UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

o		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)

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

		Name of each exchange
Title of each class		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 o No þ

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 o No þ

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 þ No o

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 o No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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. o

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.

Large accelerated filer o		Accelerated filer o		Non-accelerated filer o		Smaller reporting company þ
				(Do not check if a smaller reporting company)

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

There were 4,437,479 Units of Limited Partnership Interest held by non-affiliates of the Registrant as of June 30, 2009. At June 30, 2009, there was no public market for the Registrant’s Units of Limited Partnership Interest. The Units generally do not have any voting rights, but, in certain circumstances, the Units are entitled to one vote per Unit.

Except as otherwise indicated, the information contained in this Report is as of December 31, 2009.

 

 

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 (telephone number 330-533-2692).

Description of the Business

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

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

A-1 Storage of Canfield, Ltd. (“A-1 Storage”) was organized as an Ohio limited liability company in late 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 80% of the estimated total future cash inflows related to the Company’s crude oil and natural gas reserves as of December 31, 2009 are attributable to natural gas reserves. The majority of such properties are located in Ohio and consist primarily of proved producing properties with established production histories.

The Company’s operations since February 1991 primarily involve the production and sale of oil and gas and the drilling and development of approximately 420 (net) wells. The Company serves as the operator of approximately 60% 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.

Business Plan. The Company continually evaluates whether the Company can develop oil and gas properties at historical levels given the current costs of drilling and development activities, the current prices of oil and gas, and the Company’s ability to find oil and gas in commercially productive quantities. In recent years, the Company dedicated additional resources to its land and lease acquisition department in an effort to increase its undeveloped lease inventory. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.”

Acquisition of Prospects. The Company maintains a leasehold inventory from which the General Partner will select oil and gas prospects for development by the Company. The Company makes additions to such leasehold inventory on an on-going basis. The Company may also acquire leases from third parties. Prior to 2000, EEI generated approximately 90% of the prospects which were drilled. Beginning in 2000, the Company began generating fewer prospects and has participated in more joint ventures with other operators. As of December 31, 2009, the Company’s current leasehold inventory consists of approximately 84 prospects in various stages of maturity representing approximately 1,653 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.

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 acquired 2 gross (1.98 net) producing oil and gas properties during 2009. Over the few years prior to 2009, there were no acquisitions of producing oil and gas properties.

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, 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 2009 and no principal indebtedness was outstanding as of March 20, 2010. 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 15, 1991 (the “Partnership Agreement”(1)) does not contain any specific restrictions on borrowings, the Company has no specific plans to borrow for the acquisition of producing oil and gas properties. The Company expects that borrowings may be necessary to enable it to repurchase Units tendered in connection with the Repurchase Right (as defined under [ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES]). See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Liquidity and Capital Resources.”

The Company owns a significant amount of oil and gas reserves. The Company generally does not expect to borrow funds, from whatever source, in excess of 40% of its total value of proved developed reserves (as determined using the Company’s Standardized Measure of Discounted Future Net Cash Flows). However, there can be no assurance that the Company’s future obligations and liabilities would not lead to borrowings in excess of such amount. Based upon its current business plan, management has no present intention to cause the Company to borrow in excess of this amount. The Company has estimated the value of proved and proved developed reserves, determined as of December 31, 2009, which aggregate $49,671,000 (Standardized Measure of Discounted Future Net Cash Flows) with no borrowings outstanding as of December 31, 2009.

Marketing. The ability of the Company to market oil and 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. All posted prices in the areas where the Company’s properties are located are generally somewhat lower than the spot market prices, although there have been substantial fluctuations in crude oil prices in recent years, including 2009.

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 2009. As of March 20, 2010, $74.50 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”) and the possibility of supply interruptions. To the extent the prices that the Company receives for its crude oil production decline or remain at current levels, the Company’s revenues from crude oil production will be reduced accordingly.

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

Natural Gas. The deliverability and price of natural gas is subject to various factors affecting the supply and demand of natural gas as well as the effect of federal regulations. Prior to 2000, there had been a surplus of natural gas available for delivery to pipelines and other purchasers. During 2000, decreases in worldwide energy production capability and increases in energy consumption resulted in a shortage in natural gas supplies. This resulted in increases in natural gas prices throughout the United States, including the Appalachian Basin. During 2001, lower energy consumption and increased natural gas supplies reduced prices to historical levels. During the period from 2002 through the first half of 2008, shortages in natural gas supplies had resulted from increased energy consumption from industrial, commercial, residential and electric power usage. During the second half of 2008 and through 2009, excess natural gas supplies resulted from the combination of increased production from independent producers and decreased industrial and commercial energy consumption resulting from the global and United States financial crises and recession. From time to time, especially in summer months, seasonal restrictions on natural gas production have occurred as a result of distribution system restrictions.

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

Since 2002, the Company has had and continues to have numerous annual contracts with Dominion, which obligate Dominion to purchase, and the Company to sell and deliver, certain quantities of natural gas production from the Company’s oil and gas properties throughout the contract periods. The Company may elect to lock-in specific volumes of natural gas to be sold in specific months at a mutually agreeable price. The Company has elected to lock-in various monthly quantities of natural gas which total 1.64 BCF through October 2011 at various monthly weighted-average prices ranging from $7.95 to $9.75 per MCF.

The Company also has two annual contracts with Interstate Gas Supply, Inc. (“IGS”), which obligate IGS to purchase, and the Company to sell and deliver, certain quantities of natural gas production from the Company’s oil and gas properties throughout the contract periods. The Company may elect to lock-in specific volumes of natural gas to be sold in specific months at a mutually agreeable price. The Company has elected to lock-in various monthly quantities of natural gas which total .99 BCF through October 2011 at various monthly weighted-average prices ranging from $8.05 to $9.49 per MCF.

A summary of the Company’s locked-in volumes and prices with Dominion and IGS by year is as follows:

		Dominion								IGS								Total
						Weighted-								Weighted-								Weighted-
Year Ending						Average								Average								Average
December 31:		BCF				Price/MCF				BCF				Price/MCF				BCF				Price/MCF
2010			1.18			$	9.13				0.66			$	8.84				1.84			$	9.03
2011			0.46				8.00				0.33				8.10				0.79				8.04
			1.64			$	8.81				0.99			$	8.59				2.63			$	8.73

As described 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 plus 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, 2009, natural gas purchased by Dominion covers production from approximately 540 gross wells, while natural gas purchased by IGS covers production from approximately 240 gross wells. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Inflation and Changes in Prices.”

For the year ended December 31, 2009, with the exception of Dominion and IGS, which accounted for approximately 44% and 22%, respectively, of the Company’s natural gas sales, no one natural gas purchaser has accounted for more than 10% of the Company’s gas sales. The Company expects that Dominion and IGS will be the only material natural gas customers for fiscal 2010.

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

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

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

The availability of a ready market for the oil and gas production of the Company depends in part on the cost and availability of alternative fuels, the level of consumer demand, the extent of other domestic production of oil and gas, the extent of importation of foreign oil and gas, the cost of and proximity to pipelines and other transportation facilities, regulations by state and federal authorities and the cost of complying with applicable environmental regulations. The volatility of prices for oil and gas and the continued oversupply of domestic natural gas have, at times, 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 oil and gas prices, widespread curtailment of gas production and delays in producing and marketing gas after it is discovered. Changes in government regulations relating to the production, transportation and marketing of natural gas have also resulted in significant changes in the historical marketing patterns of the industry. Generally, these changes have resulted in the abandonment by many pipelines of long-term contracts for the purchase of natural gas, the development by gas producers of their own marketing programs to take advantage of new regulations requiring pipelines to transport gas for regulated fees, and an increasing tendency to rely on short-term sales contracts priced at spot market prices. See “Marketing” above.

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

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

The interstate transportation and sale for resale of natural gas is regulated by the Federal Energy Regulatory Commission (the “FERC”) under the Natural Gas Act of 1938. The wellhead price of natural gas is also regulated by the FERC under the authority of the Natural Gas Policy Act of 1978 (“NGPA”). Subsequently, the Natural Gas Wellhead Decontrol Act of 1989 (the “Decontrol Act”) was enacted on July 26, 1989. The Decontrol Act provided for the phasing out of price regulation under the NGPA commencing on the date of enactment and completely eliminated all such gas price regulation on January 1, 1993. In addition, the FERC has adopted and proposed several rules or orders concerning transportation and marketing of natural gas. The impact of these rules and other regulatory developments on the Company cannot be predicted. It is expected that the Company will sell natural gas produced by its oil and gas properties to a number of purchasers, including various industrial customers, pipeline companies and local public utilities, although the majority 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, possibly resulting in an erosion of the premium price historically available for Appalachian natural gas. Regulation of the production, transportation and sale of oil and gas by federal and state agencies has a significant effect on the Company and its operating results. Certain states, including Ohio and Pennsylvania, have established rules and regulations requiring permits for drilling operations, drilling bonds and reports concerning the spacing of wells. The ultimate impact of these rules and other regulatory developments on the Company cannot be predicted.

In addition, from time to time, prices for either crude oil or natural gas have been regulated by the federal government, and such price regulation could be re-imposed at any time in the future.

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

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

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

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

Conflicts of Interest. The Partnership Agreement grants the General Partner broad discretionary authority to make decisions on matters such as the Company’s acquisition of or participation in a drilling prospect or a producing property. To limit the General Partner’s management discretion might prevent it from managing the Company properly. However, because the business activities of the affiliates of the General Partner on the one hand and the Company on the other hand are the same, potential conflicts of interest are likely to exist, and it is not possible to completely mitigate such conflicts.

The Partnership Agreement contains certain restrictions designed to mitigate, to the extent practicable, these conflicts of interest. The agreement restricts, among other things, (i) the cost at which the General Partner or its affiliates may acquire properties from or sell properties to the Company; (ii) loans between the General Partner, its affiliates and the Company, and interest and other charges incurred in connection therewith; and (iii) the use and handling of the Company’s funds by the General Partner.

Employees. As of March 20, 2010, the Company had 17 full-time and 4 part-time employees. These employees primarily are engaged in the following areas of business operations: five in land and lease acquisition, four in field operations, six in accounting, and six in administration.

ITEM 1A.		RISK FACTORS

Certain statements made in this Annual Report on Form 10-K contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934 (“Exchange Act”). All statements that address operating performance, events or developments that we anticipate will occur in the future, including statements related to future revenue, profits, expenses, income and earnings per share or statements expressing general optimism about future results, are forward-looking statements. In addition, words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “estimates,” variations of such words, and similar expressions are intended to identify forward-looking statements. Forward-looking statements are subject to the safe harbors created in the Exchange Act. Forward-looking statements are subject to numerous assumptions and risks and uncertainties that may cause our actual results or performance to be materially different from any future results or performance expressed or implied by the forward-looking statements. We have identified the following important factors which could cause our actual operational or financial results to differ materially from any projections, estimates, forecasts or other forward-looking statements made by or on our behalf. Under no circumstances should the factors listed below be construed as an exhaustive list of all factors that could cause actual results to differ materially from those expressed in forward-looking statements. We undertake no obligation to review or confirm analysts’ expectations or estimates or to release publicly any revisions to forward-looking statements contained herein to take into account events or circumstances that occur after the date of this Annual Report on Form 10-K. In addition, we do not undertake any responsibility to update publicly the occurrence of unanticipated events which may cause actual results to differ from those expressed or implied by the forward-looking statements contained herein.

Continued weakness in the United States and global economic condition or in any of the industries in which purchasers of crude oil or natural gas operate, or sustained uncertainty in financial markets may have a material adverse impact on our business and financial condition that we currently cannot predict.

Economic conditions in the United States and globally have deteriorated and the extent and timing of a full recovery is uncertain. Financial markets in the United States, Europe and Asia have experienced a period of unprecedented turmoil and upheaval characterized by extreme volatility and declines in security prices, severely diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure, collapse or sale of various financial institutions and an unprecedented level of intervention from the United States federal government and other governments. Unemployment has risen while business and consumer confidence have declined and there are fears of a prolonged recession. These deteriorating economic conditions, credit crises and related turmoil in national and global financial systems have substantially contributed to the dramatic decreases in crude oil prices in the second half of 2008 and natural gas prices in the second half of 2008 and throughout the majority of 2009. The price declines have adversely affected United States crude oil and natural gas producers, including us. The economic downturn and decline in crude oil and natural gas prices are providing declines in drilling costs and increased availability of field equipment, but those cost reductions may only partially mitigate the adverse effects of lower crude oil and natural gas prices.

Uncertainties as to the extent, duration and impacts of the United States and global economic downturn increase uncertainties and risks for us. With the general economic downturn, (i) the demand for natural gas in the United States has declined and may remain at low levels or further decline if economic conditions remain weak and continue to negatively impact the revenues, margins and profitability of our natural gas business, (ii) the tightening of credit or lack of credit availability to our suppliers, customers and joint venture partners could adversely affect their ability to meet their obligations to us, (iii) we may be unable to profitably sell, extend or explore crude oil and natural gas lease rights we currently own and (iv) we may face unanticipated challenges to our business and financial condition. Unexpected bankruptcies of financial institutions or unexpected illiquidity of funds in cash equivalent investments, such as money market funds, may limit or delay our access to our cash equivalent deposits, causing us to lose some or all of those funds or to incur additional costs to borrow funds needed on a short-term basis.

Natural gas and crude oil prices fluctuate widely, and low prices for an extended period of time are likely to have a material adverse impact on our business.

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, to a lesser extent, crude oil. Lower commodity prices may reduce the amount of natural gas and crude oil that we can produce economically. Historically, natural gas and crude oil 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 our future financial results. Because our reserves are predominantly natural gas, changes in natural gas prices may have a particularly large impact on our financial results.

Prices for natural gas and crude oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and crude oil, market uncertainty and a variety of additional factors that are beyond our control. These factors include:

	•		the level of consumer product demand;
	•		weather conditions;
	•		political conditions in natural gas and crude oil producing regions, including the Middle East;
	•		the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
	•		the price of foreign imports;
	•		actions of governmental authorities;
	•		pipeline capacity constraints;
	•		inventory storage levels;
	•		additional supply made available to the marketplace through new or previously inaccessible formations;
	•		domestic and foreign governmental regulations;
	•		the price, availability and acceptance of alternative fuels; and
	•		overall economic conditions.

These factors and the volatile nature of the energy markets make it impossible to predict with any certainty the future prices of natural gas and crude oil. If natural gas prices decline significantly for a sustained period of time, the lower prices may adversely affect our ability to make planned expenditures, including capital expenditures and cash distributions.

Drilling natural gas and crude oil wells is a high-risk activity.

Our growth is materially dependent upon the success of our drilling program. Drilling for natural gas and crude oil involves numerous risks, including the risk that no commercially productive natural gas or crude oil reservoirs will be encountered. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors beyond our control, including:

	•		unexpected drilling conditions, pressure or irregularities in formations;
	•		equipment failures or accidents;
	•		adverse weather conditions;
	•		compliance with governmental requirements; and
	•		shortages or delays in the availability of drilling rigs or crews and the delivery of equipment.

Our future drilling activities may not be successful and, if unsuccessful, such failure will have an adverse effect on our future results of operations and financial condition. Our overall drilling success rate or our drilling success rate for activity within a particular geographic area may decline. We may ultimately not be able to lease or drill identified or budgeted prospects within our expected time frame, or at all. We may not be able to lease or drill a particular prospect because, in some cases, we identify a prospect or drilling location before seeking an option or lease rights in the prospect or location. Similarly, our drilling schedule may vary from our capital budget. The final determination with respect to the drilling of any scheduled or budgeted wells will be dependent on a number of factors, including:

	•		the availability of sufficient capital resources to us and the other participants for the drilling of the prospects;
	•		economic and industry conditions at the time of drilling, including prevailing and anticipated prices for natural gas and crude oil and the availability of drilling rigs and crews;
	•		our financial resources and results; and
	•		the availability of leases and permits on reasonable terms for the prospects.

These projects may not be successfully developed and the wells, if drilled, may not encounter reservoirs of commercially productive natural gas or crude oil.

Reserve estimates depend on many assumptions that may prove to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated.

Reserve engineering is a subjective process of estimating underground accumulations of natural gas and crude oil that cannot be measured in an exact manner. The process of estimating quantities of proved reserves is complex and inherently uncertain, and the reserve data included in this document are only estimates. The process relies on interpretations of available geologic, geophysic, engineering and production data. As a result, estimates of different engineers may vary. In addition, the extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as natural gas and crude oil prices. Additional assumptions include drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of:

	•		the quality and quantity of available data;
	•		the interpretation of that data;
	•		the accuracy of various mandated economic assumptions; and
	•		the judgment of the persons preparing the estimate.

Results of drilling, testing and production subsequent to the date of an estimate may justify revising the original estimate. Accordingly, initial reserve estimates often vary from the quantities of natural gas and crude oil that are ultimately recovered, and such variances may be material. Any significant variance could reduce the estimated quantities and present value of our reserves.

You should not assume that the present value of future net cash flows from our proved reserves is the current market value of our estimated natural gas and crude oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on prices based on the 12-month average of the first-day-of-the-month price for each month within the prior 12 month period, and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with generally accepted accounting principles may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and crude oil industry in general.

Our future performance depends on our ability to find or acquire additional natural gas and crude oil reserves that are economically recoverable.

In general, the production rate of natural gas and crude oil properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Unless we successfully replace the reserves that we produce, our reserves will decline, eventually resulting in a decrease in natural gas and crude oil production and lower revenues and cash flow from operations. Our future natural gas and crude oil production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. We may not be able to replace reserves through our acquisition and development activities. Low natural gas and crude oil prices may further limit the kinds of reserves that we can develop economically. Lower prices also decrease our cash flow and may cause us to decrease capital expenditures.

Development activities involve numerous risks that may result in dry holes, the failure to produce natural gas and crude oil in commercial quantities and the inability to fully produce discovered reserves.

We are continually identifying and evaluating opportunities to acquire natural gas and crude oil properties. We may not be able to successfully consummate any acquisition, to acquire producing natural gas and crude oil properties that contain economically recoverable reserves, or to integrate the properties into our operations profitably.

We may incur substantial impairment write downs.

If reserve estimates of the recoverable reserves in a property are revised downward, if development costs exceed previous estimates or if natural gas and crude oil prices decline, we may be required to record additional non-cash impairment write downs in the future, which would result in a negative impact to our financial position. We annually review our proved oil and gas properties for impairment on a field by field basis. Our review is subject to a large degree of judgment, including the determination of the depletable fields’ estimated reserves, future cash flows and fair value.

Management’s assumptions used in calculating crude oil and natural gas reserves or regarding the future cash flows or fair value of our properties are subject to change in the future. Any change could cause impairment expense to be recorded, impacting our net income or loss and our basis in the related asset. Any change in reserves directly impacts our estimate of future cash flows from the property, as well as the property’s fair value. Additionally, as management’s views related to future prices change, the change will affect the estimate of future net cash flows and the fair value estimates. Changes in either of these amounts will directly impact the calculation of impairment.

Disruptions in the financial and credit markets may adversely impact the availability and cost of credit as well as our ability to raise additional capital, which could adversely affect our business, results of operations and financial condition.

Disruptions in the financial markets, including the bankruptcy or restructuring of certain financial institutions, may adversely impact the availability of credit and cost of credit in the future. Our failure to obtain additional funds, if need be, to meet payment obligations and working capital requirements could have a material adverse effect on our business. In addition, the disruptions in the financial markets may also have an adverse impact on regional economies or the world economy, which could negatively impact the capital and maintenance expenditures of our customers. There can be no assurance that government responses to the disruptions of the financial markets will restore confidence, stabilize markets or increase liquidity and the availability of credit.

We depend on certain key customers for sales of our natural gas and crude oil. To the extent these customers reduce the volumes of natural gas and crude oil they purchase from us, our revenues and cash available for distributions could decline.

A significant portion of our natural gas sales and crude oil are made to three purchasers. While we do have numerous contracts in place which obligate the natural gas purchasers to purchase, and us to sell and deliver, certain quantities of natural gas production through October 2011, there are no commitments beyond the contract periods by the purchasers to continue to purchase our natural gas. To the extent these and other key customers reduce the amount of natural gas and crude oil they purchase from us, our revenues and cash available for distributions to unit holders could temporarily decline in the event we are unable to sell to alternative purchasers.

Many of our leases are in areas that have been partially depleted or drained by offset wells.

Our key project areas are located in active drilling areas in the Appalachian Basin. As a result, many of our leases are in areas that have already been partially depleted or drained by earlier offset drilling. This may inhibit our ability to find economically recoverable quantities of natural gas in these areas.

We face a variety of hazards and risks that could cause substantial financial losses.

Our business involves a variety of operating risks, including:

	•		blowouts, surface cratering and explosions;
	•		mechanical problems;
	•		uncontrolled flows of natural gas, crude oil or well fluids;
	•		fires;
	•		formations with abnormal pressures;
	•		pollution and other environmental risks; and
	•		natural disasters.

Our operation of natural gas gathering and pipeline systems also involves various risks, including the risk of explosions and environmental hazards caused by pipeline leaks and ruptures. The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites, could increase these risks. As part of our normal maintenance program, we have identified certain segments of our pipelines that we believe periodically require repair, replacement or additional maintenance.

In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. We do not carry business interruption insurance. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial position and results of operations.

We have limited control over the activities on properties we do not operate.

Other companies operate some of the properties in which we have an interest. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interest could reduce our production and revenues. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.

Terrorist activities and the potential for military and other actions could adversely affect our business.

The threat of terrorism and the impact of military and other action have caused instability in world financial markets and could lead to increased volatility in prices for natural gas and crude oil, all of which could adversely affect the markets for our operations. Future acts of terrorism could be directed against companies operating in the United States. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations. These developments have subjected our operations to increased risk and, depending on their ultimate magnitude, could have a material adverse effect on our business.

Our ability to sell our natural gas and crude oil production could be materially harmed if we fail to obtain adequate services such as transportation and processing.

The sale of our natural gas and crude oil production depends on a number of factors beyond our control, including the availability and capacity of transportation and processing facilities. Our failure to obtain these services on acceptable terms could materially harm our business.

Competition in our industry is intense, and many of our competitors have substantially greater financial and technological resources than we do, which could adversely affect our competitive position.

Competition in the natural gas and crude oil industry is intense. Major and independent natural gas and crude oil companies actively bid for desirable natural gas and crude oil properties, as well as for the equipment and labor required to operate and develop these properties. Our competitive position is affected by price, contract terms and quality of service, including pipeline connection times, distribution efficiencies and reliable delivery record. Many of our competitors have financial and technological resources and exploration and development budgets that are substantially greater than ours. These companies may be able to pay more for exploratory projects and productive natural gas and crude oil properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry.

The loss of key personnel could adversely affect our ability to operate.

Our operations are dependent upon a relatively small group of key management and technical personnel, and one or more of these individuals could leave our employment. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on us. In addition, our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced professionals. Competition for experienced professionals is extremely intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.

We are subject to complex laws and regulations, including environmental regulations, which can adversely affect the cost, manner or feasibility of doing business.

Our operations are subject to extensive federal, state and local laws and regulations, including tax laws and regulations and those relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. These laws and regulations can adversely affect the cost, manner or feasibility of doing business. Many laws and regulations require permits for the operation of various facilities, and these permits are subject to revocation, modification and renewal. Governmental authorities have the power to enforce compliance with their regulations, and violations could subject us to fines, injunctions or both. These laws and regulations have increased the costs of planning, designing, drilling, installing and operating natural gas and crude oil facilities. In addition, we may be liable for environmental damages caused by previous owners of property we purchase or lease. Risks of substantial costs and liabilities related to environmental compliance issues are inherent in natural gas and crude oil operations. It is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from natural gas and crude oil production, would result in substantial costs and liabilities.

Members of our management team own a significant number of limited partnership Units and are in a position to significantly influence the outcome of matters requiring a Unitholder vote.

Members of our management team beneficially own approximately 17% of our outstanding Units as of March 20, 2010. In addition, these same members control the general partner of the Company with 100% of the ownership. As a result, these Unitholders are in a position to significantly influence the outcome of matters requiring a Unitholder vote, including the election of directors, the adoption of an amendment to the articles of incorporation or bylaws of the managing general partner and the approval of mergers and other significant transactions. The interests of these individuals may differ from those of other Unitholders and their influence may delay or prevent a change of control of the Company and may adversely affect the voting and other rights of other Unitholders.

ITEM 1B.		UNRESOLVED STAFF COMMENTS

None.

ITEM 2.		PROPERTIES

Set forth below is certain information regarding the oil and gas properties of the Company which are located in the Appalachian Basin of Ohio and 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. In December 2008, the SEC approved revisions to its oil and gas reporting disclosures by adopting amendments to Rule 4-10 of Regulation S-X and Items 201, 801, and 802 of Regulation S-K effective for fiscal years ending on or after December 31, 2009. These new disclosure requirements are referred to as “Modernization of Oil and Gas Reporting” and include provisions that:

•

Introduce a new definition of oil and gas producing activities. This new definition allows companies to include in their reserve base volumes from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations;

•

report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end pricing. This should maximize the comparability of reserve estimates among companies and mitigate the distortion of the estimates that arises when using a single pricing date;

•

permit companies to disclose their probable and possible reserves on a voluntary basis. Current rules limit disclosure to only proved reserves;

•

update and revise reserve definitions to reflect changes in the oil and gas industry and new technologies. New updated definitions include “by geographic area” and “reasonable certainty”;

•

permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes; and

•

require additional disclosures regarding the qualifications of the chief technical person who oversees the company’s overall reserve estimation process. Additionally, disclosures are required related to internal controls over reserve estimation, as well as a report addressing the independence and qualifications of a company’s reserves preparer or auditor based on Society of Petroleum Engineers’ criteria.

The Company has complied with these disclosure requirements for the year ended December 31, 2009.

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 (i.e., prices and costs as of the date the estimate is made). 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 our direct ownership interests in crude oil and natural gas properties as well as the reserves attributable to our percentage interests in crude oil and natural gas properties owned through joint ventures. All of the reserves are generally located in the Appalachian Basin region of Ohio and Pennsylvania. For the year ended December 31, 2009, we based our estimates of proved reserves on the 12-month unweighted average price of the first-day-of-the-month price for each calendar month 2009 and then applied any basis adjustments specifically applicable to each oil and gas property based on location and pricing details. For the year ended December 31, 2008, we based our estimate of proved reserves using the natural gas and crude oil prices as of December 31. The natural gas prices used in the estimation of proved reserves were $4.13 and $5.71 at December 31, 2009 and 2008, respectively, and the crude oil prices used in the estimation of proved reserves were $55.13 and $39.00 at December 31, 2009 and 2008, 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 our natural gas and crude oil reserve estimates were completed in accordance with our prescribed internal control procedures, which include verification of input data delivered to our third-party reserve specialist, as well as a multi-functional management review. For the year ended December 31, 2009, we 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 our 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, 2009. The Wright & Company report, including the qualifications of the chief technical person responsible for the report, was prepared in accordance with generally accepted petroleum engineering and evaluation principles and is attached as Exhibit 99.1 to this Annual Report on Form 10-K.

Reserves Reported to Other Agencies. There were no estimates of total, proved net oil or gas reserves filed with or included in reports to any other federal authority or agency during fiscal 2009, 2008 or 2007.

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, 2009.

		Oil (BBLS)				Gas (MCF)
Proved Developed			602,000				31,560,000
Proved Undeveloped			—				—
Total			602,000				31,560,000

Standardized Measure of Discounted Future Net Cash Flows.⁽¹⁾ The following table summarizes, as of December 31, 2009, 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 unescalated 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, 2009 discounted to present value at 10%.

		(Thousands)
Future cash inflows from sales of oil and gas		$	166,184
Future production and development costs			(75,549	)
Future asset retirement obligations, net of salvage			(11,613	)
Future income tax expense			(1,687	)
Future net cash flows			77,335
Effect of discounting future net cash flows at 10% per annum			(27,664	)
Standardized measure of discounted future net cash flows		$	49,671

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 the periods indicated.

										Average
		Production								Sales Price								Average Lifting Cost
		Oil (BBLS)				Gas (MCFS)				per BBL				per MCF				per Equivalent MCF (1)
2009			69,000				2,955,000			$	52.56			$	7.50			$	1.29
2008			76,000				3,530,000				96.80				9.67				1.03
2007			70,000				3,228,000				66.06				9.19				1.05

Productive Wells. The following table sets forth the gross and net oil and gas wells of the Company as of December 31, 2009.

Gross Wells												Net Wells
Oil (1)				Gas (1)				Total				Oil (1)				Gas (1)				Total
	151				1,289				1,440				83				797				880

Acreage. The Company had approximately 61,900 gross developed acres and 39,500 net developed acres as of December 31, 2009. Developed acreage is that acreage assignable to productive wells. The Company had approximately 1,653 gross and net proved undeveloped acres as of December 31, 2009.

Drilling Activity. The following table sets forth the results of drilling activities 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
2009			15				3.40				—				—
2008			91				38.11				—				—
2007			73				28.54				2				0.36

Present Activities. The Company has drilled 7 gross and 5.2 net development wells since December 31, 2009. As of March 20, 2010, the Company had no wells in the process of being drilled.

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 contract wells. The contract wells comprised approximately 66% of the Company’s natural gas sales during 2009. In addition, the Company has entered into various short-term contracts which obligate the purchasers to purchase and the Company to sell and deliver undetermined quantities of natural gas production on a monthly basis throughout the term of the contracts.

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

ITEM 3.		LEGAL PROCEEDINGS

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

ITEM 4.		REMOVED AND RESERVED

PART II

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

Market

There is currently no established public trading market for the Units. At the present time, the Company does not intend to list any of the Units for trading on any exchange or otherwise take any action to establish any market for the Units. As of March 20, 2010, there were 5,621,851 Units held by 1,395 holders of record.

Distribution History

The Company commenced operations with the consummation of the Exchange Offer in February 1991. Management’s stated intention was to make quarterly cash distributions equal to $0.125 per Unit (or $0.50 per Unit on an annualized basis) for the first eight quarters following the closing date of the Exchange Offer. The Company has paid a quarterly distribution every quarter since July 1991. The Company paid total cash distributions of $3.00 per Unit during 2009 and 2008, respectively. Based upon the current number of Units outstanding, the aggregate value of a quarterly distribution of $0.50 per Unit made to our holders of record (“Holders”) would amount to approximately $2,844,000. The Company made a distribution of $0.50 per Unit in January 2010 and currently intends to make a distribution of $0.50 per Unit in April 2010 and additional distributions in July and October 2010.

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 2,442, 18,975, and 826 of its Units of limited partnership interest at a price of $11.07, $16.25, and $12.88 per Unit pursuant to the terms of the Company’s Offers to Purchase dated April 30, 2009, 2008 and 2007, respectively. See Note 4 in the Company’s financial statements for additional information on the Repurchase Right.

ITEM 6.		SELECTED FINANCIAL DATA

The following selected consolidated financial data should be read in conjunction with, and is qualified by reference to, our consolidated financial statements and related notes thereto in Item 8 of this report and Management’s Discussion and Analysis of Financial Condition and Results of Operations included in Item 7 of this report.

		Year Ended December 31,
		2009				2008				2007				2006				2005
Revenue		$	26,398,062			$	42,069,515			$	34,835,438			$	34,847,915			$	33,114,351
Net Income			3,913,369				24,117,868				23,505,248				23,142,714				22,968,275
Net Income Per Unit			0.69				4.23				4.12				4.04				3.99
Total Assets			70,630,631				83,441,393				75,123,907				72,462,307				71,329,497
Debt			—				—				—				—				—
Cash Distributions Per Unit			3.00				3.00				4.00				3.75				2.50

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 that is co-managed by an individual who is a director of EEI, Robert F. Sykes, and owned by the four adult children of Mr. Sykes.

Liquidity and Capital Resources

Financial Position

The following table summarizes the Company’s financial position at December 31, 2009 and December 31, 2008:

		December 31, 2009								December 31, 2008
		Amount				%				Amount				%
		(Amounts in Thousands)								(Amounts in Thousands)
Working capital		$	19,782				29	%		$	18,853				24	%
Property and equipment (net)			47,706				70				59,928				75
Other			474				1				904				1
Total		$	67,962				100	%		$	79,685				100	%
Deferred income taxes		$	320				—	%		$	360				—	%
Long-term liabilities			5,069				8				3,568				5
Partners’ equity			62,573				92				75,757				95
Total		$	67,962				100	%		$	79,685				100	%

Working capital surplus of $19.8 million as of December 31, 2009 represented a $930,000 increase from December 31, 2008 due primarily to an increase in cash and equivalents of $2.2 million and decrease of accrued expenses of $882,000, offset somewhat by a decrease in accounts receivable from crude oil and natural gas production of $2.4 million. Accounts receivable from crude oil and natural gas production decreased $2.4 million primarily due to lower natural gas prices in the fourth quarter of 2009 as compared to natural gas prices in the fourth quarter of 2008, as well as due to lower natural gas volumes produced in the fourth quarter of 2009 as compared to natural gas volumes produced in the fourth quarter of 2008. Accounts receivable from joint venture partners decreased $291,000 due to a decrease in drilling activity throughout 2009. The current portion of employee notes receivable increased $326,000 primarily due to the anticipated settlement of one employee’s full balance in January 2010. Accounts payable decreased $206,000 primarily due to a decrease in drilling costs. Accrued expenses decreased $882,000 primarily due to a decrease in the current portion of asset retirement obligations.

The Company had a revolving credit facility with Bank One, N.A. that expired in 2003, and has had no borrowings since that time. The Company expects to have more than $4 million of cash available to fund the Repurchase Right. As a result, additional financing will likely not be required in the event the Repurchase Right is fully subscribed. In the event that additional financing is necessary to fund the Repurchase Right, the Company would likely enter into a commitment for a new line of credit. We cannot provide any assurance as to the availability of any such line of credit under current market conditions. The Company repurchased 2,442 Units at a price of $11.07 per Unit on June 30, 2009.

Cash Flows from Operating, Investing and Financing Activities

The Company generated almost all of its cash sources from operating activities. During the years ended 2009 and 2008, cash provided by operations was used primarily to fund the development of additional oil and gas properties, repurchase of Units pursuant to the Repurchase Right and distributions to Unitholders.

The following table summarizes the Company’s Statements of Cash Flows for the years ended December 31, 2009 and 2008:

		2009								2008
		Dollars				%				Dollars				%
		(Amounts in Thousands)
Operating Activities:
Net income before adjustments		$	3,913				18	%		$	24,118				63	%
Adjustments			15,331				70				11,645				37
Cash flow from operations before working capital changes			19,244				88				35,763				100
Changes in working capital			2,657				12				(133	)			—
Net cash provided by operating activities			21,901				100				35,630				100
Investing Activities:
Proceeds received from employees’ notes receivables			217				1				250				1
Advances disbursed to employees			(113	)			—				(688	)			(2	)
Proceeds from sale of investments			—				—				6,076				17
Purchase of property and equipment			(2,971	)			(14	)			(15,423	)			(43	)
Proceeds from sale of property and equipment			223				1				4				—
Net cash used by investing activities			(2,644	)			(12	)			(9,781	)			(27	)
Financing Activities:
Distributions			(17,071	)			(78	)			(17,103	)			(48	)
Repurchase and retirement of Units			(27	)			—				(308	)			(1	)
Net cash used by financing activities			(17,098	)			(78	)			(17,411	)			(49	)
Net increase in cash and equivalents		$	2,159				10	%		$	8,438				24	%

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 the twelve months of 2009 and 2008 represented 88% and 100% of total cash sources, respectively. Changes in working capital other than cash and equivalents increased cash by $2.7 million during 2009 and decreased cash by $133,000 during 2008. The primary reason for the increase during 2009 is due to a decrease in accounts receivable from crude oil and natural gas production resulting from lower natural gas prices in the fourth quarter of 2009 as compared to natural gas prices in the fourth quarter of 2008, as well as due to lower natural gas volumes produced in the fourth quarter of 2009 as compared to natural gas volumes produced in the fourth quarter of 2008. The primary reasons for the decrease in 2008 are due to an increase in accounts receivable from joint venture partners resulting from drilling activity and a decrease in accounts payable resulting primarily from a decrease in drilling costs payable.

The Company’s cash flows used by investing activities decreased $7.1 million, or 73%, during 2009 as compared with 2008. The primary reason for the decrease in cash flows used by investing activities in 2009 was due to a decrease in the purchase of property and equipment. This decrease was partially offset by a decrease in proceeds received on sale of investments. The purchase of property and equipment decreased $12.5 million, or 81%, during 2009 as compared with 2008. Proceeds received on sale of investments decreased $6.1 million during 2009 as compared with 2008.

The Company’s cash flows used by financing activities decreased $313,000, or 2%, during 2009 as compared with 2008, which was primarily the result of less payments made on the repurchase of Units in 2009 as compared to 2008.

The Company’s ending cash and equivalents balance of $16.6 million at December 31, 2009, as well as on-going monthly operating cash flows, should be adequate to meet short-term cash requirements. The Company has established a quarterly distribution and management believes the payment of such distributions will continue at least through 2010. The Company has paid a quarterly distribution every quarter since July 1991. The Company made a distribution of $2.8 million ($0.50 per Unit) in January 2010 and currently intends to distribute an additional $2.8 million ($0.50 per Unit) in April 2010 from existing cash and equivalents.

Capital expenditures for the development of oil and gas properties have decreased during 2009 as compared to 2008. The Company drilled or participated in the drilling of 15 drill sites in 2009. The Company’s share of these drill sites amounts to 3.40 net developed properties. The Company’s share of proved gas reserves decreased by 9.6 BCF, or 23%, between December 31, 2008 and December 31, 2009, while proved oil reserves decreased by 91,000 barrels, or 13%, between December 31, 2008 and December 31, 2009. The Company continues to develop primarily natural gas fields, as represented by the discovery of 267,000 MCF of natural gas versus 12,000 barrels of crude oil during 2009. The Standardized Measure of Discounted Future Net Cash Flows of the Company’s reserves decreased by $38.9 million between December 31, 2008 and December 31, 2009. The primary reasons for this decrease were due to sales of crude oil and natural gas and decreases in natural gas and crude oil prices and related downward revisions in quantities of oil and gas reserves between December 31, 2008 and December 31, 2009. Management believes the Company will likely drill or participate in the drilling of 10 to 20 net wells during 2010.

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 2,442, 18,975, and 826 Units during 2009, 2008, and 2007 pursuant to the Repurchase Right at a price of $11.07, $16.25, and $12.88 per Unit, respectively. The Repurchase Right to be conducted in 2010 will result in Unitholders being offered a price of $6.86 per Unit. The Company believes existing cash flows will be sufficient to fund the 2010 offering pursuant to the Repurchase Right if fully subscribed.

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, 2009, 2008 and 2007. 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,
		2009				2008				2007
Revenues:
Oil and gas sales			98	%			99	%			98	%
Well management and operating			2				1				2
Total Revenues			100				100				100
Expenses:
Production costs			16				10				11
Well management and operating			1				1				1
Depreciation, depletion and amortization			34				18				15
Accretion expense			2				—				—
Write down/impairment and abandonment of oil and gas properties			22				9				1
General and administrative expense			10				5				6
Other income			(1	)			(1	)			(2	)
Income tax expense			1				1				1
Total Expenses			85				43				33
Net income			15	%			57	%			67	%

Revenues for the year ended December 31, 2009 decreased $15.7 million, or 37%, compared to the same period in 2008. This decrease was due primarily to decreases in crude oil and natural gas sales during 2009 compared with 2008. Revenues for the year ended December 31, 2008 increased $7.2 million, or 21%, compared to the same period in 2007. This increase was due primarily to increases in crude oil and natural gas sales during 2008 compared with 2007.

Oil and gas sales decreased $15.7 million, or 38%, from 2008 to 2009. This decrease was the result of lower natural gas and crude oil production volumes and lower natural gas and crude oil prices. Lower production volumes were primarily the result of many operated properties being shut-in during the 2009 spring and summer months as compared to 2008 when all operated properties were on-line throughout the entire year. The average price received per MCF of natural gas decreased from $9.67 in 2008 to $7.50 in 2009. The average price received per BBL of crude oil decreased from $96.80 in 2008 to $52.56 per barrel in 2009. The Company’s natural gas production decreased by 575,000 MCF, or 16%, and oil production decreased by 7,000 barrels, or 9%, from 2008 to 2009. Natural gas sales accounted for 86%, 82%, and 87% of total oil and gas sales in 2009, 2008, and 2007, respectively. Oil and gas sales increased $7.2 million, or 21%, from 2007 to 2008. This increase was the result of higher production volumes and higher natural gas and crude oil prices. The average price received per MCF of natural gas increased from $9.19 in 2007 to $9.67 in 2008. The average price received per BBL of crude oil increased from $66.06 in 2007 to $96.80 in 2008. The Company’s natural gas production increased by 302,000 MCF, or 9%, and oil production increased by 6,000 barrels, or 9%, from 2007 to 2008.

Production costs increased $224,000, or 5%, and $304,000, or 8% during 2009 and 2008, respectively. The primary reason for these increases was an increase in the number of producing wells and increases in the costs to operate and manage producing properties.

Depreciation, depletion and amortization increased $1.5 million, or 20%, from 2008 to 2009 and $2.4 million, or 46%, from 2007 to 2008. The primary reason for both increases is the result of lower crude oil and natural gas reserves as of their respective fiscal year-end valuation dates (December 31, 2009 and 2008, respectively) as compared to their most recent valuation dates (December 31, 2008 and 2007, respectively). The decreases in crude oil and natural gas reserves was primarily the result of lower crude oil and natural gas prices used to value reserves at December 31, 2009 and 2008, respectively. The lower prices contributed to reducing the average economic life of the Company’s oil and gas properties as compared to their prior valuation dates. Another significant factor of the increase in depreciation, depletion and amortization is higher finding costs and drilling costs on a per unit of production basis on wells drilled during 2007 and 2008. Finding costs and drilling costs per recoverable MCF on wells drilled during 2007 and 2008 were significantly higher than those from their recent years due to the substantial competition for lease acreage and drilling rigs, higher contract drilling and tubular costs, and disappointing drilling results in western Pennsylvania.

Accretion expense increased $390,000, or 184%, from 2008 to 2009. The primary reason for this increase was due to significant increases in asset retirement obligations at December 31, 2008. Accretion expense remained relatively consistent from 2007 to 2008.

Write down/impairment and abandonment of oil and gas properties increased $2.0 million, or 52%, from 2008 to 2009 and $3.7 million from 2007 to 2008. In recent years, the Company had expanded its drilling and development geographically into western Pennsylvania, an area in which it previously had only minimal activity. The drilling and development in this area was conducted through a joint venture with another oil and gas operator with which the Company had previous experience. During 2007 and 2008, the Company invested more than $15 million in western Pennsylvania through this venture. The results were less than expected and the Company has ceased participation in this venture going forward. The combination of downward revisions to reserves, development costs exceeding estimates, declining crude oil and natural gas prices and disappointing results in this venture have caused the Company to record $5.9 million and $3.9 million of non-cash impairment write downs during 2009 and 2008, respectively.

General and administrative expenses increased $569,000, or 29%, from 2008 to 2009. The primary reasons for this increase are the result of additional accounting and consulting fees incurred relative to the Company’s remediation of material weaknesses in internal control over financial reporting and its ongoing assessment of internal control over financial reporting, as well as higher land and lease acquisition expenses resulting from less overhead reimbursements from joint venture partners due to decreased drilling activities. In 2008, these joint ventures provided for reimbursement to the Company for administrative services incurred during the preparation, drilling and completion of certain oil and gas properties operated by the Company, and such reimbursements were primarily responsible for a decrease in general and administrative expenses from 2007 to 2008 of $47,000, or 2%.

Well management and operating revenues decreased $15,000, or 2% from 2008 to 2009, and increased $40,000, or 7%, from 2007 to 2008. The decrease from 2008 to 2009 was primarily the result of operated properties being shut-in during the 2009 spring and summer months, while they were being operated consistently throughout 2008. The Company decided to shut-in many operated properties during 2009 because natural gas prices were lower than in previous years, whereas all operated properties produced throughout all of 2008 because crude oil and natural gas prices were higher than in previous years. The increase from 2007 to 2008 was primarily the result of operated properties not being shut-in during the summer months of 2008 as they were during 2007. Well management and operating costs increased $29,000, or 11%, from 2008 to 2009 and $20,000, or 9%, from 2007 to 2008. These increases were primarily the result of higher costs incurred to manage and operate the wells.

Net other income amounted to $323,000, $347,000, and $704,000 in 2009, 2008, and 2007, respectively. Net other income is primarily interest income on the Company’s cash balances and investments and gain from sales of property and equipment.

The Company is not a tax paying entity, and the net taxable income or loss, other than the taxable income or loss attributable to EEI, is allocated directly to its respective partners.

Net income decreased $20.2 million, or 84%, from 2008 to 2009. This decrease was primarily the result of a decrease in oil and gas sales and increases in depreciation, depletion and amortization and write down/impairment and abandonment of oil and gas properties. Net income increased $613,000, or 3%, from 2007 to 2008. This increase was primarily the result of an increase in oil and gas sales, although increases in depreciation, depletion and amortization and write down/impairment and abandonment of oil and gas properties reduced the effect of these increased sales. Net income represented 15%, 57%, and 67% of total revenues during the years ended December 31, 2009, 2008, and 2007, respectively.

Application of Critical Accounting Policies

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

Capitalized costs of proved properties, after considering estimated dismantlement and abandonment costs and estimated salvage values, are amortized by the unit-of-production method based upon estimated proved developed reserves. Depletion, depreciation and amortization on proved properties amounted to $9.0 million, $7.5 million, and $5.1 million for the years ended December 31, 2009, 2008, and 2007, respectively.

On sale or retirement of a unit of a proved property (which generally constitutes the amortization base), the cost and related accumulated depreciation, depletion, amortization and write down are eliminated from the property accounts, and the resultant gain or loss is recognized.

The Company evaluates its crude oil and natural gas properties for impairment annually. Generally accepted accounting principles require that long-lived assets (including crude oil and natural gas properties) and certain identifiable intangibles be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Everflow 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 expected to do so in the future.

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

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

The estimated liability is based on historical experience in dismantling, plugging and abandoning wells, estimated remaining lives of those wells based on reserves estimates, estimates of the external cost to dismantle, plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability will likely occur due to: changes in estimates of dismantlement, plugging and abandonment costs; changes in estimated remaining lives of the wells; changes in federal or state regulations regarding dismantlement, plugging and abandonment requirements; and other factors. At December 31, 2008, the Company made significant revisions in estimates of plugging costs, discount rate 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.

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 collectibility of the revenue is reasonably assured. The Company utilizes the sales method to account for gas production volume imbalances. Under this method, revenue is recognized only when gas is produced and sold on the Company’s behalf. The Company had no material gas imbalances at December 31, 2009 or 2008. Other revenue is recognized at the time services are rendered, the Company has a contractual right to such revenue and collection is reasonably assured.

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

Inflation and Changes in 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 20, 2010, $74.50 per barrel was the posted field price in the Appalachian Basin area, the Company’s principal area of operation. Although the Company’s sales are affected by this type of price instability, the impact on the Company is not as dramatic as might be expected since approximately 20% of the Company’s total future cash inflows related to crude oil and natural gas reserves as of December 31, 2009 are comprised of crude oil reserves.

Natural gas prices have also fluctuated more recently. The Company’s average price of natural gas during 2007 amounted to $9.19 per MCF. The Company’s average price of natural gas during 2008 increased $0.48 to $9.67 compared to 2007. The Company’s average price of natural gas during 2009 decreased $2.17 to $7.50 compared to 2008. 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 2010 at $4.82 per MCF. The Company’s natural gas is currently sold under short-term contracts where the price is determined using current NYMEX prices. The Company at times will lock-in a monthly price 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. The Company’s sales are significantly impacted by pricing instability in the natural gas market. One of the consequences of these pricing fluctuations is evident in the Company’s Standardized Measure of Discounted Future Net Cash Flows increasing from $104.7 million at December 31, 2006 to $133.5 million at December 31, 2007, decreasing to $88.6 million at December 31, 2008, and decreasing to $49.7 million at December 31, 2009.

The Company’s Standardized Measure of Discounted Future Net Cash Flows decreased by $38.9 million from December 31, 2008 to December 31, 2009 and by $44.9 million from December 31, 2007 to December 31, 2008. A reconciliation of the Changes in the Standardized Measures 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-27

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

None.

EVERFLOW EASTERN PARTNERS, L. P.

2009 CONSOLIDATED FINANCIAL REPORT

EVERFLOW EASTERN PARTNERS, L. P.

CONTENTS

		Page
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM		F-3
FINANCIAL STATEMENTS
Consolidated balance sheets			F-4 – F-5
Consolidated statements of income			F-6
Consolidated statements of partners’ equity			F-7
Consolidated statements of cash flows			F-8
Notes to consolidated financial statements			F-9 – F-27
Exhibit 14.1
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 99.1

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 as of December 31, 2009 and 2008, and the related consolidated statements of income, partners’ equity, and cash flows for each of the three years in the period ended December 31, 2009. These financial statements are the responsibility of the Company’s management. 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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, 2009 and 2008, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.

/s/ Maloney + Novotny LLC

Cleveland, Ohio
March 29, 2010

EVERFLOW EASTERN PARTNERS, L. P.

CONSOLIDATED BALANCE SHEETS

December 31, 2009 and 2008

		2009				2008
ASSETS
CURRENT ASSETS
Cash and equivalents		$	16,610,772			$	14,451,825
Accounts receivable:
Production			5,143,587				7,568,917
Joint venture partners			62,365				353,039
Employees’ notes receivable			544,909				219,006
Other			88,980				15,980
Total current assets			22,450,613				22,608,767
PROPERTY AND EQUIPMENT
Proved properties (successful efforts accounting method)			169,904,570				167,562,754
Pipeline and support equipment			555,564				555,564
Corporate and other			2,037,170				2,020,829
			172,497,304				170,139,147
Less accumulated depreciation, depletion, amortization and write down			124,791,532				110,210,576
			47,705,772				59,928,571
OTHER ASSETS
Employees’ notes receivable			396,700				826,509
Other			77,546				77,546
			474,246				904,055
		$	70,630,631			$	83,441,393

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

EVERFLOW EASTERN PARTNERS, L. P.

CONSOLIDATED BALANCE SHEETS

December 31, 2009 and 2008

		2009				2008
LIABILITIES AND PARTNERS’ EQUITY
CURRENT LIABILITIES
Accounts payable		$	1,555,798			$	1,761,683
Accrued expenses			1,112,290				1,994,696
Total current liabilities			2,668,088				3,756,379
DEFERRED INCOME TAXES			320,000				360,000
ASSET RETIREMENT OBLIGATIONS			5,069,368				3,567,665
COMMITMENTS AND CONTINGENCIES			—				—
LIMITED PARTNERS’ EQUITY, SUBJECT TO REPURCHASE RIGHT
Authorized — 8,000,000 Units
Issued and outstanding — 5,621,851 and 5,624,293 Units, respectively			61,835,159				74,864,217
GENERAL PARTNER’S EQUITY			738,016				893,132
Total partners’ equity			62,573,175				75,757,349
		$	70,630,631			$	83,441,393

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

EVERFLOW EASTERN PARTNERS, L. P.

CONSOLIDATED STATEMENTS OF INCOME

Years Ended December 31, 2009, 2008 and 2007

		2009				2008				2007
REVENUES
Oil and gas sales		$	25,813,201			$	41,469,978			$	34,275,635
Well management and operating			581,565				596,339				556,061
Other			3,296				3,198				3,742
			26,398,062				42,069,515				34,835,438
DIRECT COST OF REVENUES
Production costs			4,348,866				4,124,563				3,820,544
Well management and operating			283,520				254,811				234,583
Depreciation, depletion and amortization			8,990,492				7,515,445				5,136,780
Accretion expense			603,446				212,800				212,798
Write down/impairment and abandonment of oil and gas properties			5,911,702				3,876,903				223,592
Total direct cost of revenues			20,138,026				15,984,522				9,628,297
GENERAL AND ADMINISTRATIVE EXPENSE			2,527,691				1,958,384				2,005,335
Total cost of revenues			22,665,717				17,942,906				11,633,632
INCOME FROM OPERATIONS			3,732,345				24,126,609				23,201,806
OTHER INCOME
Interest income			99,968				343,705				691,129
Gain on sale of property and equipment			223,076				3,500				13,145
			323,044				347,205				704,274
INCOME BEFORE INCOME TAXES			4,055,389				24,473,814				23,906,080
INCOME TAX EXPENSE (BENEFIT)
Current			182,020				395,946				435,832
Deferred			(40,000	)			(40,000	)			(35,000	)
			142,020				355,946				400,832
NET INCOME		$	3,913,369			$	24,117,868			$	23,505,248
Allocation of Partnership Net Income
Limited Partners		$	3,867,223			$	23,834,006			$	23,229,076
General Partner			46,146				283,862				276,172
		$	3,913,369			$	24,117,868			$	23,505,248
Net income per unit		$	0.69			$	4.23			$	4.12

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

EVERFLOW EASTERN PARTNERS, L. P.

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

Years Ended December 31, 2009, 2008 and 2007

		2009				2008				2007
PARTNERS’ EQUITY — JANUARY 1		$	75,757,349			$	69,050,460			$	68,398,967
Net income			3,913,369				24,117,868				23,505,248
Cash distributions ($3.00 per unit in 2009 and 2008, respectively, and $4.00 per unit in 2007)			(17,070,510	)			(17,102,635	)			(22,843,116	)
Repurchase and retirement of Units			(27,033	)			(308,344	)			(10,639	)
PARTNERS’ EQUITY — DECEMBER 31		$	62,573,175			$	75,757,349			$	69,050,460

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

EVERFLOW EASTERN PARTNERS, L. P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

Years Ended December 31, 2009, 2008 and 2007

		2009				2008				2007
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		$	3,913,369			$	24,117,868			$	23,505,248
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			9,078,764				7,600,061				5,211,169
Accretion expense			603,446				212,800				212,798
Write down/impairment and abandonment of oil and gas properties			5,911,702				3,876,903				223,592
Gain on sale of property and equipment			(223,076	)			(3,500	)			(13,145	)
Investment earnings			—				(1,567	)			(269,335	)
Deferred income taxes			(40,000	)			(40,000	)			(35,000	)
Changes in assets and liabilities:
Accounts receivable			2,716,004				(74,037	)			(8,365	)
Other current assets			(73,000	)			(4,750	)			20,078
Other assets			—				—				5,356
Accounts payable			49,237				(63,268	)			559,516
Accrued expenses			(35,834	)			9,522				132,040
Total adjustments			17,987,243				11,512,164				6,038,704
Net cash provided by operating activities			21,900,612				35,630,032				29,543,952
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds received from employees’ notes receivables			216,590				249,660				76,507
Advances disbursed to employees			(112,684	)			(687,945	)			(526,644	)
Purchase of investments			—				—				(17,512,480	)
Proceeds from sale of investments			—				6,076,000				20,288,000
Purchase of property and equipment			(2,971,104	)			(15,422,548	)			(10,472,558	)
Proceeds from sale of property and equipment			223,076				3,500				46,900
Net cash used by investing activities			(2,644,122	)			(9,781,333	)			(8,100,275	)
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions			(17,070,510	)			(17,102,635	)			(22,843,116	)
Repurchase and retirement of Units			(27,033	)			(308,344	)			(10,639	)
Net cash used by financing activities			(17,097,543	)			(17,410,979	)			(22,853,755	)
NET INCREASE (DECREASE) IN CASH AND EQUIVALENTS			2,158,947				8,437,720				(1,410,078	)
CASH AND EQUIVALENTS — JANUARY 1			14,451,825				6,014,105				7,424,183
CASH AND EQUIVALENTS — DECEMBER 31		$	16,610,772			$	14,451,825			$	6,014,105
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Income taxes		$	239,056			$	450,422			$	382,531

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

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Organization and Summary of Significant Accounting Policies

A.

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 oil and gas properties of Everflow Eastern, Inc. (“EEI”) and subsidiaries and the oil and 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 co-managed 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. In addition, EML has no separate operations or role apart from its role as the Company’s general partner.

B.

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.

C.

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. The Company’s financial statements are based on a number of significant estimates (including oil and gas reserves and their related quantities, future net cash flows and remaining lives of wells) certain of which are utilized in the calculation of depreciation, depletion and amortization, the evaluation of impairment of oil and gas properties, and the measurement of asset retirement obligations.

Such estimates could change in the near term and could significantly impact the Company’s results of operations and financial position.

D.

Accounting Standards Codification — In July 2009, the Company adopted a new accounting standard on “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (the “Codification”). The Codification was approved by the Financial Accounting Standards Board (“FASB”) in June 2009 as the single source of authoritative nongovernmental GAAP. All existing accounting standard documents, such as FASB, American Institute of Certified Public Accountants, Emerging Issues Task Force, and other related accounting

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

D.

Accounting Standards Codification (continued)

literature have been superseded by the Codification. Rules and interpretive releases of the United States Securities and Exchange Commission (“SEC”) under the authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. All other accounting literature is considered non-authoritative. The switch to the Codification has affected the way the Company refers to generally accepted accounting principles in the financial statements and accounting policies, as accounting pronouncements do not have standard references.

E.

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

F.

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.

G.

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 $8,945,089, $7,472,399 and $5,096,584 during 2009, 2008 and 2007, 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.

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

G.

Property and Equipment (continued)

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 oil and 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 oil and gas prices, operating costs, and production are utilized in determining undiscounted future net cash flows. The estimated future production of oil and gas reserves is based upon the Company’s independent reserve engineer’s estimate of proved reserves which includes assumptions regarding field decline rates and future prices and costs. The Company utilized current contracts in place and market information including published futures prices, adjusted for basis differentials, for natural gas in its determination of the fair value of its properties at December 31, 2009. The Company wrote down oil and gas properties by approximately $5,911,700, $3,876,900, and $223,600 during 2009, 2008 and 2007, respectively, to provide for impairment and abandonment on certain of its oil and gas properties.

Additions to proved properties include changes to accounts payable related to property and equipment (see Note 2), and asset retirement obligations (see Note 1.H).

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 $1,407,300 — 39 to 40 years). Depreciation on pipeline and support equipment amounted to $45,403, $43,046, and $40,196 for the years ended December 31, 2009, 2008 and 2007, respectively. Depreciation on other corporate property and equipment, included in general and administrative expense, amounted to $88,272, $84,616, and $74,389 for the years ended December 31, 2009, 2008 and 2007, respectively.

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

H.

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 oil and 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.

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

H.

Asset Retirement Obligations (continued)

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 plugging and abandonment requirements; and other factors. At December 31, 2008, the Company made significant revisions in estimates of plugging costs, discount rate, 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.

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

		2009				2008
Beginning of Period		$	4,767,665			$	2,313,704
Liabilities incurred			51,685				239,245
Liabilities settled			(43,428	)			(4,820	)
Accretion expense			603,446				212,800
Revisions in estimated cash flows			—				2,006,736
End of period		$	5,379,368			$	4,767,665

The current portion of asset retirement obligations of $310,000 and $1,200,000 at December 31, 2009 and 2008, respectively, is included in accrued expenses in the Company’s consolidated balance sheets.

I.

Revenue Recognition — The Company recognizes oil and gas revenues when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred, title and risk of loss have transferred to the purchaser, and collectibility of the revenue is reasonably assured. The Company utilizes the sales method to account for gas production volume imbalances. Under this method, revenue is recognized only when gas is produced and sold on the Company’s behalf. The Company had no material gas imbalances at December 31, 2009, 2008 or 2007.

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

I.

Revenue Recognition (continued)

Other revenue is recognized at the time services are rendered, the Company has a contractual right to such revenue and collection is reasonably assured.

The Company participates (and may act as drilling contractor) with unaffiliated joint venture partners and employees in the drilling, development and operation of jointly owned oil and gas properties. Each owner, including the Company, has an undivided interest in the jointly owned property(ies). Generally, the joint venture partners and employees participate on the same drilling/development cost basis as the Company and, therefore, no revenue, expense or income is recognized on the drilling and development of the properties. 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 7). 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.

J.

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

As referred to in Note 5, EEI accounts for income taxes under generally accepted accounting principles, which require income taxes be provided for all items (as they relate to EEI) in the Consolidated Statements of Income regardless of the period when such items are reported for income tax purposes. Therefore, deferred tax assets and liabilities are recognized for temporary differences between the financial reporting basis and tax basis of certain of EEI’s assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to be recovered or settled. The impact on deferred taxes of changes in tax rates and laws, if any, is reflected in the financial statements in the period of enactment. In some situations, generally accepted accounting principles permit the recognition of expected benefits of utilizing net operating loss and tax credit carryforwards.

As of December 31, 2009, the Company’s income tax years from 2006 and thereafter remain subject to examination by the Internal Revenue Service, as well as various state and local taxing authorities.

K.

Allocation of Income and Per Unit Data — Under the terms of the limited partnership agreement, initially, 99% of revenues and costs were allocated to the unitholders (the limited partners) and 1% of revenues and costs were allocated to the general partner. The allocation changes as unitholders elect to exercise the repurchase right (see Note 4).

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

K.

Allocation of Income and Per Unit Data (continued)

Earnings and distributions per limited partner Unit have been computed based on the weighted average number of Units outstanding during the year for each year presented. Average outstanding Units for earnings and distributions per Unit calculations amount to 5,623,072, 5,633,781, and 5,643,681 in 2009, 2008 and 2007, respectively.

L.

Subsequent Events — Everflow paid a dividend in January 2010 of $0.50 per Unit. The distribution amounted to approximately $2,844,000.

As referred to in Note 7, in January 2010 the Company purchased working interests in well properties owned by an employee of the Company as part of the employee’s settlement of a note due to the Company.

In February 2010, EML entered into an Amended and Restated Agreement of Limited Partnership, which amended the prior Partnership Agreement to authorize the Company to grant options to repurchase certain Units to select officers and employees. No options have been granted as of March 20, 2010.

M.

New Accounting Standards — In December 2008, the SEC unanimously approved amendments to revise and modernize its oil and gas reserves estimation and disclosure requirements. The amendments, among other things:

•

allows the use of new technologies to determine proved reserves;

•

permits the optional disclosure of probable and possible reserves;

•

modifies the prices used to estimate reserves for SEC disclosure purposes to a 12-month average price instead of a period-end price; and

•

requires that if a third party is primarily responsible for preparing or auditing the reserve estimates, the company make disclosures relating to the independence and qualifications of the third party, including filing as an exhibit any report received from the third party.

The Company began complying with the disclosure requirements in our annual report on Form 10-K for the year ending December 31, 2009.

Effective April 1, 2009, the Company adopted a new accounting standard on “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions that are Not Orderly,” which provides additional guidance for estimating fair value in accordance with existing GAAP when the volume and level of activity for the asset or liability have significantly decreased. It also includes guidance on identifying circumstances that indicate a transaction is not orderly. Adoption of this standard did not have a material impact on the Company’s financial statements.

Effective April 1, 2009, the Company adopted a new accounting standard on “Interim Disclosures about Fair Value of Financial Instruments,” which requires disclosures about the fair value of financial instruments on an interim basis in addition to the annual disclosure requirements. Adoption of this standard did not have a material impact on the Company’s financial statements.

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

M.

New Accounting Standards (continued)

Effective upon its issuance in September 2009, the Company adopted an accounting standards update on “Extractive Activities — Oil and Gas”. This accounting standards update represents a technical correction to an existing SEC Observer comment regarding “Accounting for Gas-Balancing Arrangements”. The adoption of this accounting standards update did not have a material impact on the Company’s financial statements.

In January 2010, an accounting standard update was issued on “Oil and Gas Estimations and Disclosures”. This update aligns the current oil and natural gas reserve estimation and disclosure requirements of the Extractive Activities for Oil and Gas with the changes established by the SEC oil and gas reserves estimation and disclosure requirements as amended in December 2008. This update expands the disclosures required for equity method investments and revises the definition of oil and natural gas producing activities to include nontraditional resources in reserves unless not intended to be upgraded into synthetic oil or natural gas producing activities. This update also amends the definition of proved oil and natural gas reserves to require 12-month average pricing in estimating reserves, amends and adds definitions in the master glossary that is used in estimating proved oil and natural gas quantities and provides guidance on geographic area with respect to disclosure of information about significant reserves. It is effective for entities with annual reporting periods ending on or after December 31, 2009. The Company adopted this update on December 31, 2009.

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

N.

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

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 2. Current Liabilities

The Company’s current liabilities consist of the following at December 31:

		2009				2008
Accounts Payable:
Production and related other		$	1,094,026			$	1,088,504
Other			380,832				337,117
Drilling			80,940				336,062
		$	1,555,798			$	1,761,683
Accrued Expenses:
Payroll and retirement contributions		$	663,270			$	617,034
Current portion of asset retirement obligations			310,000				1,200,000
Federal, state and local taxes			139,020				177,662
		$	1,112,290			$	1,994,696

Note 3. Credit Facilities and Long-Term Debt

The Company had a revolving line of credit that expired in 2003, and has had no borrowings since that time. The Company anticipates entering into a commitment for a new line of credit agreement in the event funds are needed for the purpose of funding the annual repurchase right (see Note 4). The new line of credit would be utilized in the event the Company receives tenders pursuant to the repurchase right in excess of cash on hand. The Company would be exposed to market risk from changes in interest rates if it funds its future operations through long-term or short-term borrowings.

Note 4. Partners’ Equity

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

Under the terms of the limited partnership agreement, initially, 99% of revenues and costs are allocated to the unitholders (the limited partners) and 1% of revenues and costs are allocated to the general partner. Such allocation has changed and will change in the future due to unitholders electing to exercise the repurchase right.

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 4. Partners’ Equity (continued)

The partnership agreement provides that Everflow will repurchase for cash up to 10% of the then outstanding Units, to the extent unitholders offer Units to Everflow for repurchase pursuant to the repurchase right. The repurchase right entitles any unitholder, between May 1 and June 30 of each year, to notify Everflow that the unitholder elects to exercise the repurchase right and have Everflow acquire certain or all Units. The price to be paid for any such Units is calculated based upon the audited financial statements of the Company as of December 31 of the year prior to the year in which the repurchase right is to be effective and independently prepared reserve reports. The price per Unit equals 66% of the adjusted book value of the Company allocable to the Units, divided by the number of Units outstanding at the beginning of the year in which the applicable repurchase right is to be effective less all interim cash distributions received by a unitholder. The adjusted book value is calculated by adding partners’ equity, the standardized measure of discounted future net cash flows and the tax effect included in the standardized measure and subtracting from that sum the carrying value of oil and gas properties (net of undeveloped lease costs). If more than 10% of the then outstanding Units are tendered during any period during which the repurchase right is to be effective, the investors’ Units tendered shall be prorated for purposes of calculating the actual number of Units to be acquired during any such period. The price associated with the repurchase right, based upon the December 31, 2009 calculation, is estimated to be $6.86 per Unit, net of the distributions made in January 2010 ($0.50 per Unit) and expected to be made in April 2010 ($0.50 per Unit).

Units repurchased pursuant to the repurchase right, for each of the four years in the period ended December 31, 2009, are as follows:

		Per Unit
		Calculated																				Units
		Price for				Less																Outstanding
		Repurchase				Interim				Net				# of Units								Following
Year		Right				Distributions				Price Paid				Repurchased								Repurchase
2006		$	24.37			$	1.50			$	22.87								30,584				5,644,094
2007		$	14.88			$	2.00			$	12.88								826				5,643,268
2008		$	17.75			$	1.50			$	16.25								18,975				5,624,293
2009		$	12.57			$	1.50			$	11.07								2,442				5,621,851

There were no instruments outstanding at December 31, 2009, 2008 or 2007 that would potentially dilute net income per Unit.

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 5. Provision for Income Taxes

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

		Year Ended December 31,
		2009								2008								2007
		Amount				%				Amount				%				Amount				%
Provision based on the statutory rate (for taxable income up to $10,000,000)		$	1,379,000				34.0			$	8,321,000				34.0			$	8,128,000				34.0
Tax effect of:
Non-taxable status of the Programs and Everflow			(1,211,000	)			(29.9	)			(7,799,000	)			(31.9	)			(7,656,000	)			(32.0	)
Excess statutory depletion			(92,000	)			(2.3	)			(129,000	)			(0.5	)			(110,000	)			(0.5	)
Graduated tax rates, state income tax, tax credits and other — net			66,020				1.6				(37,054	)			(0.2	)			38,832				0.2
Total		$	142,020				3.4			$	355,946				1.4			$	400,832				1.7

As referred to in Note 1, EEI accounts for current and deferred income taxes under the provisions of generally accepted accounting principles. Items giving rise to deferred taxes consist of temporary differences arising from differences in financial reporting and tax reporting methods for EEI’s proved properties. At December 31, 2009 and 2008, these deferred tax items resulted in deferred tax liabilities of $320,000 and $360,000, respectively.

Note 6. Retirement Plan

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 Company matches employees’ contributions to the 401(k) Retirement Savings Plan as annually determined by EMC’s Board of Directors. Additionally, the plan has a profit sharing component which provides for contributions to the plan at the discretion of EMC’s Board of Directors. Amounts contributed to the plan vest immediately. The Company’s total matching and profit sharing contributions to the plan amounted to approximately $225,800, $193,200 and $205,100 for the years ended December 31, 2009, 2008 and 2007, respectively.

Note 7. 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.

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 7. Related Party Transactions (continued)

Employees remain obligated for the entire loan amount regardless of a dry-hole event or otherwise insufficient production. The loans carry no loan forgiveness provisions, and no loans have ever been forgiven. The loans accrue interest at the prime rate, which was 3.25% at December 31, 2009.

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, 2009 and 2008, the Company has extended various loans, evidenced by notes, to three employees, with origination dates ranging from December 2007 to December 2009. There have been no subsequent extensions or modifications to any of these notes since their original date of issuance. Employee notes receivables, including accrued interest, amounted to $941,609 and $1,045,515 at December 31, 2009 and 2008, respectively.

In January 2010, one employee repaid his entire loan balance in full by selling working interests in well properties he owned to the Company for a total purchase price of $270,000 and by paying cash of $141,700. The Company believes the price and other terms and conditions relating to the purchase of such well properties were at least as favorable to the Company as if they had been negotiated on an arm’s-length basis with unrelated third parties.

Note 8. 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.

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 8. Business Segments, Risks and Major Customers (continued)

Gas sales accounted for 86%, 82% and 87% of total oil and gas sales in 2009, 2008 and 2007, respectively. Approximate percentages of total oil and gas sales from significant purchasers for the years ended December 31, 2009, 2008 and 2007, respectively, were as follows:

Customer		2009				2008				2007
Dominion Field Services, Inc. (“Dominion”)			38	%			37	%			41	%
Interstate Gas Supply, Inc. (“IGS”)			19				18				19
Ergon Oil Purchasing, Inc. (“Ergon Oil”)			13				17				12
			70	%			72	%			72	%

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, 2009 and 2008. The Company expects that Dominion, IGS and Ergon Oil will continue to be the only major customers in 2010.

The Company has numerous annual contracts with Dominion, which obligate Dominion to purchase, and the Company to sell and deliver, certain quantities of natural gas production from the Company’s oil and gas properties throughout the contract periods. The Company may elect to lock-in specific volumes of natural gas to be sold in specific months at a mutually agreeable price. The Company has elected to lock-in various monthly quantities of natural gas which total 1.64 BCF through October 2011 at various monthly weighted-average prices ranging from $7.95 to $9.75 per MCF.

The Company also has two annual contracts with IGS, which obligates IGS to purchase, and the Company to sell and deliver, certain quantities of natural gas production from the Company’s oil and gas properties throughout the contract periods. The Company may elect to lock-in specific volumes of natural gas to be sold in specific months at a mutually agreeable price. The Company has elected to lock-in various monthly quantities of natural gas which total .99 BCF through October 2011 at various monthly weighted-average prices ranging from $8.05 to $9.49 per MCF.

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 8. Business Segments, Risks and Major Customers (continued)

A summary of the Company’s locked-in volumes and prices with Dominion and IGS by year follows:

		Dominion								IGS								Total
						Weighted-								Weighted-								Weighted-
Year Ending						Average								Average								Average
December 31:		BCF				Price/MCF				BCF				Price/MCF				BCF				Price/MCF
2010			1.18			$	9.13				0.66			$	8.84				1.84			$	9.03
2011			0.46				8.00				0.33				8.10				0.79				8.04
			1.64			$	8.81				0.99			$	8.59				2.63			$	8.73