Everflow Eastern Partners 10-K 2006 FY Annual report

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

For the Fiscal Year Ended December 31, 2006

OR

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 (State or other jurisdiction of incorporation or organization)	34-1659910 (I.R.S. Employer Identification No.)
585 West Main Street P.O. Box 629 Canfield, Ohio (Address of principal executive offices)	44406 (Zip Code)

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

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

Title of each class Name of each exchange
on which registered

None

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

Units of Limited Partnership Interest

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes 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 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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

(Check one): Large accelerated filer o                    Accelerated filer þ                    Non-accelerated filer o

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 4,377,324 Units of limited partnership interest held by non-affiliates of the Registrant as of March 10, 2007. At June 30, 2006, 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, 2006.

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 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 and development 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

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wholly-owned subsidiary of the Company. EEI is engaged in the business of oil and gas production and maintains a leasehold inventory from which the Company selects prospects for development.

          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 87% of the estimated total future cash inflows related to the Company’s oil and gas reserves as of December 31, 2006 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 354 (net) wells. The Company serves as the operator of approximately 67% of the gross wells and 80% 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. The Company has increased its level of activity in the development of oil and gas properties in recent years. During 2006, 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, 2006, the Company’s current leasehold inventory consists of approximately 38 prospects in various stages of maturity representing approximately 978 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

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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 has acquired a limited amount of producing oil and gas properties over the past few years, although there were no acquisitions during 2006.

          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 will consist primarily of borrowings from commercial banks. The Company and EEI had no borrowings during 2006 and no principal indebtedness was outstanding as of March 10, 2007. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Liquidity and Capital Resources.”

          Although the Company’s Agreement of Limited Partnership dated as of September 14, 1990 (the “Partnership Agreement”) does not contain any specific restrictions on borrowings, the Company has no specific plans to borrow for the acquisition of producing oil and gas properties. The Company expects that borrowings may be necessary to enable it to repurchase any Units tendered in connection with the Repurchase Right (as defined under Item 5Registrant’s Common Equity and Related Stockholder Matters). See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Liquidity and Capital Resources.”

          The Company owns a significant number of oil and gas reserves. The Company generally does not expect to borrow funds, from whatever source, in excess of 40% of its total Proved 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 borrow in excess of this amount. The Company has estimated Proved and Proved Developed Reserves,

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determined as of December 31, 2006, which aggregate $104,715,000 (Standardized Measure of Discounted Future Net Cash Flows) with no borrowings outstanding as of December 31, 2006.

          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.

          Oil. Any 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 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 2006.

          The price of oil in the Appalachian Basin has ranged from a low of $8.50 per barrel in December 1998 to a high of $73.00 in July 2006. As of March 10, 2007, the posted field price in the Appalachian Basin area, the Company’s principal area of operation, was $56.25 per barrel of oil. There can be no assurance that prices will not be subject to continual fluctuations. Future 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 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 2006, shortages in natural gas supplies have again resulted from increased energy consumption due to harsh weather conditions. 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

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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 (the “Contract 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 (“GCR”) rates.

          Since 2002, the Company has numerous contracts, 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. A summary of significant gas purchase contracts, including weighted average pricing provisions, with Dominion follows:

	Jan		Feb		Mar		Apr		May		Jun
	2007		2007		2007		2007		2007		2007
MCF		130,000		130,000		130,000		100,000		100,000		150,000
Price	$	9.93	$	9.93	$	9.93	$	9.74	$	9.74	$	9.55

	Jul		Aug		Sep		Oct		Nov		Dec
	2007		2007		2007		2007		2007		2007
MCF		100,000		100,000		100,000		100,000		140,000		120,000
Price	$	9.74	$	9.74	$	9.74	$	9.74	$	9.80	$	9.86

	Jan		Feb		Mar		Apr		May		Jun
	2008		2008		2008		2008		2008		2008
MCF		120,000		120,000		120,000		90,000		90,000		90,000
Price	$	9.86	$	9.86	$	9.86	$	9.16	$	9.16	$	9.16

	Jul		Aug		Sep		Oct
	2008		2008		2008		2008
MCF		90,000		90,000		90,000		90,000
Price	$	9.16	$	9.16	$	9.16	$	9.16

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          The Company also has two annual contracts with Interstate Gas Supply, Inc. (“IGS”), which obligates IGS to purchase, and the Company to sell and deliver certain quantities of natural gas production from the Company’s oil and gas properties throughout the contract periods. A summary of the significant gas purchase contract, including weighted average pricing provisions, with IGS follows:

	Jan		Feb		Mar		Apr		May		Jun
	2007		2007		2007		2007		2007		2007
MCF		70,000		70,000		70,000		50,000		50,000		90,000
Price	$	10.40	$	10.40	$	10.40	$	9.38	$	9.38	$	9.32

	Jul		Aug		Sep		Oct		Nov		Dec
	2007		2007		2007		2007		2007		2007
MCF		50,000		50,000		50,000		50,000		80,000		60,000
Price	$	9.38	$	9.38	$	9.38	$	9.38	$	9.55	$	9.46

	Jan		Feb		Mar		Apr		May		Jun
	2008		2008		2008		2008		2008		2008
MCF		60,000		60,000		60,000		40,000		40,000		40,000
Price	$	9.46	$	9.46	$	9.46	$	9.12	$	9.12	$	9.12

	Jul		Aug		Sep		Oct
	2008		2008		2008		2008
MCF		40,000		40,000		40,000		40,000
Price	$	9.12	$	9.12	$	9.12	$	9.12

          As detailed above, the price paid for natural gas purchased by Dominion and IGS varies based on quantities committed 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 derivations, but have been designated as annual sales contracts under SFAS No. 133. As of December 31, 2006, natural gas purchased by Dominion covers production from approximately 490 gross wells, while natural gas purchased by IGS covers production from approximately 225 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, 2006, with the exception of Dominion and IGS, which accounted for approximately 45% and 20%, 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 2007.

Seasonality

          During summer months, seasonal restrictions on natural gas production have occurred as a result of distribution system restrictions. These production restrictions, and the

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nature of the Company’s business, result in seasonal fluctuations in the Company’s revenue, with the Company 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 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. Decreases in worldwide energy production capability and increases in energy consumption have brought about a shortage in energy supplies recently. 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

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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 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 (“NGA”). The wellhead price of natural gas is also regulated by 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, FERC recently 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 as discussed earlier.

          As a result of the NGPA and the Decontrol Act, the Company’s gas production is no longer subject to price regulation. 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. 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,

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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. The impact of these rules and other regulatory developments on the Company cannot be predicted.

          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.

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 and for up to $50,000,000 plus response costs under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (“Superfund”) 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.

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

Operating Hazards and Uninsured Risks

          The Company’s oil and gas operations are subject to all operating hazards and risks normally incident to drilling for and producing oil and 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

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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 also 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 10, 2007, the Company had seventeen full-time and three part-time employees. These employees primarily are engaged in the following areas of business operations: four in land and lease acquisition, five in field operations, six in accounting, and five 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

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(“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.

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;

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• actions of governmental authorities;

• pipeline capacity constraints;

• inventory storage levels;

• 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.

We have identified numerous material weaknesses in our internal control over financial reporting.

          Section 404 under the Sarbanes-Oxley Act of 2002 requires that we perform an assessment of our internal controls over financial reporting, and engage our independent registered public accounting firm to perform an audit of our internal control over financial reporting. We were required to complete the assessment as to the adequacy of our internal control reporting as of December 31, 2006.

          During the preparation of our financial statements for the fiscal year ended December 31, 2005, we identified a number of control deficiencies in our internal control over financial reporting. A number of these control deficiencies have been classified as material weaknesses or significant deficiencies that in the aggregate constitute material weaknesses. A material weakness is a control deficiency that results in there being more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis by employees in the normal course of their assigned functions. Based on the material weaknesses identified, management concluded that our internal control over financial reporting was not effective as of December 31, 2006.

          As of the end of the period covered in this Form 10-K, management performed an evaluation of the effectiveness of our disclosure controls and procedures. Our disclosure controls and procedures are designed to ensure that information required to be disclosed in our periodic reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management to allow timely decisions regarding disclosures. Based on the evaluation and the identification of the material weaknesses in internal control over financial reporting described above, management concluded that our disclosure controls and procedures were not effective as of December 31 2006.

          As of the filing of this Form 10-K, we have implemented changes in our internal control over financial reporting to remediate certain but not all of the identified control deficiencies. Our continuing remediation efforts are subject to our internal control assessment,

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testing and evaluation processes. While these efforts continue, we will rely on additional substantive procedures and other measures as needed to assist us with meeting the objectives otherwise fulfilled by an effective control environment. As a result, we expect that once we commence our preparation and review of 2007 interim financial statements, our internal control over financial reporting will not be effective as of March 31, 2007, June 30, 2007 and September 30, 2007, respectively. There can be no assurance that our internal control over financial reporting or our disclosure controls and procedures will prevent future error or fraud in connection with our financial statements. See “Item 9A. Controls and Procedures” for additional information.

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.

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          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 oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on prices 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 the Financial Accounting Standards Board in Statement of Financial Accounting Standards No. 69 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.

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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 depletable unit basis. To determine if a depletable unit is impaired, we compare the carrying value of the depletable unit to the undiscounted future net cash flows by applying estimates of future oil and gas prices to the estimated future production of oil and gas reserves over the economic life of the property. Future net cash flows are based upon our independent reservoir engineers’ estimates of proved reserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions. For each property determined to be impaired, we recognize an impairment loss equal to the difference between the estimated fair value and the carrying value of the property on a depletable unit basis. Fair value is estimated to be the present value of the aforementioned expected future net cash flows. Any impairment charge incurred is recorded in accumulated depreciation, depletion, impairment and amortization to reduce our recorded basis in the asset. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units’ estimated reserves, future cash flows and fair value.

          Management’s assumptions used in calculating oil and 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.

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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

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gas and 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,

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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 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 partnership units, giving them influence or control, and the interests of these individuals could differ from those of other unitholders.

          Members of our management team beneficially own approximately 22% of our outstanding units as of March 10, 2007. 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 or control 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. Their control of the Company 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.

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          Proved Reserves.⁽¹⁾ The following table reflects the estimates of the Company’s Proved Reserves which are based on the Company’s report as of December 31, 2006.

	Oil (BBLS)		Gas (MCF)
Proved Developed		718,000		43,006,000
Proved Undeveloped		—		—
Total		718,000		43,006,000

⁽¹⁾ The Company has not determined proved reserves associated with its proved undeveloped acreage which are not deemed significant at December 31, 2006. A reconciliation of the Company’s proved reserves is included in the Notes to the Financial Statements.

          Standardized Measure of Discounted Future Net Cash Flows.⁽¹⁾ The following table summarizes, as of December 31, 2006, 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 Securities and Exchange Commission, using calculations based solely on Proved Reserves, current unescalated cost and price factors, and discounted to present value at 10%.

	(Thousands)
Future cash inflows from sales of oil and gas	$	313,397
Future production and development costs		107,322
Future asset retirement obligations, net of salvage		9,220
Future income tax expense		4,294
Future net cash flows		192,561
Effect of discounting future net cash flows at 10% per annum		87,846
Standardized measure of discounted future net cash flows	$	104,715

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

          Production. The following table summarizes the net oil and 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 (MCF)		per BBL		per MCF		per Equivalent MCF(1)
2006		72,000		3,500,000	$	62.60	$	8.51	$	.96
2005		72,000		3,878,000		52.40		7.42		.83
2004		72,000		3,932,000		37.98		5.68		.69

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

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          Productive Wells. The following table sets forth the gross and net oil and gas wells of the Company as of December 31, 2006.

Gross Wells					Net Wells
Oil(1)	Gas(1)		Total		Oil(1)		Gas(1)		Total
84		1,170		1,254		55		762		817

⁽¹⁾ Oil wells are those wells which generate the majority of their revenues from oil production; gas wells are those wells which generate the majority of their revenues from gas production.

          Acreage. The Company had approximately 53,000 gross developed acres and 36,000 net developed acres as of December 31, 2006. Developed acreage is that acreage assignable to productive wells. The Company had approximately 978 gross and net proved undeveloped acres as of December 31, 2006.

          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
2006		36		11.44		1		.20
2005		54		18.16		2		.46
2004		75		33.20		2		.70

⁽¹⁾ All wells are located in the United States. All wells are development wells; no exploratory wells were drilled.

          Present Activities. The Company has drilled 8 gross and 2.98 net development wells since December 31, 2006. As of March 10, 2007, the Company had no gross or net wells in the process of being drilled.

          Delivery Commitments. The Company 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 comprise approximately 65% of the Company’s natural gas sales. In addition, the Company has entered into various short-term contracts which obligate the purchasers to

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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 5,400 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. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

          During the fourth quarter of the fiscal year ended December 31, 2006, there were no matters submitted to a vote of security holders through the solicitation of proxies or otherwise.

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PART II

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

Market

          There is currently no established public trading market for the Units. At the present time, the Company does not intend to list any of the Units for trading on any exchange or otherwise take any action to establish any market for the Units. As of March 10, 2007, there were 5,644,094 Units held by 1,392 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 $2.50 and $3.75 per Unit during 2005 and 2006, respectively. Based upon the current number of Units outstanding, each quarterly distribution of $0.125 per Unit would be approximately $714,000. The Company made a quarterly distribution of $1.00 per Unit in January 2007 and currently intends to make a quarterly distribution of $1.00 per Unit in April 2007 and quarterly distributions of at least $0.125 per Unit in July and October 2007.

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 Unitholders offer Units to the Company for repurchase (the “Repurchase Right”). The Repurchase Right entitles any Unitholder, between May 1 and June 30 of each year, to notify the Company that the Unitholder 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 23,865, 16,196 and 30,584 of its Units of limited partnership interest at a price of $12.44, $14.46 and $22.87 per Unit pursuant to the terms of the Company’s Offers to Purchase dated April 30, 2004, 2005 and 2006, respectively. See Note 3 in the Company’s financial statement for additional information on the Repurchase Right.

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ITEM 6.SELECTED FINANCIAL DATA

          The following selected consolidated financial data should be read in conjunction with, and are 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,
	2006		2005		2004		2003(1)		2002
Revenue	$	34,847,915	$	33,114,351	$	25,670,760	$	21,834,446	$	16,757,418
Net Income		23,142,714		22,968,275		16,403,297		11,951,300		8,004,090
Net Income Per Unit		4.04		3.99		2.84		2.06		1.37
Total Assets		72,562,307		71,329,497		61,481,489		58,136,578		52,579,304
Debt		—		—		—		—		—
Cash Distributions Per Unit		3.75		2.50		2.25		1.25		1.25

⁽¹⁾ See Note 1G to the 2003 consolidated financial statements. The cumulative effect of change in accounting principle was $471,545.

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 currently directors and/or officers of EEI, Thomas L. Korner and William A. Siskovic, and Sykes Associates, LLC, a New York limited liability company owned by the four adult children of Robert F. Sykes, the Chairman of the Board of EEI.

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Liquidity and Capital Resources

Financial Position

          Working capital surplus of $22.1 million as of December 31, 2006 represented a $2.7 million increase from December 31, 2005 due primarily to an increase in commercial paper investments of $8.6 million. Cash and equivalents decreased $5.9 million during 2006. Accounts receivable from oil and gas production decreased $335,000 due primarily to a decrease in production volumes included in the accounts receivable balance at December 31, 2006 compared to December 31, 2005. Accounts receivable from employees increased $36,000 and accounts receivable from joint venture partners decreased $7,000. Accounts payable decreased $695,000 due to lower production revenues payable and accrued expenses increased $424,000 due to higher accrued payroll costs and increases in the current portion of Asset Retirement Obligations and accrued federal income taxes.

          The Company had a revolving credit facility with Bank One, N.A. that expired in 2003. The Company had no borrowings in 2005 or 2006. 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. The Company expects to have more than $10 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. Cash flows were used to pay for the funding of the Company’s purchase of investments, the continued development of oil and gas properties and to repurchase Units pursuant to the Repurchase Right. The Company repurchased 30,584 Units at a price of $22.87 per Unit on June 30, 2006. The Company also used cash flows to make cash distributions, which totaled 21.5 million in 2006.

          The following table summarizes the Company’s financial position at December 31, 2006 and December 31, 2005:

	December 31, 2006					December 31, 2005
	Amount		%			Amount		%
	(Amounts in Thousands)					(Amounts in Thousands)
Working capital	$	22,048		31	%	$	19,459		28	%
Property and equipment (net)		48,347		69			49,503		72
Other		183		—			111		—
Total	$	70,588		100	%	$	69,073		100	%
Deferred income taxes	$	435		1	%	$	—		—	%
Long-term liabilities		1,744		2			1,655		2
Partners’ equity		68,399		97			67,418		98
Total	$	70,588		100	%	$	69,073		100	%

Cash Flows from Operating, Investing and Financing Activities

          The Company generated almost all of its cash sources from operating activities. During the years ended 2006 and 2005, cash provided by operations was used to fund the

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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, 2006 and 2005:

	2006						2005
	Dollars			%			Dollars			%
	(Amounts in Thousands)
Operating Activities:
Net income before adjustments	$	23,143			65	%	$	22,968			82	%
Adjustments		6,330			18			5,075			18
Cash flow from operations before working capital changes		29,473			83			28,043			100
Changes in working capital		(171	)		—			(1,614	)		(6	)
Net cash provided by operating activities		29,302			83			26,429			94
Investing Activities:
Proceeds received on receivables from employees		53			—			41			—
Advances disbursed to employees		(89	)		—			(124	)		—
Purchase of investments		(8,581	)		(24	)		—			—
Purchase of property and equipment		(4,471	)		(13	)		(6,401	)		(23	)
Proceeds on disposal of property and equipment		—			—			11			—
Net cash used by investing activities		(13,088	)		(37	)		(6,473	)		(23	)
Financing Activities:
Distributions		(21,463	)		(61	)		(14,371	)		(51	)
Repurchase and retirement of Units		(699	)		(2	)		(234	)		(1	)
Net cash used by financing activities		(22,162	)		(63	)		(14,605	)		(52	)
Net (decrease) increase in cash and equivalents	$	(5,948	)		17		$	5,351			19

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

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          As the above table indicates, the Company’s cash flow from operations before working capital changes during the twelve months of 2006 and 2005 represented 84% and 100% of total cash sources, respectively. Changes in working capital other than cash and equivalents decreased cash by $171,000 during 2006 and decreased cash by $1.6 million during 2005. The primary reason for the decrease during 2006 is due to a decrease in accounts payable at December 31, 2006 resulting from decreases in natural gas prices and production volumes. The decrease during 2005 was primarily due to the increase in accounts receivable at December 31, 2005 resulting from increases in natural gas and crude oil prices.

          The Company’s cash flows used by investing activities increased $6.6 million, or 102%, during 2006 as compared with 2005. The Company’s cash flows used by investing activities decreased $1.5 million, or 19%, during 2005 as compared with 2004. The primary reason for these changes in cash flows used by investing activities in 2006 and 2005 was due to changes in the purchase of investments and the purchase of property and equipment. The purchase of investments increased $8.6 million during 2006 as compared with 2005 when there was no purchase of investments. The purchase of property and equipment decreased $1.9 million, or 30%, during 2006 as compared with 2005. The purchase of property and equipment decreased $1.6 million, or 20%, during 2005 as compared with 2004.

          The Company’s cash flows used by financing activities increased $7.6 million, or 52%, during 2006 as compared with 2005. The reasons for this increase were that distributions to Unitholders increased $7.1 million and payments on the repurchase of Units increased $465,000 during 2006. The Company’s cash flows used by financing activities increased $1.3 million, or 10%, during 2005 as compared with 2004. The reasons for this increase were that distributions to Unitholders increased $1.4 million although payments on the repurchase of Units decreased $63,000 during 2005.

          The Company’s ending cash and equivalents balance of $7.4 million at December 31, 2006, as well as $8.6 million in investments and 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 2007. The Company has paid a quarterly distribution every quarter since July 1991. Minimum cash distributions are estimated to be $714,000 per quarter ($.125 per Unit). The Company intends to distribute $5.7 million ($1.00 per Unit) in April 2007 from existing cash and equivalents.

          Capital expenditures for the development of oil and gas properties and the acquisition of undeveloped leasehold acreage have decreased during 2006 compared to 2005. The Company drilled or participated in the drilling of an additional 37 drillsites in 2006. The Company’s share of these drillsites amounts to 11.64 net developed properties. The Company’s share of proved gas reserves decreased by 8.0 BCF, or 16%, between December 31, 2005 and December 31, 2006, while proved oil reserves decreased by 85,000 barrels, or 11%, between December 31, 2005 and December 31, 2006. The Company continues to develop primarily natural gas fields, as represented by the discovery and addition of 808,000 MCF of natural gas versus 1,000 barrels of crude oil during 2006. The Standardized Measure of Discounted Future Net Cash Flows of the Company’s reserves decreased by $83.5 million between December 31, 2005 and December 31, 2006. The primary reasons for this decrease were due to decreases in natural gas prices and related downward revisions in quantities of oil and gas reserves between

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December 31, 2005 and December 31, 2006. Management believes the Company should be able to drill or participate in the drilling of 15 to 20 net wells each year for the next few years.

          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 30,584, 16,196 and 23,865 Units during 2006, 2005 and 2004 pursuant to the Repurchase Right at a price of $22.87, $14.46 and $12.44 per Unit, respectively. The Repurchase Right to be conducted in 2007 will result in Unitholders being offered a price of $12.88 per Unit. The Company believes existing cash flows, including borrowing if necessary (although the Company currently has no credit facility), will be sufficient to fund the 2007 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, 2006, 2005 and 2004. 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:

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	Year Ended December 31,
	2006			2005			2004
Revenues:
Oil and gas sales		98	%		98	%		98	%
Well management and operating		2			2			2
Total Revenues		100			100			100
Expenses:
Production costs		11			11			12
Well management and operating		—			1			1
Depreciation, depletion and amortization		16			15			18
Accretion expense		1			—			—
Abandonment of oil and gas properties		—			—			—
General and administrative		6			5			6
Other expense (income)		(2	)		(1	)		(1	)
Income taxes		2			—			—
Total Expenses		34			31			36
Net income		66	%		69	%		64	%

          Revenues for the year ended December 31, 2006 increased $1.7 million, or 5%, compared to the same period in 2005. Revenues for the year ended December 31, 2005 increased $7.4 million, or 29%, compared to the same period in 2004. These changes were due primarily to increases in crude oil and natural gas sales between the periods involved.

          Oil and gas sales increased $1.7 million, or 5%, from 2005 to 2006. This increase was the result of higher natural gas and crude oil prices. The average price received per MCF of natural gas increased from $7.42 to $8.51 from 2005 to 2006. Oil sales were higher due primarily to an increase in the average sales price from $52.40 to $62.60 per barrel from 2005 to 2006. The Company’s gas production decreased by 378,000 MCF and oil production remained consistent with the prior year level. Gas sales accounted for 87%, 88% and 89% of total oil and gas sales in 2006, 2005 and 2004, respectively. Oil and gas sales increased $7.4 million, or 30%, from 2004 to 2005. The primary reason for this increase in oil and gas sales between 2004 and 2005 was due to an increase in oil and gas prices. The Company’s gas production decreased by 54,000 MCF and oil production remained consistent with the prior year level. The average price received per MCF increased from $5.68 to $7.42. The average price received per barrel increased from $37.98 to $52.40.

          Production costs increased $197,000, or 6%, and $567,000, or 19%, during 2006 and 2005, respectively. The primary reason for these increases was an increase in the number of producing wells and inflationary increases in the costs to operate and manage producing properties. Depreciation, depletion and amortization increased $668,000, or 14%, from 2005 to 2006. The primary reason for this increase is due to the decrease in oil and gas reserves resulting from lower natural gas pricing for estimated future production. Depreciation, depletion and amortization increased $246,000, or 5%, from 2004 to 2005. The primary reason for this increase was the result of higher production on oil and gas properties drilled over the past few years. These more recent properties have higher carrying values than older properties and higher depletion rates. Accretion expense increased $106,000 or 80%, from 2005 to 2006. Accretion expense increased $32,000, or 33%, from 2004 to 2005. Accretion will typically increase each

-28-

year due to the Company reporting of the current value of asset retirement obligations. Present value measurement is used to report the asset retirement obligations. So, as time passes and asset retirement dates approach, the present value of the expected future cash flows will increase along with the reported amount of the asset retirement obligations.

          Well management and operating revenues increased $5,000, or 1%, from 2005 to 2006. Well management and operating costs decreased $18,000, or 8%, from 2005 to 2006. Well management and operating revenues decreased $5,000, or 1%, from 2004 to 2005. Well management and operating costs increased $42,000, or 23%, from 2004 to 2005. The reason for the small increase in well management and operating revenues between 2005 and 2006 was due to an increase in rates charged as operating fees on Company operated properties, although a number of operated properties were shut-in during summer months in anticipation of higher prices in the fall and winter. Operating costs, on the other hand, decreased in 2006 as a result of the Company choosing to shut-in a number of properties during the summer months. Operating revenues and costs would have both been higher had these shut-ins not occurred during 2006.

          Abandonments of oil and gas properties decreased $19,000 from 2005 to 2006 and increased $58,000 from 2004 to 2005. These changes were attributable to abandonments of oil and gas properties, including dry hole costs.

          General and administrative expenses increased $489,000, or 32%, from 2005 to 2006, and $59,000, or 4%, from 2004 to 2005. General and administrative expenses increased in 2005 and 2006 as a result of increasing ongoing expenses of administering the Company. Legal and audit fees have increased along with salaries, employee benefits and related administrative overhead. In particular, administrative overhead in the Company’s land and lease acquisition department increased as a result of the Company’s efforts to increase its undeveloped lease inventory over recent years.

          Net other income amounted to $691,000, $276,000 and $105,000 in 2006, 2005 and 2004, respectively. Net other income is primarily interest earnings on the Company’s cash balances and investments.

          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 increased $174,000, or 1%, from 2005 to 2006. Net income increased $6.6 million, or 40%, from 2004 to 2005. The increases were primarily the result of increases in oil and gas sales. Net income represented 66%, 69% and 64% of total revenues during the years ended December 31, 2006, 2005 and 2004, 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.

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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 $5.4 million, $4.7 million and $4.5 million for the years ended December 31, 2006, 2005 and 2004, 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 oil and gas properties for impairment annually. SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” requires 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. 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 oil and gas property impairment is a “critical accounting estimate” because it is highly susceptible to change from year to year. It requires the use of oil and gas reserve estimates that are directly impacted by future oil and gas prices and future production volumes. Actual oil and gas prices have fluctuated in the past and are expected to do so in the future.

          Oil and 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 oil and gas properties. In contrast, decreases in estimated future cash flows could require the recognition of an impairment loss equal to the difference between the fair value of the oil and gas properties (determined by calculating the discounted value of the estimated future cash flows) and the carrying amount of the oil and 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 SFAS No. 143 which requires 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.

          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

          

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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, 2005, the Company made revisions in estimates of plugging costs, discount rate, inflation 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 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, income is recorded based on the Company’s net revenue interest in production taken for delivery. The Company had no material gas imbalances at December 31, 2006 and 2005. 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 receivable from joint venture partners and employees consist principally of drilling and development costs the Company has advanced or incurred on behalf of joint venture partners and employees (see Note 6). Accounts payable to joint venture partners consist principally of drilling and development advances the Company has received on behalf of joint venture partners. 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, oil and gas prices have fluctuated in recent years and generally have not matched inflation. The price of oil in the Appalachian Basin has ranged from a low of $8.50 per barrel in December 1998 to a high of $73.00 in July 2006. As of March 10, 2007, the posted field price in the Appalachian Basin area, the Company’s principal area of operation, was $56.25 per barrel of oil. 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 less than 10% of the Company’s total future cash inflows related to oil and gas reserves as of December 31, 2006 are comprised of oil reserves.

          Natural gas prices have also fluctuated more recently. The Company’s average price of gas during 2004 amounted to $5.68 per MCF. The Company’s average price of gas during 2005 increased $1.74 to $7.42 compared to 2004. The Company’s average price of gas during 2006 increased $1.09 to $8.51 compared to 2005. The price of gas in the Appalachian

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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 February 2007 at $7.30 per MCF. The Company’s 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 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 $101.8 million at December 31, 2003 to $119.1 million at December 31, 2004 and $188.3 million at December 31, 2005, and decreasing to $104.70 million at December 31, 2006.

          The Company’s Standardized Measure of Discounted Future Net Cash Flows decreased by $83.5 million from December 31, 2005 to December 31, 2006 and increased by $69.2 million from December 31, 2004 to December 31, 2005. 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

          The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market-risk exposure. All of our market-risk sensitive instruments were entered into for purposes other than trading. All accounts are U.S. dollar denominated.

          There were no borrowings during 2006 and 2005. 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.

          The Company is exposed to market risk from changes in commodity prices. Realized pricing is primarily driven by the prevailing worldwide prices for crude oil and spot market prices applicable to United States natural gas production. Pricing for gas and oil production has been volatile and unpredictable for many years. These market risks can impact the Company’s results of operations, cash flows and financial position. The Company’s primary commodity price risk exposure results from contractual delivery commitments with respect to the Company’s gas purchase contracts. The Company periodically makes commitments to sell certain quantities of natural gas to be delivered in future months at certain contract prices. This affords the Company the opportunity to “lock in” the sale price for those quantities of natural gas. Failure to meet these delivery commitments would result in the Company being forced to purchase any short fall at current market prices. The Company’s risk management objective is to lock in a range of pricing for no more than 80% to 90% of expected production volumes. This allows the Company to forecast future cash flows and earnings within a predictable range.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

          See attached pages F-1 to F-25.

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EVERFLOW EASTERN PARTNERS, L. P.

2006 CONSOLIDATED FINANCIAL REPORT

F-1

EVERFLOW EASTERN PARTNERS, L. P.

CONTENTS

	Page
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM	F-3
FINANCIAL STATEMENTS
Consolidated balance sheets	F-4 - F-5
Consolidated statements of income	F-6
Consolidated statements of partners’ equity	F-7
Consolidated statements of cash flows	F-8
Notes to consolidated financial statements	F-9 - F-25

F-2

Report of Independent Registered Public Accounting Firm

To the Partners
Everflow Eastern Partners, L. P.
Canfield, Ohio

     We have audited the accompanying consolidated balance sheets of Everflow Eastern Partners, L. P. and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of income, partners’ equity, and cash flows for each of the three years in the period ended December 31, 2006. 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, 2006 and 2005, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

     We were engaged to audit, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, and our report dated March 16, 2007 disclaimed an opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting because of a scope limitation and expressed an adverse opinion on the effectiveness of the Company’s internal control over financial reporting because of material weaknesses identified and the effects of a scope limitation.

/s/ Hausser + Taylor LLC

Cleveland, Ohio
March 16, 2007

F-3

EVERFLOW EASTERN PARTNERS, L. P.

CONSOLIDATED BALANCE SHEETS

December 31, 2006 and 2005

	2006		2005
ASSETS
CURRENT ASSETS
Cash and equivalents	$	7,424,183	$	13,371,923
Investments		8,580,618		—
Accounts receivable:
Production		7,833,519		8,168,703
Employees		157,093		120,801
Joint venture partners		6,035		13,531
Other		31,308		40,400
Total current assets		24,032,756		21,715,358
PROPERTY AND EQUIPMENT
Proved properties (successful efforts accounting method)		140,443,938		136,388,136
Pipeline and support equipment		528,193		532,229
Corporate and other		1,776,217		1,817,384
		142,748,348		138,737,749
Less accumulated depreciation, depletion, amortization and write down		94,401,699		89,235,011
		48,346,649		49,502,738
OTHER ASSETS		182,902		111,401
	$	72,562,307	$	71,329,497

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

F-4

EVERFLOW EASTERN PARTNERS, L. P.

CONSOLIDATED BALANCE SHEETS

December 31, 2006 and 2005

	2006		2005
LIABILITIES AND PARTNERS’ EQUITY
CURRENT LIABILITIES
Accounts payable:
Production and other	$	838,539	$	1,166,449
Joint venture partners		90,834		457,926
Accrued expenses		1,055,260		631,571
Total current liabilities		1,984,633		2,255,946
DEFERRED INCOME TAXES		435,000		—
ASSET RETIREMENT OBLIGATIONS		1,743,707		1,654,996
COMMITMENTS AND CONTINGENCIES
LIMITED PARTNERS’ EQUITY, SUBJECT TO REPURCHASE RIGHT
Authorized — 8,000,000 units Issued and outstanding — 5,644,094 and 5,674,678 units, respectively		67,595,381		66,630,706
GENERAL PARTNER’S EQUITY		803,586		787,849
Total partners’ equity		68,398,967		67,418,555
	$	72,562,307	$	71,329,497

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

F-5

EVERFLOW EASTERN PARTNERS, L. P.

CONSOLIDATED STATEMENTS OF INCOME

Years Ended December 31, 2006, 2005 and 2004

	2006			2005		2004
REVENUES
Oil and gas sales	$	34,282,448		$	32,557,169	$	25,108,890
Well management and operating		559,962			555,093		560,340
Other		5,505			2,089		1,530
		34,847,915			33,114,351		25,670,760
DIRECT COST OF REVENUES
Production costs		3,760,391			3,563,389		2,996,361
Well management and operating		209,289			227,249		185,097
Depreciation, depletion and amortization		5,473,789			4,805,380		4,559,746
Accretion expense		237,147			131,554		99,181
Abandonment of oil and gas properties		78,752			97,983		40,000
Total direct cost of revenues		9,759,368			8,825,555		7,880,385
GENERAL AND ADMINISTRATIVE EXPENSE		2,000,493			1,511,487		1,452,586
Total cost of revenues		11,759,861			10,337,042		9,332,971
INCOME FROM OPERATIONS		23,088,054			22,777,309		16,337,789
OTHER INCOME
Interest income		725,231			271,520		105,084
(Loss) gain on disposal of property and equipment		(34,526	)		4,086		—
		690,705			275,606		105,084
INCOME BEFORE INCOME TAXES		23,778,759			23,052,915		16,442,873
INCOME TAXES Current		201,045			84,640		39,576
Deferred		435,000			—		—
		636,045			84,640		39,576
NET INCOME	$	23,142,714		$	22,968,275	$	16,403,297
Allocation of Partnership Net Income
Limited Partners	$	22,871,548		$	22,700,247	$	16,212,544
General Partner		271,166			268,028		190,753
	$	23,142,714		$	22,968,275	$	16,403,297
Net income per unit	$	4.04		$	3.99	$	2.84

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

F-6

EVERFLOW EASTERN PARTNERS, L. P.

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

Years Ended December 31, 2006, 2005 and 2004

	2006			2005			2004
PARTNERS’ EQUITY — JANUARY 1	$	67,418,555		$	59,055,110		$	55,927,996
Net income		23,142,714			22,968,275			16,403,297
Cash distributions ($3.75 per unit in 2006, $2.50 per unit in 2005 and $2.25 per unit in 2004)		(21,462,846	)		(14,370,636	)		(12,979,302	)
Repurchase and retirement of Units		(699,456	)		(234,194	)		(296,881	)
PARTNERS’ EQUITY — DECEMBER 31	$	68,398,967		$	67,418,555		$	59,055,110

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

F-7

EVERFLOW EASTERN PARTNERS, L. P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

Years Ended December 31, 2006, 2005 and 2004

	2006			2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	23,142,714		$	22,968,275		$	16,403,297
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		5,544,428			4,850,207			4,608,569
Accretion expense		237,147			131,554			99,181
Abandonment of oil and gas properties		78,752			97,983			40,000
Loss (gain) on disposal of property and equipment		34,526			(4,086	)		—
Deferred income taxes		435,000			—			—
Changes in assets and liabilities:
Accounts receivable		342,680			(2,522,313	)		(1,623,030	)
Other current assets		9,092			(1,382	)		48,863
Other assets		(71,501	)		12,569			(3,294	)
Accounts payable		(695,002	)		847,840			54,807
Accrued expenses		244,220			48,950			30,452
Total adjustments		6,159,342			3,461,322			3,255,548
Net cash provided by operating activities		29,302,056			26,429,597			19,658,845
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds received on receivables from employees		53,108			41,009			42,356
Advances disbursed to employees		(89,400	)		(124,000	)		(39,500	)
Purchase of investments		(8,580,618	)		—			—
Purchase of property and equipment		(4,470,584	)		(6,400,874	)		(7,963,798	)
Proceeds on disposal of property and equipment		—			10,500			—
Net cash used by investing activities		(13,087,494	)		(6,473,365	)		(7,960,942	)
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions		(21,462,846	)		(14,370,636	)		(12,979,302	)
Repurchase and retirement of Units		(699,456	)		(234,194	)		(296,881	)
Net cash used by financing activities		(22,162,302	)		(14,604,830	)		(13,276,183	)
NET (DECREASE) INCREASE IN CASH AND EQUIVALENTS		(5,947,740	)		5,351,402			(1,578,280	)
CASH AND EQUIVALENTS — JANUARY 1		13,371,923			8,020,521			9,598,801
CASH AND EQUIVALENTS — DECEMBER 31	$	7,424,183		$	13,371,923		$	8,020,521
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Income taxes	$	289,305		$	70,000		$	60,000

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

F-8

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Organization and Summary of Significant Accounting Policies

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, 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 Everflow Management Limited, LLC are Everflow Management Corporation (“EMC”), two individuals who are Officers and Directors of EEI and Sykes Associates, LLC a limited liability company managed by Robert F. Sykes, the Chairman of the Board of EEI. EMC is an Ohio corporation formed in September 1990 and is the managing member of Everflow Management Limited, LLC.

B. Principles of Consolidation — The consolidated financial statements include the accounts of Everflow, its wholly-owned subsidiaries, including EEI and EEI’s wholly-owned subsidiaries, and investments in oil and gas drilling and income partnerships (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 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.

D. Fair Value of Financial Instruments — The fair values of cash and equivalents, accounts 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 Statement of Financial Accounting Standards (“SFAS”) No. 107, “Disclosure About Fair Value of Financial Instruments,” rates available at balance sheet dates to the Company are used to estimate the fair value of existing obligations.

E. Cash and Equivalents — The Company considers all highly liquid debt instruments purchased with a 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.

F-9

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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

F. Investments — The Company’s investments consist of commercial paper with original maturity dates of greater than three months, which are recorded at their amortized cost. Interest earnings on investments amounted to approximately $180,100 during the year ended December 31, 2006. The Company did not hold any investments in 2005.

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 $5,434,719. $4,728,556 and $4,503,933 for the years ended December 31, 2006, 2005 and 2004, 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 oil and gas properties for impairment annually. SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” requires 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. Everflow utilizes a field by field basis for assessing impairment of its oil and gas properties. The Company wrote down oil and gas properties by approximately $79,000, $98,000 and $40,000 during 2006, 2005 and 2004, respectively, to provide for impairment on certain of its oil and gas properties.

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 $1,209,523 — 40 years). Depreciation on pipeline and support equipment amounted to $39,070, $76,824 and $55,813 for the years ended December 31, 2006, 2005 and 2004, respectively. Depreciation on other corporate property and equipment, included in general and administrative expense, amounted to $70,639, $44,827 and $48,823 for the years ended December 31, 2006, 2005 and 2004, respectively.

F-10

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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

G.	Property and Equipment (Continued)
	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 — The Company follows SFAS No. 143, which requires 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.

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, 2005, the Company made significant revisions in estimates of plugging costs, discount rate, inflation 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:

	2006			2005
Beginning of Period	$	1,854,996		$	1,267,223
Liabilities incurred		31,033			37,029
Liabilities settled		(19,469	)		—
Accretion expense		237,147			131,554
Revisions in estimated cash flows		—			419,190
Total	$	2,103,707		$	1,854,996

F-11

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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

H. Asset Retirement Obligations (Continued)

At December 31, 2006 and 2005, the asset retirement obligations are included in accrued expenses (current portion) and asset retirement obligations (non-current portion) in the Company’s consolidated balance sheets. The current portion of the asset retirement obligations were $360,000 and $200,000 at December 31, 2006 and 2005, respectively.

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, income is recorded based on the Company’s net revenue interest in production taken for delivery. The Company had no material gas imbalances at December 31, 2006 and 2005. 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 receivable from joint venture partners and employees consist principally of drilling and development costs the Company has advanced or incurred on behalf of joint venture partners and employees (see Note 6). Accounts payable to joint venture partners consist principally of drilling and development advances the Company has received on behalf of joint venture partners. 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 tax elections that were made by owners of the working interests and limited partnership interests that comprised Programs.

As referred to in Note 4, EEI and its subsidiaries account for income taxes under SFAS No. 109, “Accounting for Income Taxes.” Income taxes are provided for all items (as they relate to EEI and its subsidiaries) in the Consolidated Statements of Income regardless of the period when such items are reported for income tax purposes. SFAS No. 109 provides that deferred tax assets and liabilities be recognized for temporary differences between the financial reporting basis and tax basis of certain of EEI’s and its subsidiaries’ assets and liabilities. In addition, SFAS No. 109 requires that deferred tax assets and liabilities be measured using

F-12

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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

J. Income Taxes (Continued)

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, SFAS No. 109 permits the recognition of expected benefits of utilizing net operating loss and tax credit carryforwards.

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 3).

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 5,659,386, 5,682,776 and 5,702,806 in 2006, 2005 and 2004, respectively.

L. New Accounting Standards — In June 2006, the Financial Accounting Standards Board issued Financial Interpretation No. 48 (“FIN 48”), “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109.” FIN 48 addresses the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes.” FIN 48 prescribes specific criteria for the financial statement recognition and measurement of the tax effects of a position taken or expected to be taken in a tax return. This interpretation also provides guidance on derecognition of previously recognized tax benefits, classification of tax liabilities on the balance sheet, recording interest and penalties on tax underpayments, accounting in interim periods, and disclosure requirements. FIN 48 is effective for fiscal periods beginning after December 15, 2006. Adoption of this standard is not expected to materially impact the Company’s financial statements.

In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157. This Statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. This Statement applies under other accounting pronouncements that require or permit fair value measurements, where fair value has been determined to be the relevant measurement attribute. This statement is effective for fiscal periods beginning after November 15, 2007. Adoption of this standard is not expected to materially impact the Company’s financial statements.

F-13

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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

L. New Accounting Standards (Continued)

In September 2006, the SEC issued Staff Accounting Bulletin No. 108 (“SAB 108”), “Considering the Effects of Prior Year Misstatements in Current Year Financial Statements.” SAB 108 provides guidance for quantifying and assessing the materiality of misstatements of financial statements, including uncorrected misstatements that were not material to prior years’ financial statements. SAB 108 is effective for fiscal years ending after November 15, 2006. The adoption of SAB 108 did not have a material effect on the Company’s financial statements and related disclosures.

In February 2007, the FASB issued SFAS No. 159. This Statement permits the option to choose to measure selected financial assets and liabilities at fair value. If the fair value option is elected, reporting of unrealized gains and losses on those assets and liabilities occurs in each subsequent reporting date. This statement is effective for fiscal years beginning after November 15, 2007. The Company is currently assessing the impact, if any, that the adoption of SFAS No. 159 will have on its financial statements.

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

Note 2. Credit Facilities and Long-Term Debt

The Company had a revolving line of credit that expired in 2003. 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 3). 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.

There were no borrowings outstanding during 2006 and 2005. 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 3. Partners’ Equity

Units represent limited partnership interests in Everflow. The Units are transferable subject only to the approval of any transfer by Everflow Management Limited, LLC 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.

F-14

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 3. Partners’ Equity (Continued)

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.

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, 2006 calculation, is estimated to be $12.88 per Unit, net of the distributions ($2.00 per Unit in total) expected to be made in January and April 2007.

Units repurchased pursuant to the repurchase right, for each of the four years in the period ended December 31, 2006, are as follows:

	Per Unit
	Calculated								Units
	Price for		Less						Outstanding
	Repurchase		Interim		Net		# of Units		Following
Year	Right		Distributions		Price Paid		Repurchased		Repurchase
2003	$	8.94	$	.50	$	8.44		34,034		5,714,739
2004	$	13.44	$	1.00	$	12.44		23,865		5,690,874
2005	$	15.46	$	1.00	$	14.46		16,196		5,674,678
2006	$	24.37	$	1.50	$	22.87		30,584		5,644,094

F-15

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 4. Provision for Income Taxes

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

	Year Ended December 31,
	2006						2005						2004
	Amount			%			Amount			%			Amount			%
Provision based on the statutory rate (for taxable income up to $10,000,000)	$	8,085,000			34.0		$	7,838,000			34.0		$	5,591,000			34.0
Tax effect of:
Non-taxable status of the Programs and Everflow		(7,413,000	)		(31.2	)		(7,301,000	)		(31.7	)		(5,226,000	)		(31.8	)
Excess statutory depletion		(99,000	)		(0.4	)		(99,000	)		(0.4	)		(80,000	)		(0.5	)
Graduated tax rates, state income tax, tax credits and other — net		63,045			0.3			(353,360	)		(1.5	)		(245,424	)		(1.5	)
Total	$	636,045			2.7		$	84,640			0.4		$	39,576			0.2

As referred to in Note 1, EEI and its subsidiaries account for current and deferred income taxes under the provisions of SFAS No. 109. 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, 2006 and 2005, these deferred tax items resulted in deferred tax liabilities of $435,000 and $469,000, respectively. In 2005, the deferred tax liability was offset by deferred tax assets resulting from the tax benefit of EEI’s percentage depletion and tax credit carryovers. The tax credit carryforwards were generated from payment of alternative minimum tax (“AMT credits”) in prior years. Prior to 2005, due to the anticipated minimum utilization of the AMT credits, the Company recorded no tax benefit related to the credits. At December 31, 2006 and 2005, EEI had estimated percentage depletion deduction carryforwards for tax purposes of approximately $0 and $654,000, respectively. At December 31, 2006 and 2005, EEI had AMT credit carryforwards for tax purposes of approximately $0 and $177,000, respectively.

Note 5. 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 $191,001, $175,788 and $167,220 for the years ended December 31, 2006, 2005 and 2004, respectively.

F-16

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 6. Related Party Transactions

The Company’s Officers, Directors, Affiliates and certain employees have frequently participated, and will likely 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. At December 31, 2006 and 2005, these employee receivables amounted to $157,093 and $120,801, respectively. The loans accrue interest at prime (8.25% at December 31, 2006) and are expected to be paid from production revenues attributable to such interests or through joint interest assessments.

Note 7. Business Segments, Risks and Major Customers

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

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

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

Gas sales accounted for 87%, 88% and 89% of total oil and gas sales in 2006, 2005 and 2004, respectively. Approximate percentages of total oil and gas sales from significant purchasers for the years ended December 31, 2006, 2005 and 2004, respectively, were as follows:

Customer	2006			2005			2004
Dominion Field Services, Inc., its affiliates and its predecessors (“Dominion”)		40	%		40	%		46	%
Ergon Oil Purchasing, Inc. (“Ergon Oil”)		12			12			10
Interstate Gas Supply, Inc. (“IGS”)		18			18			21
		70	%		70	%		77	%

F-17

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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

The Company’s production accounts receivable result from sales of natural gas and crude oil. A significant portion of the Company’s production accounts receivable is due from the Company’s major customers. The Company does not view such concentration as an unusual credit risk. However, the Company does not require collateral from its customers and could incur losses if its customers fail to pay. As a result of management’s review of current and historical credit losses and economic activity, a valuation allowance was not deemed necessary at December 31, 2006 and 2005. The Company expects that Dominion, Ergon Oil and IGS will be the only major customers in 2007.

The Company has numerous contracts, 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. A summary of significant gas purchase contracts, including weighted average pricing provisions, with Dominion follows:

	Jan		Feb		Mar		Apr		May		Jun
	2007		2007		2007		2007		2007		2007
MCF		130,000		130,000		130,000		100,000		100,000		150,000
Price	$	9.93	$	9.93	$	9.93	$	9.74	$	9.74	$	9.55

	Jul		Aug		Sep		Oct		Nov		Dec
	2007		2007		2007		2007		2007		2007
MCF		100,000		100,000		100,000		100,000		140,000		120,000
Price	$	9.74	$	9.74	$	9.74	$	9.74	$	9.80	$	9.86

	Jan		Feb		Mar		Apr		May		Jun
	2008		2008		2008		2008		2008		2008
MCF		120,000		120,000		120,000		90,000		90,000		90,000
Price	$	9.86	$	9.86	$	9.86	$	9.16	$	9.16	$	9.16

	Jul		Aug		Sep		Oct
	2008		2008		2008		2008
MCF		90,000		90,000		90,000		90,000
Price	$	9.16	$	9.16	$	9.16	$	9.16

F-18

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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

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 on a monthly basis throughout the contract periods. A summary of significant gas purchase contracts, including weighted average pricing provisions, with IGS follows:

	Jan		Feb		Mar		Apr		May		Jun
	2007		2007		2007		2007		2007		2007
MCF		70,000		70,000		70,000		50,000		50,000		90,000
Price	$	10.40	$	10.40	$	10.40	$	9.38	$	9.38	$	9.32

	Jul		Aug		Sep		Oct		Nov		Dec
	2007		2007		2007		2007		2007		2007
MCF		50,000		50,000		50,000		50,000		80,000		60,000
Price	$	9.38	$	9.38	$	9.38	$	9.38	$	9.55	$	9.46

	Jan		Feb		Mar		Apr		May		Jun
	2008		2008		2008		2008		2008		2008
MCF		60,000		60,000		60,000		40,000		40,000		40,000
Price	$	9.46	$	9.46	$	9.46	$	9.12	$	9.12	$	9.12

	Jul		Aug		Sep		Oct
	2008		2008		2008		2008
MCF		40,000		40,000		40,000		40,000
Price	$	9.12	$	9.12	$	9.12	$	9.12

As detailed above, the price paid for natural gas purchased by Dominion and IGS varies based on quantities committed by the Company from time to time. Natural gas sold under these contracts in excess of the committed prices are 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 under SFAS No. 133. As of December 31, 2006, natural gas purchased by Dominion covers production from approximately 490 gross wells, while natural gas purchased by IGS covers production from approximately 225 gross wells. Production from the Dominion and IGS contract oil and gas properties comprises approximately 65% of the Company’s natural gas sales.

F-19

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 8. Commitments and Contingencies

Everflow paid a dividend in January 2007 of $1.00 per Unit. The distribution amounted to approximately $5,711,000.

As described in Note 7, the Company has significant natural gas delivery commitments to Dominion and IGS, its major customers. Management believes the Company can meet its delivery commitments based on estimated production. If, however, the Company cannot meet its delivery commitments, it will purchase natural gas at market prices to meet such commitments which will result in a gain or loss for the difference between the delivery commitment price and the price the Company is able to purchase the gas for redelivery (resale) to its customers.

Note 9. Selected Quarterly Financial Data (Unaudited)

The following is a summary of selected quarterly financial data (unaudited) for the years ended December 31, 2006 and 2005:

	Quarters Ended
	March 31		June 30		September 30		December 31
2006
Revenues	$	9,539,090	$	8,079,677	$	8,607,349	$	8,621,799
Income from operations		6,821,042		5,494,945		5,896,245		4,875,822
Net income		6,892,377		5,634,514		5,868,886		4,746,937
Net income per unit		1.20		0.98		1.03		0.83

	Quarters Ended
	March 31		June 30		September 30		December 31
2005
Revenues	$	5,813,500	$	7,379,613	$	8,053,619	$	11,867,619
Income from operations		3,414,384		5,059,288		5,331,105		8,972,532
Net income		3,461,021		5,116,275		5,374,890		9,016,089
Net income per unit		0.60		0.89		0.94		1.56

Quarterly operating results are not necessarily representative of operations for a full year for various reasons, including the volatility and seasonality of oil and gas production and prices, the highly competitive and, at times, seasonal nature of the oil and gas industry and worldwide economic conditions.

F-20

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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

The following supplemental unaudited oil and gas information is required by SFAS No. 69, “Disclosures About Oil and Gas Producing Activities.”

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

CAPITALIZED COSTS RELATING TO OIL AND GAS
PRODUCING ACTIVITIES

	Years ended December 31,
	2006		2005		2004
Proved oil and gas properties	$	140,443,938	$	136,388,136	$	129,734,209
Pipeline and support equipment		528,193		532,229		621,481
		140,972,131		136,920,365		130,355,690
Accumulated depreciation, depletion, amortization and write down		94,064,163		88,767,760		84,127,102
Net capitalized costs	$	46,907,968	$	48,152,605	$	46,228,588

COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES

	Years ended December 31,
	2006		2005		2004
Property acquisition costs	$	173,704	$	321,395	$	318,155
Development costs		4,101,986		6,017,543		7,384,951

In 2006, 2005 and 2004, development costs include the purchase of approximately $-0-, $-0- and $21,000, respectively, of producing oil and gas properties.

F-21

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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

RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES

	Years ended December 31,
	2006			2005			2004
Oil and gas sales	$	34,282,448		$	32,557,169		$	25,108,890
Production costs		(3,760,391	)		(3,563,389	)		(2,996,361	)
Depreciation, depletion and amortization		(5,473,789	)		(4,805,380	)		(4,559,746	)
Accretion expense		(237,147	)		(131,554	)		(99,181	)
Abandonment of oil and gas properties		(78,752	)		(97,983	)		(40,000	)
		24,732,369			23,958,863			17,413,602
Income tax expense		500,000			260,000			100,000
Results of operations for oil and gas producing activities (excluding corporate overhead and financing costs)	$	24,232,369		$	23,698,863		$	17,313,602

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

F-22

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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

ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES

	Oil			Gas
	(BBLS)			(MCF)
Balance, January 1, 2004		703,000			47,069,000
Extensions, discoveries and other additions		65,000			3,194,000
Production		(72,000	)		(3,932,000	)
Revision of previous estimates		86,000			3,019,000
Balance, December 31, 2004		782,000			49,350,000
Extensions, discoveries and other additions		32,000			1,355,000
Production		(72,000	)		(3,878,000	)
Revision of previous estimates		61,000			4,216,000
Balance, December 31, 2005		803,000			51,043,000
Extensions, discoveries and other additions		1,000			808,000
Production		(72,000	)		(3,500,000	)
Revision of previous estimates		(14,000	)		(5,345,000	)
Balance, December 31, 2006		718,000			43,006,000
PROVED DEVELOPED RESERVES:
December 31, 2003		703,000			47,069,000
December 31, 2004		782,000			49,350,000
December 31, 2005		803,000			51,043,000
December 31, 2006		718,000			43,006,000

The Company has not determined proved reserves associated with its proved undeveloped acreage. At December 31, 2006 and 2005, the Company had 978 and 255 net proved undeveloped acres, respectively. The carrying cost of the proved undeveloped acreage that is included in proved properties amounted to $209,016 and $89,741 at December 31, 2006 and 2005, respectively.

F-23

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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

STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS

			December 31,
	2006		2005		2004
	(Thousands of Dollars)
Future cash inflows from sales of oil and gas	$	313,397	$	566,186	$	352,486
Future production and development costs		107,322		139,946		105,807
Future asset retirement obligations, net of salvage		9,220		9,145		3,509
Future income tax expense		4,294		8,997		5,133
Future net cash flows		192,561		408,098		238,037
Effect of discounting future net cash flows at 10% per annum		87,846		219,835		118,948
Standardized measure of discounted future net cash flows	$	104,715	$	188,263	$	119,089

CHANGES IN THE STANDARDIZED MEASURE OF
DISCOUNTED FUTURE NET CASH FLOWS

	Years Ended December 31,
	2006			2005			2004
	(Thousands of Dollars)
Balance, beginning of year	$	188,263		$	119,089		$	101,843
Extensions, discoveries and other additions		1,947			6,380			9,487
Development costs incurred		412			1,436			349
Revision of quantity estimates		(11,822	)		15,809			8,456
Sales of oil and gas, net of production costs		(30,522	)		(28,994	)		(22,113	)
Net change in income taxes		1,836			(1,534	)		(203	)
Net changes in prices and production costs		(75,149	)		63,400			10,504
Accretion of discount		18,826			11,909			10,184
Other		10,924			768			582
Balance, end of year	$	104,715		$	188,263		$	119,089

F-24

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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

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

The methodology and assumptions used in calculating the standardized measure are those required by SFAS No. 69. It is not intended to be representative of the fair market value of the Company’s proved reserves. The valuation of revenues and costs does not necessarily reflect the amounts to be received or expended by the Company. In addition to the valuations used, numerous other factors are considered in evaluating known and prospective oil and gas reserves.

F-25

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

          Not applicable.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

          As of the end of the period covered by this report, management preformed, with the participation of our Chief Executive Officer and Chief Financial Officer, an evaluation of the effectiveness of our disclosure controls and procedures as defined in Exchange Act Rules 13a-15. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures. Based on the evaluation and identification of the material weaknesses in internal control over financial reporting described below, management concluded that our disclosure controls and procedures were not effective for the year ended December 31, 2006 and management further expects that our disclosure controls and procedures may not be effective for the year ending December 31, 2007.

          Because of the material weaknesses identified in our evaluation of internal control over financial reporting, we performed additional procedures, where necessary, so that our financial statements and selected financial data for the years ended December 31, 2004 through December 31, 2006, are presented in accordance with accounting principles generally accepted in the United States (“GAAP”). These procedures include evaluating the accounting documentation and reassessing original judgments we made about accounting treatments, reviewing our existing contracts to determine proper financial reporting, re-performance of accounting accruals for both revenues and expenses, performing additional closing procedures, including detailed review of journal entries, account reconciliations and analysis of balance sheet and income statement accounts.

Management’s Report on Internal Control Over Financial Reporting

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

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improve our internal controls over financial reporting as necessary and appropriate for our business, but we cannot provide you with assurance that such improvements will be sufficient to provide us with effective internal control over financial reporting.

          Management was responsible for assessing the effectiveness of our internal controls over financial reporting as of December 31, 2006 as required under Section 404 of the Sarbanes-Oxley Act of 2002. Management’s assessment efforts undertaken during the 2006 fiscal year were conducted using the framework established inInternal Control-Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Management did not complete our evaluation of internal control over financial reporting by the end of 2006.

          Management utilized internal resources to assist in the various aspects of its assessment and compliance efforts. Based on the material weaknesses identified below, management concluded that our internal control over financial reporting was not effective as of December 31, 2006. A “material weakness” is a significant deficiency, or combination of significant deficiencies, that results in there being more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. A “significant deficiency” is a control deficiency, or combination of control deficiencies, that adversely affects a company’s ability to initiate, authorize, record, process and report external financial data reliably in accordance with GAAP. While our control deficiencies have not resulted in any material misstatements of account balances or disclosures that we are aware of, they could result in misstatements or disclosures which could cause a material misstatement of annual or interim financial statements that would not be prevented or detected. Accordingly, management has determined that these control deficiencies constitute a material weakness.

          In connection with management’s assessment of our internal control over financial reporting, we identified five material weaknesses in our internal control over financial reporting as of December 31, 2006.

1)	We did not have adequate controls in place to establish and maintain an effective control environment. Specifically, we did not establish and maintain sufficient, documented and formalized consistent finance and accounting policies. This material weakness in the control environment increases the likelihood of material misstatements of our annual and interim financial statements that would not be prevented or detected.
2)	We did not maintain sufficient, formalized written policies and procedures governing the financial reporting process. Effective controls were not designed and in place to provide reasonable assurance that accounts were complete and accurate and agreed to the detailed supporting documentation.
3)	We did not maintain effective controls, including policies and procedures, over accounting for property and equipment. Specifically, we do not have a comprehensive formal policy regarding property and equipment. As a result, asset retirements were not identified and their values were not properly assessed and adjusted for based on their status in the proper accounting period.

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	Additionally, depletion, depreciation and amortization was not properly assessed and adjusted for within the framework of an effective control environment.
4)	We did not maintain effective controls, including policies and procedures, over accounting for crude oil and natural gas production accruals. Specifically, we did not establish a formal written policy regarding crude oil and natural gas production accruals. As a result, accrued oil and gas production revenues were not properly assessed and adjusted for within the framework of an affective control environment.
5)	We did not maintain effective controls over access by personnel to information technology programs and systems. Specifically, we do not have adequate policies and procedures to control security access, as well as a lack of independent review of such access.

          Because of the five material weaknesses described above, management has concluded that we did not maintain effective internal controls over financial reporting as of December 31, 2006, based on theInternal Control — Integrated Frameworkissued by COSO.

          As a result of management’s incomplete assessment of the effectiveness of our internal controls over financial reporting as of December 31, 2006, Hausser + Taylor LLC, our independent registered public accounting firm, was unable to perform auditing procedures necessary to form an opinion on management’s assessment and did not express an opinion on management’s assessment and expressed an adverse opinion on the effectiveness of internal control over financial reporting because of the material weaknesses identified and effects of a scope limitation. Hausser + Taylor LLC has issued an attestation report which is included herein.

Changes in Internal Control Over Financial Reporting

          There have been no changes in the Company’s internal controls over financial reporting or in other factors that occurred during the fiscal period covered by this report other than our ongoing efforts to remediate our ineffective internal controls. We have engaged in, and are continuing to engage in, substantial efforts to improve our internal control over financial reporting and disclosures and procedures related to substantially all areas of our financial statements and disclosures.

Remediation of Material Weaknesses in Internal Control Over Financial Reporting

          We have engaged in substantial efforts to address the material weaknesses in our internal control over financial reporting and the ineffectiveness of our disclosure controls and procedures. It is management’s goal to remediate as many material weaknesses as feasible during 2007, but we expect that we will need to continue our remediation efforts into 2008 once documentation and testing have been completed. Ongoing changes to our internal control over financial reporting have been instituted following the year end December 31, 2006 as follows:

• Management has communicated its endorsement and reinforced its commitment to maintaining sound and effective internal controls over financial reporting;

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• Additional effective control policies and procedures established as a result of the new financial data reporting system implemented during 2006 will assist us in establishing and maintaining effective policies and procedures governing the financial reporting process;

• Additional personnel resources have been identified to address the shortfalls in staffing to assist us with accounting, finance and information technology responsibilities;

• Review of existing control policies and procedures and further design and documentation of additional policies and procedures as necessary to provide reasonable assurance that we comply with these enhanced policies and procedures in key areas, including accounting for property and equipment and crude oil and natural gas production accruals;

• Additional control policies and procedures have been identified and are in the process of being added to appropriately restrict and monitor access to our information technology programs and systems.

          Efforts to continue to document, test and remediate our internal control over financial reporting are continuing and are expected to continue throughout fiscal 2007 and beyond. Our continuing remediation efforts noted above are subject to our internal control assessment, testing and evaluation processes. While these efforts continue, we will rely on additional substantive procedures and other measures as needed to assist us with meeting the objectives otherwise fulfilled by an effective control environment.

Report of Independent Registered Public Accounting Firm

To the Partners
Everflow Eastern Partners, L.P.
Canfield, Ohio

          We were engaged to audit management’s assessment regarding the effectiveness of internal control over financial reporting of Everflow Eastern Partners, L.P. and subsidiaries (the “Company”) as of December 31, 2006. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting.

          As described in the accompanying Management’s Report on Internal Control over Financial Reporting on page 33, the Company was unable to complete its assessment of the effectiveness of the Company’s internal control over financial reporting. Accordingly, we are unable to perform auditing procedures necessary to form an opinion on management’s assessment.

          A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in

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accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

          Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

          A material weakness is a significant deficiency, or combination of significant deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. The following five material weaknesses have been identified and included in management’s assessment:

1.	The Company did not have adequate controls in place to establish and maintain an effective control environment. Specifically, the Company did not establish and maintain sufficient, documented and formalized consistent finance and accounting policies. This material weakness in the control environment increases the likelihood of material misstatements of our annual and interim financial statements that would not be prevented or detected.
2.	The Company did not maintain sufficient, formalized written policies and procedures governing the financial reporting process. Effective controls were not designed and in place to provide reasonable assurance that accounts were complete and accurate and agreed to the detailed supporting documentation.
3.	The Company did not maintain effective controls, including policies and procedures, over accounting for property and equipment. Specifically, the Company did not have a comprehensive formal policy regarding property and equipment. As a result, asset retirements were not identified and their values were not properly assessed and adjusted for based on their status in the proper accounting period. Additionally, depletion, depreciation and amortization was not properly assessed and adjusted for within the framework of an effective control environment.
4.	The Company did not maintain effective controls, including policies and procedures, over accounting for crude oil and natural gas production accruals. Specifically, the Company did not establish a formal written policy regarding

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crude oil and natural gas production accruals. As a result, accrued oil and gas production revenues were not properly assessed and adjusted for within the framework of an affective control environment.

5. The Company did not maintain effective controls over access by personnel to information technology programs and systems. Specifically, the company did not have adequate policies and procedures to control security access, as well as a lack of independent review of such access.

          These material weaknesses were considered in determining the nature, timing, and extent of audit tests applied in our audit of the consolidated financial statements as of and for the year ended December 31, 2006, of the Company and this report does not affect our report on such consolidated financial statements.

          Because of the limitation on the scope of our audit described in the second paragraph of this report, the scope of our work was not sufficient to enable us to express, and we do not express, an opinion on management’s assessment referred to above. In our opinion, because of the effect of the material weaknesses described above on the achievement of the objectives of the control criteria and the effects of any other material weaknesses, if any, that we might have identified if we had been able to perform sufficient auditing procedures relating to management’s assessment regarding the effectiveness of internal control over financial reporting, the Company has not maintained effective internal control over financial reporting as of December 31, 2006, based in criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

          We have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Everflow Eastern Partners, L.P. and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of income, partners’ equity, and cash flows for each of the three years in the period ended December 31, 2006, and our report dated March 16, 2007 expressed an unqualified opinion.

/s/ Hausser + Taylor LLC

Cleveland, Ohio
March 16, 2007

ITEM 9B. OTHER INFORMATION

          None.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

          The Company, as a limited partnership, does not have any directors or executive officers. The General Partner of the Company is Everflow Management Limited, LLC, an Ohio limited liability company formed in March 1999, as the successor to the Company’s original general partner. The members of the General Partner as of March 10, 2007 are EMC, Thomas L. Korner and William A. Siskovic, all of whom are directors and/or officers of EEI, and Sykes Associates LLC, a New York limited liability company managed by Robert F. Sykes, Chairman of the Board of EEI.

          EMC is the Managing Member of the General Partner. EMC was formed in September 1990 to act as the Managing General Partner of Everflow Management Company, the predecessor of the General Partner. EMC is owned by the other members of the General Partner and EMC currently has no employees, but as Managing Member of the General Partner, makes all management and business decisions on behalf of the General Partner and thus on behalf of the Company.

          EEI has continued its separate existence and provides general, administrative, management and leasehold functions for the Company. Personnel previously employed by EEI to conduct its operation, drilling and field supervisory functions have become employed directly by the Company and discharge the same functions on behalf of the Company. All of EEI’s outstanding shares are owned by the Company.

          Directors and Officers of EEI and EMC. The executive officers and directors of EEI and EMC as of March 10, 2007 are as follows:

			Positions and	Positions and
Name	Age		Offices with EEI	Offices with EMC
Robert F. Sykes		83	Chairman of the Board	Chairman of the Board and Director
Thomas L. Korner		53	President, Principal Executive Officer and Director	President, Principal Executive Officer and Director
William A. Siskovic		51	Vice President, Secretary — Treasurer, Principal Financial and Accounting Officer and Director	Vice President, Secretary — Treasurer, Principal Financial and Accounting Officer and Director

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

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     All directors and officers of EMC hold their positions with EMC pursuant to a shareholders’ agreement among EMC and such directors and officers. The shareholders agreement controls the operation of EMC, provides for changes in share ownership of EMC, and determines the identity of the directors and officers of EMC as well as their replacements.

Robert F. Sykes has been a Director of EEI since March 1987 and Chairman of the Board since May 1988. Mr. Sykes is the Chairman of the Board and a Director of EMC and has served in such capacities since its formation in September 1990. He was the Chairman of the Board of Sykes Datatronics, Inc., Rochester, New York, from its organization in 1986 until his resignation in January 1989. Sykes Datatronics, Inc. is a manufacturer of telephone switching equipment. Mr. Sykes also served as President and Chief Executive Officer of Sykes Datatronics, Inc. from 1968 until October 1983 and from January 1985 until October 1985. Mr. Sykes also has been a Director of Voplex, Inc., Rochester, New York, a manufacturer of plastic products, and a Director of ACC Corp., a long distance telephone company.

Thomas L. Korner has been President and Principal Executive Officer of EEI and EMC since November 1995. Mr. Korner is also a Director of EMC and has served in such capacity since its formation in September 1990. He served as Vice President and Secretary of EEI from April 1985 to November 1995 and as Vice President and Secretary of EMC from September 1990 to November 1995. He served as the Treasurer of EEI from June 1982 to June 1986. Mr. Korner supervises and oversees all aspects of the Company and EEI’s business, including oil and gas property acquisition, development, operation and marketing. Prior to joining EEI in June 1982, Mr. Korner was a practicing certified public accountant with Hill, Barth and King, certified public accountants, and prior to that with Arthur Andersen & Co., certified public accountants. He has a Business Administration Degree from Mt. Union College.

William A. Siskovic has been a Vice President of EEI since January 1989. Mr. Siskovic is a Vice President, Secretary-Treasurer, Principal Financial and Accounting Officer and a Director of EMC. He has served as Principal Financial Officer and Secretary of EMC since November 1995 and in all other capacities since the formation of EMC in September 1990. He is responsible for the financial operations of the Company and EEI. From August 1980 to July 1984, Mr. Siskovic served in various financial and accounting capacities including Assistant Controller of Towner Petroleum Company, a public independent oil and gas operator, producer and drilling fund sponsor company. From August 1984 to September 1985, Mr. Siskovic was a Senior Consultant for Arthur Young & Company, certified public accountants, where he was primarily responsible for the firm’s oil and gas consulting practice in the Cleveland, Ohio office. From October 1985 until joining EEI in April 1988, Mr. Siskovic served as Controller and Principal Accounting Officer of Lomak Petroleum, Inc., a public independent oil and gas operator and producer. He has a Business Administration Degree in Accounting from Cleveland State University.

Audit Committee

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

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REPORT OF THE AUDIT COMMITTEE

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

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

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

          Based on our review and discussions referred to above, we have recommended to the Board of Directors that the audited financial statements of the Company be included in the Company’s Annual Report on Form 10-K for the year ended December 30, 2006, for filing with the Securities and Exchange Commission.

          Respectfully submitted by the members of the Audit Committee:

��	Robert F. Sykes (Chairman)
	Thomas L. Korner William A. Siskovic

Code of Ethics

          The Company has adopted a Code of Ethics that applies to the Company’s principal executive officer, principal financial officer, principal accounting officer, or persons performing similar functions. The Code of Ethics referenced in Exhibit 14.1 filed with the appropriate exhibit to the Registrant’s Form 10-K for the year ended December 31, 2006.

          Compliance to Section 16(a) of the Exchange Act. Section 16(a) of the Securities Exchange Act of 1934 requires the Company’s officers and directors, and persons who own more than 10% of the Units to file reports of ownership and changes in ownership with the Securities and Exchange Commission. Officers, directors and greater than 10% Unitholders are required by SEC regulation to furnish the Company with copies of all Section 16(a) forms they file.

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          Based solely on the Company’s review of the copies of such forms furnished to the Company, the Company believes that its officers, directors and greater than 10% beneficial owners complied with all Section 16(a) filing requirements for 2006.

ITEM 11. EXECUTIVE COMPENSATION

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

Compensation Discussion and Analysis

          The Company has no formal compensation committee. The board of directors of EMC is responsible for formulating and implementing the compensation recommendations of our executive officers. The board of directors of EMC is comprised solely of Mr. Robert F. Sykes, Mr. Thomas L. Korner and Mr. William A. Siskovic. We believe our compensation program must support a strategy of being competitive in order to encourage and reward strong performance and to motivate our executive officers by providing them with stability in our compensation environment.

          Our compensation program is designed to attract and retain talented and productive executives who are motivated to protect and enhance the long-term value of the Company for its unitholders. Our objective is to reward individual performance by providing competitive compensation with our peers. Our compensation levels are reviewed for available information on compensation paid by companies in our industry that are similar to us, taking into account the Company’s size.

          Our compensation philosophy is committed to a strong link between business performance and the attainment of strategic goals with the Company’s compensation and benefit programs. The Company’s compensation policy is designed to support the overall objective of maximizing the return to the Company’s unitholders by:

• Attracting, developing, retaining and rewarding highly qualified and productive individuals.

• Aligning compensation to both the Company and individual performance.

          This policy is intended to provide incentives that promote both short-term and long-term financial objectives of the Company.

Overview of 2006 Executive Compensation Components

          Mr. Thomas L. Korner and Mr. William A. Siskovic components of compensation in fiscal 2006 include the following:

• base salary

• annual cash bonuses

• retirement and other benefits

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Base Salary

          The base salary of our executive officers is intended to provide fixed compensation for the performance of core duties. In determining appropriate salary levels, consideration is given to the level and scope of responsibility, experience, and Company and individual performance. The base salaries paid to our executive officers during fiscal 2006 are shown in the Summary Compensation Table on page 44.

Annual Cash Bonuses

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

          Our executive officers are provided an annual cash bonus each year based on the achievement of certain financial and non-financial performance objectives during the previous fiscal year. Annual cash bonuses are based on a percentage of the executive’s base salary. For 2006, the board of directors set a range of these bonuses between 60% and 100% of the executive’s base salary, based on the Company achieving specified financial and non-financial performance objectives. In 2006, the financial performance objectives that were used for determining financial performance-based cash awards were profitability and overall company growth. In 2006, the non-financial performance objectives that were used for determining non-financial performance based cash awards were corporate governance and adherence to policies and procedures as well as other factors that vary depending on responsibilities.

          The 2007 target annual cash bonus awards for our executive officers are established as a percentage of the executive’s base salary. These target amounts range between 65% and 115% of base salary. These target amounts were determined considering executive pay at companies of comparable size. The board of directors believes it is important that these target and maximum payout levels are aligned with the Company’s long-term strategic plan and the Company’s expectation of future financial performance.

Retirement and Other Benefits

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

          The Company does not currently offer any deferred compensation program, supplemental executive retirement plan or any financial planning services for its executive officers. In addition, executive officers are not compensated with equity awards of stock or options for services performed for the Company.

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          The following table sets forth information concerning the annual compensation for services in all capacities to the Company for the fiscal years ended December 31, 2006, 2005 and 2004, of those persons who were, at December 31, 2006: (i) the chief executive officer; and (ii) the chief financial officer of EMC and EEI. The Chief Executive Officer and Chief Financial Officer are hereinafter referred to collectively as the “Named Executive Officers.”

SUMMARY COMPENSATION TABLE

	Annual Compensation
							All Other
Name and Principal Position	Year		Salary		Bonus		Compensation (1)			Total
Thomas L. Korner		2006	$	100,800	$	90,000	$	35,969	(2)	$	226,769
President and Principal		2005		100,800		77,500		32,195	(3)		210,495
Executive Officer		2004		100,800		86,000		32,403	(4)		219,203
William A. Siskovic		2006	$	100,800	$	90,000	$	35,200	(5)	$	226,000
Vice President and		2005		100,800		77,500		32,066	(6)		210,366
Principal Financial and		2004		100,800		86,000		31,670	(7)		218,470
Accounting Officer

No Named Executive Officer received personal benefits or perquisites during 2006, 2005 and 2004 in excess of $10,000.
(1)	Includes amounts contributed under the Company’s 401(K) Retirement Savings Plan. The Company matched employees’ contributions to the 401(K) Retirement Savings Plan to the extent of 100% of the first 6% of a participant’s salary reduction. Also includes amounts contributed under the profit sharing component of the Company’s 401(K) Retirement Savings Plan. The amounts attributable to the Company’s matching and profit sharing contributions vest immediately. Includes amounts considered taxable wages with respect to personal use of a Company vehicle and the Company’s Group Term Life Insurance Plan.
(2)	Includes $20,604 contributed under the profit sharing component of the Company’s 401(K) Retirement Savings Plan. Includes $11,460 contributed by the Company as matching contribution from the Company’s 401(K) Retirement Savings Plan. Includes $3,015 considered taxable wages with respect to personal use of a Company vehicle. Includes $690 considered taxable wages with respect to the Company’s Group Term Life Insurance Plan.
(3)	Includes $18,304 contributed under the profit sharing component of the Company’s 401(K) Retirement Savings Plan. Includes $10,698 contributed by the Company as matching contribution from the Company’s 401(K) Retirement Savings Plan. Includes $2,441 considered taxable wages with respect to personal use of a Company vehicle. Includes $690 considered taxable wages with respect to the Company’s Group Term Life Insurance Plan.
(4)	Includes $17,644 contributed under the profit sharing component of the Company’s 401(K) Retirement Savings Plan. Includes $11,488 contributed by the Company as matching contribution from the Company’s 401(K) Retirement Savings Plan. Includes $2,581 considered taxable wages with respect to personal use of a Company vehicle. Includes $690 considered taxable wages with respect to the Company’s Group Term Life Insurance Plan.
(5)	Includes $20,604 contributed under the profit sharing component of the Company’s 401(K) Retirement Savings Plan. Includes $11,460 contributed by the Company as matching contribution from the Company’s 401(K) Retirement Savings Plan. Includes $2,246 considered taxable wages with respect to personal use of a Company vehicle. Includes $690 considered taxable wages with respect to the Company’s Group Term Life Insurance Plan.
(6)	Includes $18,304 contributed under the profit sharing component of the Company’s 401(K) Retirement Savings Plan. Includes $10,698 contributed by the Company as matching contribution from the Company’s 401(K) Retirement Savings Plan. Includes $2,554 considered taxable wages with respect to personal use of a Company vehicle. Includes $450 considered taxable wages with respect to the Company’s Group Term Life Insurance Plan.
(7)	Includes $17,644 contributed under the profit sharing component of the Company’s 401(K) Retirement Savings Plan. Includes $11,488 contributed by the Company as matching contribution from the Company’s 401(K) Retirement Savings Plan. Includes $2,088 considered taxable wages with respect to personal use of a Company vehicle. Includes $450 considered taxable wages with respect to the Company’s Group Term Life Insurance Plan.

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          The General Partner, EMC and the members do not receive any separate compensation or reimbursement for their management efforts on behalf of the Company. All direct and indirect costs incurred by the Company are borne by the General Partner of the Company and the Unitholders as Limited Partners of the Company in proportion to their respective interest in the Company. The members are not entitled to any fees or other compensation as a result of the acquisition or operation of oil and gas properties by the Company. The members, in their individual capacities, are not entitled to share in distributions from or income of the Company on an ongoing basis, upon liquidation or otherwise. The members only share in the revenues, income and distributions of the Company indirectly through their ownership of the General Partner of the Company. The General Partner is entitled to share in the income and expense of the Company on the basis of its interests in the Company. The General Partner through its predecessor, Everflow Management Company, contributed Interests (as defined and described in “Item 1. Business” above) with an Exchange value of $670,980 for its interest as a general partner in the Company. Currently, the General Partner of the Company owns a 1.17% interest in the Company.

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

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

          The General Partner is a limited liability company of which EMC, an Ohio corporation is the Managing Member. The members of the General Partner are Thomas L. Korner and William A. Siskovic, both of whom are directors and officers of EEI, and Sykes Associates, a limited partnership controlled by Robert F. Sykes, Chairman of the Board of EEI and EMC. The General Partner of the Company, owns a 1.17% interest in the Company. The members and their affiliates currently hold (in addition to the General Partner’s interest in the Company) 1,266,770 Units, representing approximately 22.44% of the outstanding Units.

          The following table sets forth certain information with respect to the number of Units beneficially owned as of March 10, 2007 by each person known to the management of the Company to own beneficially more than 5% of the outstanding Units; by each director and officer of EMC; and by all directors and officers as a group. The table also sets forth (i) the ownership interests of the General Partner, and (ii) the ownership of EMC.

BENEFICIAL OWNERSHIP OF UNITS IN THE COMPANY,
EVERFLOW MANAGEMENT LIMITED, LLC AND EMC

					Percentage
					Interest in
			Percentage		Everflow		Percentage
Name	Units		of Units		Management		Interest in
of Holder	in Company		in Company(1)		Limited, LLC(2)		EMC
Robert F. Sykes(3)		1,056,464		18.72		66.6666		66.6666
Thomas L. Korner		138,575		2.45		16.6667		16.6667
William A. Siskovic		71,731		1.27		16.6667		16.6667
All officers and directors as a group (3 persons in EMC)		1,266,770		22.44		100.0000		100.0000

(1)	Does not include the interest in the Company owned indirectly by such individuals as a result of their ownership in (i) the General Partner (based on its 1.17% interest in the Company) or (ii) EMC (based on EMC’s 1% managing member’s interest in the General Partner).
(2)	Includes the interest in the General Partner owned indirectly by such individuals as a result of their share ownership in EMC resulting from EMC’s 1% managing member’s interest in the General Partner.
(3)	Includes 732,855 Units held by Sykes Associates, LLC, a New York limited liability company owned by the four adult children of Mr. Sykes as members, 162,462 Units of the Company held by the Robert F. Sykes Annuity Trust and 161,147 Units held by the Catherine Sykes Annuity Trust.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

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

          Certain officers and directors of EMC own oil and gas properties and, as such, contract with the Company to provide field operations on such properties. These ownership interests are charged per well fees for such services on the same basis as all other working interest owners. Thomas L. Korner and William A. Siskovic each had investments in oil and gas properties during 2006 and 2005 in the amount of $91,527 and $139,694, respectively.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

          Hausser + Taylor LLC (“Hausser + Taylor”) served as the Company’s independent auditor for the year ended December 31, 2006. The following is a summary of the fees billed to the Company by Hausser + Taylor, which served as the Company’s auditor, for professional services rendered during the years ended December 31, 2006 and 2005:

	December 31,
	2006		2005
Audit fees	$	135,964	$	107,020
Audit related fees		-0-		-0-
Tax fees		-0-		-0-
All other fees		-0-		-0-
Total	$	135,964	$	107,020

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

     Hausser + Taylor has a continuing relationship with RSM McGladrey, Inc. (“RSM”) (formerly with American Express Tax and Business Services, Inc.) from which it leases

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auditing staff who are full time, permanent employees of RSM and through which its shareholders provide non-audit services. As a result of this arrangement, Hausser + Taylor has no full time employees and, therefore, none of the audit services performed were provided by permanent full time employees of Hausser + Taylor. Hausser + Taylor manages and supervises the audit and audit staff, and is exclusively responsible for the opinion rendered in connection with its examination.

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)     (1) Financial Statements

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

	Page(s)
Report of Independent Registered Public Accounting Firm	F-3
Balance Sheets	F-4 — F-5
Statements of Income	F-6
Statements of Partners’ Equity	F-7
Statements of Cash Flows	F-8
Notes to Financial Statements	F-9 — F-25

(a)     (2) Financial Statements Schedules

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

(a)     (3) Exhibits

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

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

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

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

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

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SIGNATURES

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

EVERFLOW EASTERN PARTNERS, L.P.
By:	EVERFLOW MANAGEMENT LIMITED, LLC General Partner
By:	EVERFLOW MANAGEMENT CORPORATION Managing Member
By:	/s/ Robert F. Sykes	Director	March 16, 2007
	Robert F. Sykes
By:	/s/ Thomas L. KornerThomas L. Korner	President and Director (principal executive officer)	March 16, 2007
By:	/s/ William A. SiskovicWilliam A. Siskovic	Vice President, Secretary-Treasurer and Director (principal financial and accounting officer)	March 16, 2007

Exhibit Index

Exhibit No.	Description
3.1	Certificate of Limited Partnership of the Registrant dated September 13, 1990, as filed with the Delaware Secretary of State on September 14, 1990	(1	)
3.2	Form of Agreement of Limited Partnership of the Registrant	(1	)
3.3	General Partnership Agreement of Everflow Management Company	(1	)
3.4	Articles of Incorporation of Everflow Management Corporation	(1	)
3.5	Code of Regulations of Everflow Management Corporation	(1	)
3.6	Shareholders Agreement for Everflow Management Corporation	(1	)
10.1	Credit Agreement dated January 19, 1995 between Everflow Eastern, Inc. and Everflow Eastern Partners, L.P. and Bank One, Texas, National Association	(2	)
10.2	Operating facility lease dated October 3, 1995 between Everflow Eastern Partners, L.P. and A-1 Storage of Canfield, Ltd.	(3	)
10.3	Amendment to Credit Agreement dated February 23, 1996 between Everflow Eastern, Inc. and Everflow Eastern Partners, L.P. and Bank One, Texas, National Association	(5	)
10.4	Second Amendment to Credit Agreement dated December 30, 1996 between Everflow Eastern, Inc. and Everflow Partners, L.P. and Bank One, Texas, National Association	(5	)
10.5	Loan Modification Agreement dated June 16, 1997 between Bank One, N.A., Bank One, Texas, N.A. and Everflow Eastern, Inc. and Everflow Eastern Partners, L.P.	(6	)
10.6	Loan Modification Agreement dated May 29, 1998 between Bank One, N.A., Successor to Bank One, Texas, N.A., and Everflow Eastern, Inc. and Everflow Eastern Partners L.P.	(7	)
10.7	Articles of Organization of Everflow Management Limited, LLC	(8	)

E-1

Exhibit Index

Exhibit No.	Description
10.8	Operating Agreement of Everflow Management Limited, LLC dated March 8, 1999	(8	)
10.9	Loan Modification Agreement dated May 25, 1999 between Bank One, N.A., and Everflow Eastern, Inc. and Everflow Eastern Partners, L.P.	(9	)
10.10	Loan Modification Agreement dated September 19, 2000, between Bank One, N.A., and Everflow Eastern, Inc. and Everflow Eastern Partners, L.P.	(10	)
10.11	Loan Modification Agreement dated August 28, 2001 between Bank One, N.A., and Everflow Eastern, Inc. and Everflow Eastern Partners, L.P.	(11	)
14.1	Code of Ethics
21.1	Subsidiaries of the Registrant	(4	)
31.1	Certification of CEO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certification of CFO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1	Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

(1)	Incorporated herein by reference to the appropriate exhibit to Registrant’s Registration Statement on Form S-1 (Reg. No. 33-36919).
(2)	Incorporated herein by reference to the appropriate exhibit to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1994 (File No. 0-19279).
(3)	Incorporated herein by reference to the appropriate exhibit to the Registrant’s Quarterly Report on Form 10-Q for the third quarter ended September 30, 1995 (File No. 0-19279).
(4)	Incorporated herein by reference to the appropriate exhibit to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1995 (File No. 0-19279).
(5)	Incorporated herein by reference to the appropriate exhibit to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1996 (File No. 0-19279).
(6)	Incorporated herein by reference to the appropriate exhibit to the Registrant’s Quarterly Report on Form 10-Q for the second quarter ended June 30, 1997 (File No. 0-19279).
(7)	Incorporated herein by reference to the appropriate exhibit to the Registrant’s Quarterly Report on Form 10-Q for the second quarter ended June 30, 1998 (File No. 0-19279).
(8)	Incorporated herein by reference to the appropriate exhibit to the Registrant’s Quarterly Report on Form 10-Q for the first quarter ended March 31, 1999 (File No. 0-19279).
(9)	Incorporated herein by reference to the appropriate exhibit to the Registrant’s Quarterly Report on Form 10-Q for the second quarter ended June 30, 1999 (File No. 0-19279).
(10)	Incorporated herein by reference to the appropriate exhibit to the Registrant’s Quarterly Report on Form 10-Q for the third quarter ended September 30, 2000 (File No. 0-19279).
(11)	Incorporated herein by reference to the appropriate exhibit to the Registrant’s Quarterly Report on Form 10-Q for the third quarter ended September 30, 2001 (File No. 0-19279).

E-2