and 150% of the executive’s base salary, based on the Company achieving specified financial and non-financial performance objectives. In 2015, the financial performance objectives that were used for determining financial performance-based cash awards were asset management, profitability and overall company stability. In 2015, the non-financial performance objectives that were used for determining non-financial performance based cash awards were corporate governance and adherence to policies and procedures as well as other factors that vary depending on responsibilities.

The 2016 target annual cash bonus awards for executive officers are established as a percentage of the executive’s base salary. These target amounts range between 90% and 150% of base salary. These target amounts were determined considering executive pay at companies of comparable size. The Board of Directors believes it is important that these target and maximum payout levels are aligned with the Company’s long-term strategic plan and the Company’s expectation of future financial performance.

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 2015 and 2014, the Company granted a total of 10,710 and 4,786 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, 2015 and 2014, of those persons who were at December 31, 2015: (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⁾		Other Compensation⁽²⁾			Total
William A. Siskovic,		2015	$	125,200	$	175,000	$	—	$	83,220	⁽³⁾	$	383,420
President and Principal Executive Officer		2014	$	122,700	$	166,000	$	—	$	262,070	⁽³⁾	$	550,770

Brian A. Staebler,		2015	$	113,000	$	130,000	$	—	$	76,090	⁽⁴⁾	$	319,090
Vice President and		2014	$	110,500	$	101,000	$	—	$	120,420	⁽⁴⁾	$	331,920
Principal Financial and Accounting Officer

No Named Executive Officer received personal benefits or perquisites during 2015 or 2014 in excess of $10,000.

(1)

In June 2015 and 2014, the Company issued William A. Siskovic and Brian A. Staebler each 5,355 and 2,393 options, respectively, to repurchase certain Units at exercise prices of $4.56 per Unit and $6.51 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 2015 and 2014.

(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, which was terminated in December 2015, 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)

During fiscal years ended December 31, 2015 and 2014, includes $26,500 and $31,200, respectively, contributed as profit sharing to the Defined Contribution Plan, $7,950 and $7,800 contributed as matching contributions to the Defined Contribution Plan, $40,500 and $215,000, respectively, awarded as benefits to the Pension Plan, $1,700 and $1,500, respectively, considered taxable wages with respect to personal use of a Company vehicle, and $6,570 considered taxable wages with respect to the Company’s Group Term Life Insurance Plan and additional supplemental life insurance.

(4)

During fiscal years ended December 31, 2015 and 2014, includes $24,360 and $25,310, respectively, contributed as profit sharing to the Defined Contribution Plan, $7,310 and $6,330, respectively, contributed as matching contributions to the Defined Contribution Plan, $40,500 and $85,000, respectively, awarded as benefits to the Pension Plan, $2,590 and $2,450, respectively, considered taxable wages with respect to personal use of a Company vehicle, and $1,330 considered taxable wages with respect to the Company’s Group Term Life Insurance Plan and additional supplemental life insurance.

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

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Outstanding Equity Awards

During June 2015 and 2014, the Company granted a total of 10,710 and 4,786 options, respectively, to executive officers. All options granted were exercised during the same month. There were no outstanding unexercised options as of December 31, 2015 or 2014.

Retirement Plans

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

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

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

Director Compensation

Thomas L. Korner, William A. Siskovic, Brian A. Staebler, Robert F. Sykes and Peter H. Sykes did not receive any additional compensation for their service as Directors during the 2015 or 2014 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, 2016 are EMC; two individuals who are officers and directors of EEI, William A. Siskovic and Brian A. Staebler; one individual who serves as the Chairman of the Board of EEI, Thomas L. Korner; one individual who is an employee of the Company, Richard M. Jones; and one New York limited liability company founded by an individual who is a director of EEI, Robert F. Sykes, and owned by the four adult children of Mr. Sykes. The General Partner of the Company owns a 1.19% interest in the Company.

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The following table sets forth certain information with respect to the number of Units beneficially owned as of March 10, 2016 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		2.84		*		*
William A. Siskovic (officer and director of EMC)		86,230		1.55		16.6667		16.6667
Thomas L. Korner (Chairman of the Board & director of EMC)		64,476		1.15		16.6667		16.6667
Peter H. Sykes⁽⁴⁾(director of EMC)		41,244		0.74		*		*
Brian A. Staebler (officer and director of EMC)		15,213		0.27		8.3333		8.3333

		365,797		6.55		41.6667		41.6667
Other Beneficial Owners of >5% of the Company
David F. Sykes⁽⁵⁾		774,099		13.85		50.0000		50.0000

		1,139,896		20.40		91.6667		91.6667

*	Represents less than one percent.

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

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

(3)	Includes 79,639 Units held 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 13.11% of the Company’s outstanding Units, held by Sykes Associates, LLC, a New York limited liability company located at 27 Wexford Glen, Pittsford, NY 14535 and owned by the four adult children of Robert F. Sykes as members, and 41,244 Units of the Company held by DFS Associates, a New York limited partnership owned by the family of David F. Sykes, who manages Sykes Associates, LLC. David F. Sykes is the son of Robert F. Sykes and is not an officer or director of EMC.

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ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

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

Certain officers and directors of EMC own crude oil and natural gas properties and, as such, contract with the Company to provide field operations on such properties. These ownership interests are charged per well fees for such services on the same basis as all other working interest owners. William A. Siskovic made investments in crude oil and natural gas properties during 2015 and 2014 in the amount of $9,210 and $3,720, respectively. Brian A. Staebler made investments in crude oil and natural gas properties during 2015 and 2014 in the amount of $9,210 and $1,860, respectively. Thomas L. Korner made investments in crude oil and natural gas properties during 2015 and 2014 in the amount of $9,210 and $3,720, 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, 2015 and 2014. 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, 2015 and 2014, respectively.


	December 31,
	2015		2014
Audit fees	$	161,222	$	168,782
Audit related fees		—		—
Tax fees		855		1,000
All other fees		—		—

Total	$	162,077	$	169,782

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 2015 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 Operations		F-6
Consolidated Statements of Partners’ Equity		F-7
Consolidated Statements of Cash Flows		F-8
Notes to Consolidated Financial Statements		F-9 - F-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).

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

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

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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 25, 2016
	Robert F. Sykes

By:	/s/ Peter H. Sykes	Director	March 25, 2016
	Peter H. Sykes

By:	/s/ Thomas L. Korner	Director	March 25, 2016
	Thomas L. Korner

By:	/s/ William A. Siskovic William A. Siskovic	President, Principal Executive Officer and Director	March 25, 2016

By:	/s/ Brian A. Staebler Brian A. Staebler	Vice President, Secretary-Treasurer, Principal Financial and Accounting Officer and Director	March 25, 2016

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, 2008	(4	)

10.1	Shareholders Agreement for Everflow Management Corporation	(1	)

10.2	Operating facility lease dated October 3, 1995 between Everflow Eastern Partners, L.P. and A-1 Storage 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 January 28, 2016 concerning evaluation of oil and gas reserves.

99.2	Audit Committee Charter of Everflow Management Corporation	(7	)

101.INS	Instance Document

101.SCH	XBRL Taxonomy Extension Schema Document

101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document

E-1

Exhibit Index


Exhibit No.		Description

101.LAB		XBRL Taxonomy Extension Label Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

(1)	Incorporated herein by reference to the appropriate exhibit to Registrant’s Registration Statement 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).

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

E-2

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company