EVERFLOW EASTERN PARTNERS LP - 10-K Annual Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

COMMISSION FILE NO. 0-19279

EVERFLOW EASTERN PARTNERS, L.P.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)

DELAWARE 34-1659910
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)

585 WEST MAIN STREET
P.O. BOX 629
CANFIELD, OHIO 44406
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)

REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 330-533-2692

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

NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED

None

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

UNITS OF LIMITED PARTNERSHIP INTEREST

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

Indicate by check mark 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.[ ]

Indicate by check mark whether the registrant is an accelerated filer
(as defined in Exchange Act Rule 12b-2). Yes [ ] No [X]

There were 4,447,969 Units of limited partnership interest held by
non-affiliates of the Registrant as of March 20, 2004. 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, 2003.

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 exploration and development.
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).

General

This Annual Report on Form 10-K contains forward-looking statements
which involve risks and uncertainties. The Company's actual results may differ
significantly from the results discussed in the forward-looking statements. All
statements that address operating performance, events or developments that the
Company anticipates will occur in the future,

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including statements related to future revenue, profits, expenses, and income or
statements expressing general optimism about future results, are forward-looking
statements within the meaning of Section 21E of the Securities Exchange Act of
1934, as amended ("Exchange Act"). 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.

Factors that may cause differences in the Company's actual results
versus results discussed in forward-looking statements include, but are not
limited to, the competition within the oil and gas industry, the price of oil
and gas in the Appalachian Basin area, the number of Units tendered pursuant to
the Repurchase Right and the ability to locate productive oil and gas prospects
for development by the Company. The Company undertakes no obligation to update
publicly any forward-looking statements, whether as a result of new information,
future events or otherwise.

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 wholly-owned subsidiary of the Company. EEI is engaged in the
business of drilling, developing and operating oil and gas properties 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 93% of the estimated total future cash inflows
related to the Company's oil and gas reserves as of December 31, 2003 are
attributable to natural gas reserves. The substantial 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 291 (net)
wells. The Company serves as the operator of approximately 75% of the gross
wells and 85% of the net wells which comprise the Company's properties.

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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 experience with regard to finding oil and gas in commercially
productive quantities. The Company has decreased its level of activity in the
development of oil and gas properties compared with historical levels.
Management of the Company has from time to time explored and evaluated the
possible sale of the Company. The Company intends to continue to evaluate this
and other alternatives to maximize value for its Unitholders. See "MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS."

Acquisition of Prospects. The Company, through its wholly-owned
subsidiary EEI, maintains a leasehold inventory from which the General Partner
will select oil and gas prospects for development by the Company. EEI 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. EEI's current leasehold inventory consists of approximately 12
prospects in various stages of maturity representing approximately 430 net acres
under lease.

In choosing oil and gas prospects for the Company, the General Partner
does not attempt to manage the risks of drilling through a policy of selecting
diverse prospects in various geographic areas or with the potential of oil and
gas production from different geological formations. Rather, substantially all
prospects are expected to be located in the Appalachian Basin of Ohio (and, to a
lesser extent, Pennsylvania) and 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.

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.

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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 have had no
borrowings during 2003 and no principal indebtedness was outstanding as of March
20, 2004. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS - Liquidity and Capital Resources."

Although 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 made to enable it to repurchase any Units tendered in
connection with the Repurchase Right. See "Management's Discussion and Analysis
of Financial Condition and results of operations - Liquidity and Capital
Resources."

The Company has a substantial amount of oil and gas reserves. The
Company generally would 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), although there can be
no assurance that circumstances would not lead to the necessity of borrowings in
excess of this amount. Based upon its current business plan, management has no
present intention to have the Company borrow in excess of this amount. The
Company has estimated Proved and Proved Developed Reserves, determined as of
December 31, 2003, which aggregate $101,843,000 (Standardized Measure of
Discounted Future Net Cash Flows) with no bank debt outstanding as of December
31, 2003.

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Marketing

The ability of the Company to market oil and gas found in and produced
on its properties will depend on many factors beyond its control, the effect of
which cannot be accurately anticipated or predicted. 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.

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 $35.00 in March 2004. As of March
20, 2004, the posted field price in the Appalachian Basin area, the Company's
principal area of operation, was $34.75 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 brought about 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. More
recently, during 2002, shortages in natural gas supplies once again have
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.
Certain of the Company's wells have been subject to these limited, seasonal
shut-ins and 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

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affiliates ("Dominion") (including The East Ohio Gas Company). Pursuant to the
East Ohio Contracts and subject to certain restrictions and adjustments,
including termination clauses, Dominion was obligated to purchase, and the
Company was obligated to sell, all natural gas production from a specified list
of wells (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.

The Company's last remaining East Ohio Contract terminated during 2001
and was replaced by a short-term contract, which obligate Dominion to purchase,
and the Company to sell and deliver certain quantities of natural gas production
on a monthly basis throughout the contract periods. A summary of significant gas
purchase contracts, including weighted average pricing provisions, with Dominion
follows:

Nov Dec Jan Feb Mar Apr
2003 2003 2004 2004 2004 2004
-------- -------- -------- -------- -------- --------

MCF 220,000 160,000 180,000 180,000 180,000 160,000
Price $ 4.82 $ 4.65 $ 4.77 $ 4.77 $ 4.77 $ 4.96

May Jun Jul Aug Sep Oct
2004 2004 2004 2004 2004 2004
-------- -------- -------- -------- -------- --------

MCF 160,000 220,000 180,000 180,000 180,000 180,000
Price $ 4.96 $ 5.01 $ 5.00 $ 5.00 $ 5.00 $ 5.00

Nov Dec Jan Feb Mar Apr
2004 2004 2005 2005 2005 2005
-------- -------- -------- -------- -------- --------

MCF 180,000 150,000 150,000 150,000 150,000 100,000
Price $ 5.76 $ 5.68 $ 5.68 $ 5.68 $ 5.68 $ 5.54

May Jun Jul Aug Sep Oct
2005 2005 2005 2005 2005 2005
-------- -------- -------- -------- -------- --------

MCF 100,000 100,000 100,000 100,000 100,000 100,000
Price $ 5.54 $ 5.54 $ 5.54 $ 5.54 $ 5.54 $ 5.54

The Company also has a short-term contract with Interstate Gas Supply,
Inc. ("IGS"), which obligate IGS to purchase, and the Company to sell and
deliver certain quantities of natural gas production on a monthly basis
throughout the contract periods. A summary of significant gas purchase
contracts, including weighted average pricing provisions, with IGS follows:

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Nov Dec Jan Feb Mar Apr
2003 2003 2004 2004 2004 2004
-------- -------- -------- -------- -------- --------

MCF 120,000 80,000 90,000 90,000 90,000 80,000
Price $ 4.53 $ 4.38 $ 4.54 $ 4.54 $ 4.54 $ 4.83

May Jun Jul Aug Sep Oct
2004 2004 2004 2004 2004 2004
-------- -------- -------- -------- -------- --------

MCF 80,000 110,000 80,000 80,000 80,000 80,000
Price $ 4.83 $ 4.83 $ 4.83 $ 4.83 $ 4.83 $ 4.83

Nov Dec Jan Feb Mar Apr
2004 2004 2005 2005 2005 2005
-------- -------- -------- -------- -------- --------

MCF 120,000 90,000 90,000 90,000 90,000 60,000
Price $ 6.20 $ 6.14 $ 6.14 $ 6.14 $ 6.14 $ 5.72

May Jun Jul Aug Sep Oct
2005 2005 2005 2005 2005 2005
-------- -------- -------- -------- -------- --------

MCF 60,000 60,000 60,000 60,000 60,000 60,000
Price $ 5.72 $ 5.72 $ 5.72 $ 5.72 $ 5.72 $ 5.72

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 locked in prices are
sold at the month's closing price plus basis adjustments, as per the contracts.
As of December 31, 2003, natural gas purchased by Dominion covers production
from approximately 480 gross wells, while natural gas purchased by IGS covers
production from approximately 220 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, 2003, with the exception of Dominion
and IGS, which accounted for approximately 55% and 25%, 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 2004.

Seasonality

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

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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 will encounter 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 marketing
programs to take advantage of new regulations requiring pipelines to transport
gas for

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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 East Ohio 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 recently 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

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services by separately pricing the various components of their services, such as
supply, gathering, transportation and sales. These pipeline companies are
required to provide customers only the specific service desired without regard
to the source for the purchase of the gas. Although the Partnership is not an
interstate pipeline, it is likely that this regulation may indirectly impact the
Partnership 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 activities offshore. 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.

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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 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.

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Employees

As of March 20, 2004, the Company had fifteen full-time and three
part-time employees. These employees primarily are engaged in the following
areas of business operations: two in land and lease acquisition, five in field
operations, five in accounting, and six in administration.

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ITEM 2. PROPERTIES

Set forth below is certain information regarding the oil and gas
properties of the Company.

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.

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, 2003.

Oil (BBLS) Gas (MCF)
---------- ----------

Proved Developed 703,000 47,069,000
Proved Undeveloped - -
------- ----------
Total 703,000 47,069,000
======= ==========

- ----------
(1) The Company has not determined proved reserves associated
with its proved undeveloped acreage which are not deemed significant at
December 31, 2003. 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, 2003, 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 $311,816
Future production and development costs 95,721
Future asset retirement obligations, net of salvage 3,151
Future income tax expense 4,841
--------

Future net cash flows 208,103
Effect of discounting future net cash flows
at 10% per annum 106,260
--------
Standardized measure of discounted future
net cash flows $101,843
========

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

-13-

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)
---------- --------- ------- ------- ---------------------

2003 76,000 4,053,000 $ 27.93 $ 4.73 $ .63
2002 73,000 3,680,000 22.33 3.98 .64
2001 76,000 3,583,000 22.57 3.93 .60

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

Productive Wells. The following table sets forth the gross and net oil
and gas wells of the Company as of December 31, 2003.

Gross Wells Net Wells
- -------------------------------------
(1) (1) (1) (1)
Oil Gas Total Oil Gas Total
- -------------------------------------

73 1,026 1,099 52 707 759

- ----------
(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 48,000 gross developed acres and
34,000 net developed acres as of December 31, 2003. Developed acreage is that
acreage assignable to productive wells. The Company had approximately 430 gross
and net proved undeveloped acres as of December 31, 2003.

-14-

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
----- ----- ----- ---

2003 46 18.87 - -
2002 29 14.00 2 .33
2001 33 15.14 - -

- ----------
(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 7 gross and 4.6 net
development wells since December 31, 2003. As of March 20, 2004, the Company had
no 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 more than
75% of the Company's natural gas sales. In addition, the Company has entered
into various short-term contracts which obligate the purchasers to purchase and
the Company to sell and deliver certain 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, 2003,
there were no matters submitted to a vote of security holders through the
solicitation of proxies or otherwise.

-15-

PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS

Market

There is currently no established public trading market for the Units.
At the present time, the Company does not intend to list any of the Units for
trading on any exchange or otherwise take any action to establish any market for
the Units. As of March 20, 2004, there were 5,714,739 Units held by 1,413
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 $1.25 per Unit during 2002
and 2003. Based upon the current number of Units outstanding, each quarterly
distribution of $0.125 per Unit would be approximately $723,000. The Company
made a quarterly distribution of $0.50 per Unit in January 2004 and currently
intends to make a quarterly distribution of $0.50 per Unit in April 2004 and
quarterly distributions of at least $0.125 per Unit in July and October 2004.

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
he elects to exercise the Repurchase Right and have the Company acquire certain
or all of his 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 117,488, 22,401 and 34,034 of its Units of limited partnership
interest at a price of $9.73, $5.66 and $8.44 per Unit pursuant to the terms of
the Company's Offers to Purchase dated April 30, 2001, 2002 and 2003,
respectively. See Note 3 in the Company's financial statement for additional
information on the Repurchase Right.

-16-

ITEM 6. SELECTED FINANCIAL DATA

Year Ended December 31,
-------------------------------------------------------------------
2003(2) 2002 2001 2000 1999
----------- ----------- ----------- ----------- -----------

Revenue ................................... $21,834,446 $16,757,418 $16,261,220 $16,921,139 $15,063,170
Net Income ................................ 11,951,300 8,004,090 7,842,162 8,590,757 5,445,941
Net Income Per Unit ....................... 2.06 1.37 1.33 1.42 .88
Total Assets .............................. 58,136,578 52,579,304 52,254,265 55,043,294 55,422,986
Debt(1) ................................... -- -- 512,014 637,822 692,289
Cash Distributions Per Unit ............... 1.25 1.25 1.50 1.25 .625

- ----------
(1) Debt includes the Company's long-term debt and borrowings under the
Company's revolving credit facility.

(2) See Note 1G to the 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 exploration and
development 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 EMC, two individuals who are currently directors and/or
officers of EEI, Thomas L. Korner and William A. Siskovic, and Sykes Associates,
a limited partnership controlled by Robert F. Sykes, the Chairman of the Board
of EEI.

LIQUIDITY AND CAPITAL RESOURCES

Financial Position

Working capital surplus of $12.6 million as of December 31, 2003
represented a $5.1 million increase from December 31, 2002 due primarily to
increases in cash and equivalents of $4.9 million and accounts receivable from
oil and gas production of $420,000 during 2003.

-17-

The primary reason for the increase in cash and equivalents was the increase in
net income of $3.9 million.

The Company had a revolving credit facility with Bank One, N.A. that
expired May 31, 2003. The Company had no borrowings in 2002 or 2003. The Company
has no alternative financing plan, nor does it anticipate that one will be
necessary. Cash flows were used to pay for the funding of the Company's
investment in and the continued development of oil and gas properties and to
repurchase Units pursuant to the Repurchase Right. The Company repurchased
34,034 Units at a price of $8.44 per Unit on June 30, 2003. The Company also
used cash flows to make cash distributions, which totaled $7.2 million.

The following table summarizes the Company's financial position at
December 31, 2003 and December 31, 2002:

December 31, 2003 December 31, 2002
---------------------- ----------------------
Amount % Amount %
---------------------- ----------------------
(Amounts in Thousands) (Amounts in Thousands)

Working capital $12,590 22% $ 7,530 15%
Property and equipment (net) 44,252 78 43,848 85
Other 121 - 130 -
------- --- ------- ---
Total $56,963 100% $51,508 100%
======= === ======= ===

Long-term liabilities $ 1,035 2% $ - -%
Deferred income taxes - - - -
Partners' equity 55,928 98 51,508 100
------- --- ------- ---
Total $56,963 100% $51,508 100%
======= === ======= ===

Cash Flows from Operating, Investing and Financing Activities

The Company generated almost all of its cash sources from operating
activities. During the years ended 2003 and 2002, cash provided by operations
was used to fund the development of additional oil and gas properties,
repurchase of Units pursuant to the Repurchase Right and distributions to
partners.

-18-

The following table summarizes the Company's Statements of Cash Flows
for the years ended December 31, 2003 and 2002:

2003 2002
---------------- ----------------
Dollars % Dollars %
-------- ---- -------- ----
(Amounts in Thousands)

Operating Activities:
Net income before adjustments $ 11,951 68% $ 8,004 52%
Adjustments 5,525 32 4,565 29
-------- ---- -------- ----
Cash flow from operations
before working capital
changes 17,476 100 12,569 81
Changes in working capital (422) (2) 3,015 19
-------- ---- -------- ----
Net cash provided by
operating activities 17,054 98 15,584 100
Investing Activities:
Proceeds received on receivables
from officers and employees 472 3 197 1
Advances disbursed to officers
and employees (291) (2) (162) (1)
Purchase of property and
equipment (4,876) (28) (4,186) (26)
Proceeds on sale of other assets
and equipment 82 - 48 -
-------- ---- -------- ----
Net cash (used) by investing
activities (4,613) (27) (4,103) (26)
Financing Activities:
Distributions (7,245) (41) (7,281) (47)
Repurchase of Units (287) (2) (127) (1)
Debt repayments - - (512) (3)
-------- ---- -------- ----
Net cash (used) by financing
activities (7,532) (43) (7,920) (51)
-------- ---- -------- ----
Increase (decrease) in cash
and equivalents 4,909 28 3,561 23

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

As the above table indicates, the Company's cash flow from operations
before working capital changes during the twelve months of 2003 and 2002
represented 100% and 81%

-19-

of total cash sources, respectively. Changes in working capital other than cash
and equivalents decreased cash by $422,000 during 2003 and increased cash by
$3.0 million during 2002. The decrease in short-term investments at December 31,
2002 compared to December 31, 2001 is the result of the Company's selling of
marketable corporate debt securities and investing excess cash flows in a high
balance savings account. The increase in accounts receivable at December 31,
2003 compared to December 31, 2002 is the result of higher natural gas
production volumes and an increase in gas and oil prices. Total production
revenues receivable as of December 31, 2003 amounted to $4.0 million compared to
$3.6 million at December 31, 2002.

The Company's cash flows used by investing activities increased
$510,000, or 12%, during 2003 as compared with 2002. The Company's cash flows
used by investing activities increased $860,000, or 27%, during 2002 as compared
with 2001. The primary reason for the increase in cash flows used by investing
activities in 2003 and 2002 was an increase in the purchase of property and
equipment. The purchase of property and equipment increased $690,000, or 16%,
during 2003 as compared with 2002. The purchase of property and equipment
increased $791,000, or 23%, during 2002 as compared with 2001.

The Company's cash flows used by financing activities decreased
$388,000, or 5%, during 2003 as compared with 2002. The reasons for this
decrease were that distributions to Unitholders decreased $37,000, payments on
the repurchase of Units increased $160,000 and payments on debt decreased
$512,000 during 2003. The Company's cash flows used by financing activities
decreased $2.2 million, or 22%, during 2002 as compared with 2001. The reasons
for this decrease were that distributions to Unitholders decreased $1.6 million
although payments on debt increased $386,000 during 2002. Additionally, payments
on the repurchase of Units decreased $1.0 million, or 89%, during 2002 as
compared with 2001.

The Company's ending cash and equivalents balance of $9.6 million at
December 31, 2003, as well as on-going monthly operating cash flows, should be
adequate to meet short-term cash requirements. The Company has established a
quarterly distribution and management believes the payment of such distributions
will continue at least through 2004. The Company has paid a quarterly
distribution every quarter since July 1991. Minimum cash distributions are
estimated to be $723,000 per quarter ($.125 per Unit). The Company intends to
distribute $2.9 million ($.50 per Unit) in April 2004 from existing cash and
equivalents.

Capital expenditures for the development of oil and gas properties and
the acquisition of undeveloped leasehold acreage have increased over recent
years. The Company drilled or participated in the drilling of an additional 46
drillsites in 2003. The Company's share of these drillsites amounts to 18.87 net
developed properties. The Company's share of proved gas reserves increased by
3.8 BCF, or 9%, between December 31, 2002 and December 31, 2003, while proved
oil reserves increased by 4,000 barrels, or 1%, between December 31, 2002 and
December 31, 2003. The Company continues to develop primarily natural gas
fields, as represented by the discovery and addition of 1.5 BCF of natural gas
versus 9,000 barrels of crude oil during 2003. The Standardized Measure of
Discounted Future Net Cash Flows of the Company's reserves increased by $33.9
million between December 31, 2002 and December 31, 2003. The primary reason for
this increase was due to increases in natural gas and crude oil

-20-

prices and related upward revisions in quantities of oil and gas reserves
between December 31, 2002 and December 31, 2003. Based on historical experience,
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 34,034, 22,401 and 117,488 Units during
2003, 2002 and 2001 pursuant to the Repurchase Right at a price of $8.44, $5.66
and $9.73 per Unit, respectively. The Repurchase Right to be conducted in 2004
will result in Unitholders being offered a price of $12.44 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 2004
offering pursuant to the Repurchase Right is 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, 2003, 2002 and 2001.
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:

-21-

Year Ended December 31,
-----------------------
2003 2002 2001
---- ---- ----

Revenues:
Oil and gas sales 98% 97% 97%
Well management and operating 2 3 3
---- --- ---
Total Revenues 100 100 100
Expenses:
Production costs 13 16 15
Well management and operating 1 1 1
Depreciation, depletion and amortization 23 26 28
Abandonment of oil and gas properties 1 1 1
General and administrative 6 8 8
Other expense (income) (1) - (1)
Cumulative effect of accounting change 2 - -
Income taxes - - -
---- --- ---
Total Expenses 45 52 52
---- --- ---
Net income 55% 48% 48%
==== === ===

Revenues for the year ended December 31, 2003 increased $5.1 million,
or 30%, compared to the same period in 2002. Revenues for the year ended
December 31, 2002 increased $496,000, or 3%, compared to the same period in
2001. These changes were due primarily to increases in crude oil and natural gas
sales between the periods involved.

Oil and gas sales increased $5.0 million, or 31%, from 2002 to 2003.
This increase was the result of increased natural gas production and higher
natural gas and crude oil prices. The Company's gas production increased by
373,000 MCF. The primary reason for this increase was due to increased
production resulting from the Company developing additional oil and gas
properties and increased production during summer months due to higher pricing.
The average price received per MCF increased from $3.98 to $4.73 from 2002 to
2003. Oil sales were higher due primarily to an increase in the average sales
price of oil from $22.33 to $27.93 per barrel from 2002 to 2003. Additionally,
oil production increased by 3,000 barrels. Gas sales accounted for 90%, 90% and
89% of total oil and gas sales in 2003, 2002 and 2001, respectively. Oil and gas
sales increased $449,000, or 3%, from 2001 to 2002. The primary reasons for this
increase in oil and gas sales between 2001 and 2002 were higher natural gas
production and prices. The Company's gas production increased by 97,000 MCF. The
average price received per MCF increased from $3.93 to $3.98. The average price
received per barrel decreased from $22.57 to $22.33.

Production costs increased $237,000, or 9%, and $199,000, or 8%, during
2003 and 2002, respectively. The primary reason for these increases was an
increase in the number of producing wells. Depreciation, depletion and
amortization increased $557,000, or 13%, between 2002 and 2003. The primary
reason for this increase is increased production of oil and gas for both new and
existing wells during 2003 compared to 2002. Depreciation, depletion and
amortization decreased $63,000, or 1%, between 2001 and 2002.

-22-

Well management and operating revenues increased $42,000, or 8%, from
2002 to 2003. Well management and operating costs increased $33,000, or 17%,
from 2002 to 2003. Well management and operating revenues increased $48,000, or
11%, from 2001 to 2002. Well management and operating costs increased $19,000,
or 11%, from 2001 to 2002. The reason for these increases in well management and
operating revenues and costs was due to an increase in Company operated oil and
gas interests. The Company added approximately 20 oil and gas properties to its
existing operations during 2002.

Abandonments of oil and gas properties decreased $100,000 between 2002
and 2003 and remained constant between 2001 and 2002. This decrease was
attributable to a reduction in abandonments of oil and gas properties.

General and administrative expenses decreased $31,000, or 2%, between
2002 and 2003, and increased $35,000, or 3%, between 2001 and 2002. Overall,
general and administrative expenses have remained relatively constant over the
last few years.

Net other income amounted to $141,000, $47,000 and $178,000 in 2003,
2002 and 2001, respectively. In 2003 and 2002, interest expense decreased as a
result of lower interest rates and debt reductions.

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 $3.9 million (after reduction for the cumulative
effect of change in accounting principle of $471,545), or 49%, between 2002 and
2003. Net income increased $162,000, or 2%, between 2001 and 2002. The increases
were primarily the result of increases in oil and gas sales. Net income
represented 55%, 48% and 48% of total revenues during the years ended December
31, 2003, 2002 and 2001, respectively.

APPLICATION OF CRITICAL ACCOUNTING POLICIES

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

Capitalized costs of proved properties, after considering estimated
dismantlement and abandonment costs and estimated salvage values, are amortized
by the unit-of-production method based upon estimated proved developed reserves.
Depletion, depreciation and amortization on proved properties amounted to $4.9
million, $4.4 million and $4.4 million for the years ended December 31, 2003,
2002 and 2001, respectively.

-23-

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. In 2003, the Company adopted SFAS No.
143, "Accounting for Asset Retirement Obligations." SFAS No. 143 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 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. Historically, and consistent with industry practice, the
Company determined that the cost of plugging and abandoning its oil and gas
properties would be offset by proceeds received from salvage. The Company
recorded a non-cash charge of approximately $500,000 as the cumulative effect of
a change in accounting principle, an increase to oil and gas properties of
approximately $400,000 and a non-current liability of approximately $900,000 in
connection with the adoption of SFAS No. 143.

The estimated liability is based on historical experience in plugging
and abandoning wells, estimated remaining lives of those wells based on reserves
estimates, estimates of the external cost to 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 could occur due to changes in estimates of plugging and
abandonment costs or remaining lives of the wells, or if federal or state
regulators enact new plugging and abandonment requirements.

Revenue Recognition. The Company recognizes revenue from oil and gas
production as it is extracted and sold from the properties. Other revenue is
recognized at the time it is earned and the Company has a contractual right to
such revenue.

The Company participates (and may act as drilling contractor) with
unaffiliated joint venture partners 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

-24-

property(ies). Generally, the joint venture partners 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 consist principally
of drilling and development costs the Company has advanced or incurred on behalf
of joint venture partners. The Company earns and receives monthly management and
operating fees from certain joint venture partners after the properties are
completed and placed into production.

NEW ACCOUNTING STANDARDS

In December 2002, the Financial Accounting Standards Board ("FASB")
issued SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and
Disclosure," that, among other provisions, amends SFAS No. 123, "Accounting for
Stock-Based Compensation," to provide alternative methods of transition to the
fair value method of accounting for stock-based employee compensation. SFAS No.
148 also amends the disclosure provisions of SFAS No. 123 and APB Opinion No.
28, "Interim Financial Reporting." The Statement does not amend SFAS No. 123 to
require companies to account for employee stock options using the fair value
method. The Statement is effective for fiscal years beginning after December 15,
2002.

In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement
133 on Derivative Instruments and Hedging Activities." This statement amends and
clarifies financial reporting for derivative instruments, including certain
derivative instruments embedded in other contracts and for hedging activities
under SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities." This statement is effective for contracts entered into or modified
after June 30, 2003, and for hedging relationships designated after June 30,
2003.

In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity." This
statement establishes standards for how an issuer classifies and measures
certain financial instruments with characteristics of both liabilities and
equity. SFAS No. 150 was originally to be effective for financial instruments
entered into or modified after May 31, 2003, and otherwise was to be effective
at the beginning of the first interim period beginning after June 15, 2003. In
November 2003, FASB issued FASB Staff Position 150-3 which delays or defers
indefinitely the effective date of certain provisions of SFAS No. 150.

In January 2003, the FASB issued Interpretation No. 46 ("FIN 46"),
"Consolidation of Variable Interest Entities," an interpretation of Accounting
Research Bulletin No. 51. FIN 46 requires certain variable interest entities, or
VIEs, to be consolidated by the primary beneficiary of the entity if the equity
investors in the entity do not have the characteristics of a controlling
financial interest or do not have sufficient equity at risk for the entity to
finance its activities without additional subordinated financial support from
other parties. FIN 46 is effective for all VIEs created or acquired after
January 31, 2003. For VIEs created or acquired prior to February 1, 2003, the
provisions of FIN 46 must be applied for the first interim or annual period
beginning after June 15, 2003. The Company currently has no contractual
relationship or other business relationship with a variable interest entity.

-25-

The adoption of the new standards did not, or is not expected to,
materially affect the Company's financial position and results of operations.

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 $35.00 in March 2004. As of March 20, 2004,
the posted field price in the Appalachian Basin area, the Company's principal
area of operation, was $34.75 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, 2003 are
comprised of oil reserves.

Natural gas prices have also fluctuated more recently. The Company's
average price of gas during 2001 amounted to $3.93 per MCF. The Company's
average price of gas during 2002 increased $.05 to $3.98 compared to 2001. The
Company's average price of gas during 2003 increased $.75 to $4.73 compared to
2002. The price of gas in the Appalachian Basin increased significantly
throughout 2000 and reached a high of more than $10.00 per MCF in January 2001.
More recently, the price of natural gas on the NYMEX settled for the month of
March 2003 at $9.13 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. As of March 20, 2004, the current
one-year strip price for Henry Hub Natural Gas on the NYMEX is $5.85 per MCF.
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 decreasing from $82.0 million at December 31, 2000 to $45.1 million at
December 31, 2001, and then increasing to $67.9 million at December 31, 2002 and
$101.8 million at December 31, 2003.

The Company's Standardized Measure of Discounted Future Net Cash Flows
increased by $33.9 million from December 31, 2002 to December 31, 2003 and
increased by $22.8 million from December 31, 2001 to December 31, 2002. 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

There were no borrowings during 2003 and 2002. 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

-26-

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.

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

Not applicable.

ITEM 9A. CONTROLS AND PROCEDURES

The Company's Chief Executive Officer and Chief Financial Officer have
evaluated the effectiveness of the design and operation of the Company's
disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based
upon that evaluation, such officers concluded that the Company's disclosure
controls and procedures are effective to ensure that information required to be
disclosed by the Company in the reports it files or submits under the Exchange
Act is recorded, processed, summarized and reported, within the time periods
specified in the Commission's rules and forms.

There have been no significant changes in the Company's internal
controls or in other factors that occurred during the last fiscal quarter that
has materially affected, or is reasonably likely to materially affect, the
Company's internal control over financial reporting.

-27-

EVERFLOW EASTERN PARTNERS, L. P.

2003 CONSOLIDATED FINANCIAL REPORT

F-1

EVERFLOW EASTERN PARTNERS, L. P.

CONTENTS

Page
----------

AUDITORS' REPORT ON THE FINANCIAL STATEMENTS 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

Independent Auditors' Report

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, 2003 and
2002, and the related consolidated statements of income, partners' equity, and
cash flows for each of the three years in the period ended December 31, 2003.
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 auditing standards generally
accepted in the United States of America. 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, 2003 and
2002, and the consolidated results of their operations and their cash flows for
each of the three years in the period ended December 31, 2003, in conformity
with accounting principles generally accepted in the United States of America.

HAUSSER + TAYLOR LLC

Cleveland, Ohio
March 17, 2004

F-3

EVERFLOW EASTERN PARTNERS, L. P.

CONSOLIDATED BALANCE SHEETS

December 31, 2003 and 2002

2003 2002
------------ ------------

ASSETS
CURRENT ASSETS
Cash and equivalents $ 9,598,801 $ 4,689,831
Accounts receivable:
Production 3,976,909 3,557,396
Officers and employees 40,666 220,764
Joint venture partners 59,982 30,630
Other 87,881 102,245
------------ ------------
Total current assets 13,764,239 8,600,866

PROPERTY AND EQUIPMENT
Proved properties (successful efforts accounting method) 122,422,677 118,513,983
Pipeline and support equipment 498,179 514,060
Corporate and other 1,708,140 1,587,219
------------ ------------
124,628,996 120,615,262
Less accumulated depreciation, depletion, amortization
and write down 80,377,333 76,766,803
------------ ------------
44,251,663 43,848,459
OTHER ASSETS 120,676 129,979
------------ ------------
$ 58,136,578 $ 52,579,304
------------ ------------

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

F-4

EVERFLOW EASTERN PARTNERS, L. P.

CONSOLIDATED BALANCE SHEETS

December 31, 2003 and 2002

2003 2002
----------- -----------

LIABILITIES AND PARTNERS' EQUITY

CURRENT LIABILITIES
Accounts payable $ 721,728 $ 746,421
Accrued expenses 452,169 324,627
----------- -----------
Total current liabilities 1,173,897 1,071,048

ASSET RETIREMENT OBLIGATIONS 1,034,685 -

COMMITMENTS AND CONTINGENCIES

LIMITED PARTNERS' EQUITY, SUBJECT TO REPURCHASE RIGHT
Authorized - 8,000,000 units
Issued and outstanding - 5,714,739 and 5,748,773
units, respectively 55,278,954 50,914,003

GENERAL PARTNER'S EQUITY 649,042 594,253
----------- -----------
Total partners' equity 55,927,996 51,508,256
----------- -----------
$58,136,527 $52,579,304

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, 2003, 2002 and 2001

2003 2002 2001
------------ ------------ ------------

REVENUES
Oil and gas sales $ 21,288,143 $ 16,254,014 $ 15,805,040
Well management and operating 543,948 501,561 453,774
Other 2,355 1,843 2,406
------------ ------------ ------------
21,834,446 16,757,418 16,261,220
DIRECT COST OF REVENUES
Production costs 2,855,663 2,618,399 2,419,260
Well management and operating 220,794 188,238 168,937
Depreciation, depletion and amortization 4,943,770 4,386,745 4,449,545
Abandonment of oil and gas properties 100,000 200,000 200,000
------------ ------------ ------------
Total direct cost of revenues 8,120,227 7,393,382 7,237,742
GENERAL AND ADMINISTRATIVE EXPENSE 1,363,267 1,394,121 1,359,378
------------ ------------ ------------
Total cost of revenues 9,483,494 8,787,503 8,597,120
------------ ------------ ------------
INCOME FROM OPERATIONS 12,350,952 7,969,915 7,664,100
OTHER INCOME (EXPENSE)
Interest income 104,587 69,515 222,764
Interest expense - (28,521) (44,702)
Gain on sale of property and equipment and other assets 36,609 5,974 -
------------ ------------ ------------
141,196 46,968 178,062
------------ ------------ ------------
INCOME BEFORE INCOME TAXES AND
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE 12,492,148 8,016,883 7,842,162
INCOME TAXES 69,303 12,793 -
------------ ------------ ------------
INCOME BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE 12,422,845 8,004,090 7,842,162

CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE 471,545 - -
------------ ------------ ------------
NET INCOME $ 11,951,300 $ 8,004,090 $ 7,842,162
------------ ------------ ------------
Allocation of Partnership Net Income
Limited Partners $ 11,813,013 $ 7,911,924 $ 7,752,932
General Partner 138,287 92,166 89,230
------------ ------------ ------------
$ 11,951,300 $ 8,004,090 $ 7,842,162
------------ ------------ ------------
Net income per unit:
Before cumulative effect of change in accounting principle $ 2.14 $ 1.37 $ 1.33
Cumulative effect of change in accounting principle (0.08) - -
------------ ------------ ------------
Net income per unit $ 2.06 $ 1.37 $ 1.33
------------ ------------ ------------

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, 2003, 2002 and 2001

2003 2002 2001
------------ ------------ ------------

PARTNERS' EQUITY - JANUARY 1 $ 51,508,256 $ 50,911,995 $ 53,043,829

Net income 11,951,300 8,004,090 7,842,162

Cash distributions ($1.25 per unit in 2003, $1.25 per
unit in 2002 and $1.50 per unit in 2001) (7,244,313) (7,281,039) (8,830,838)

Purchase and retirement of Units (287,247) (126,790) (1,143,158)
------------ ------------ ------------
PARTNERS' EQUITY - DECEMBER 31 $ 55,927,996 $ 51,508,256 $ 50,911,995
------------ ------------ ------------

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, 2003, 2002 and 2001

2003 2002 2001
------------ ------------ ------------

CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 11,951,300 $ 8,004,090 $ 7,842,162
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 4,989,909 4,421,028 4,508,950
Abandonment of oil and gas properties 100,000 200,000 200,000
Gain on sale of property and equipment and other
assets (36,609) (5,974) -
Cumulative effect of change in accounting principle 471,545 - -
Deferred income taxes - (50,000) -
Changes in assets and liabilities:
Accounts receivable (448,865) (991,445) 596,362
Short-term investments - 3,790,562 (167,188)
Other current assets 14,364 (54,247) 31,731
Other assets 9,303 (20,407) (6,555)
Accounts payable (24,693) 241,175 (513,713)
Accrued expenses 27,542 49,617 (17,674)
------------ ------------ ------------
Total adjustments 5,102,496 7,580,309 4,631,913
------------ ------------ ------------
Net cash provided by operating activities 17,053,796 15,584,399 12,474,075

CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds received on receivables from officers and
employees 471,545 197,364 273,447
Advances disbursed to officers and employees (291,447) (162,680) (122,053)
Purchase of property and equipment (4,875,596) (4,185,744) (3,394,808)
Proceeds on sale of property and equipment and
other assets 82,232 47,500 -
------------ ------------ ------------
Net cash used by investing activities (4,613,266) (4,103,560) (3,243,414)

CASH FLOWS FROM FINANCING ACTIVITIES
Distributions (7,244,313) (7,281,039) (8,830,838)
Repurchase of Units (287,247) (126,790) (1,143,158)
Payments on debt including revolver - (512,014) (125,808)
------------ ------------ ------------
Net cash used by financing activities (7,531,560) (7,919,843) (10,099,804)
------------ ------------ ------------
NET INCREASE (DECREASE) IN CASH AND
EQUIVALENTS 4,908,970 3,560,996 (869,143)

CASH AND EQUIVALENTS - JANUARY 1 4,689,831 1,128,835 1,997,978
------------ ------------ ------------
CASH AND EQUIVALENTS - DECEMBER 31 $ 9,598,801 $ 4,689,831 $ 1,128,835
------------ ------------ ------------

Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest $ - $ 28,521 $ 42,656
Income taxes 60,000 80,000 -

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

Capitalized costs of proved properties, after considering
estimated dismantlement and abandonment costs and estimated
salvage values, are amortized by the unit-of-production method
based upon estimated proved developed reserves. Depletion,
depreciation and amortization on proved properties amounted to
$4,801,170, $4,345,208 and $4,417,473 for the years ended
December 31, 2003, 2002 and 2001, 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.

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
$100,000, $200,000 and $200,000 during 2003, 2002 and 2001,
respectively, to provide for impairment on certain of its oil
and gas properties.

Pipeline and support equipment and other corporate property
and equipment are depreciated principally on the straight-line
method over their estimated useful lives (pipeline and support
equipment - 10 years, other corporate equipment - 3 to 7
years, other corporate property - building and improvements
with a cost of $1,154,270 - 40 years). Depreciation on
pipeline and support equipment and other corporate property
and equipment amounted to $95,901, $75,820 and $91,477 for the
years ended December 31, 2003, 2002 and 2001, respectively.

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

F-10

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

G. Asset Retirement Obligations - In 2003, the Company adopted
SFAS No. 143, "Accounting for Asset Retirement Obligations."
SFAS No. 143 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
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. Historically, and consistent with industry
practice, the Company determined that the cost of plugging and
abandoning its oil and gas properties would be offset by
proceeds received from salvage. The Company recorded a
non-cash charge of approximately $500,000 as the cumulative
effect of a change in accounting principle, an increase to oil
and gas properties of approximately $400,000 and a non-current
liability of approximately $900,000 in connection with the
adoption of SFAS No. 143.

The estimated liability is based on historical experience in
plugging and abandoning wells, estimated remaining lives of
those wells based on reserves estimates, estimates of the
external cost to 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 could occur due to changes in
estimates of plugging and abandonment costs or remaining lives
of the wells, or if federal or state regulators enact new
plugging and abandonment requirements.

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 year ended December 31, 2003:

Asset
Retirement
Obligations
-----------

Upon adoption $ 942,419
Liabilities incurred 99,428
Liabilities settled -
Accretion 92,838
-----------
Total ($100,000 current) $ 1,134,685
===========

F-11

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

G. Asset Retirement Obligations (Continued)
For 2003, accretion expense is included in depreciation,
depletion and amortization in the Company's consolidated
statements of operations and 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 pro forma effects had SFAS
No. 143 been applied during prior periods would have reduced
the Company's net income and net income per unit by
approximately $85,000 and $.01, respectively, in 2002 and
2001.

H. Revenue Recognition - The Company recognizes revenue from oil
and gas production as it is extracted and sold from the
properties. Other revenue is recognized at the time it is
earned and the Company has a contractual right to such
revenue.

The Company participates (and may act as drilling contractor)
with unaffiliated joint venture partners 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 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 consist principally of drilling and
development costs the Company has advanced or incurred on
behalf of joint venture partners. The Company earns and
receives monthly management and operating fees from certain
joint venture partners after the properties are completed and
placed into production.

I. 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.

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 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.

F-12

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

J. 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 5,731,756, 5,759,974 and 5,829,918 in
2003, 2002 and 2001, respectively.

K. New Accounting Standards - In December 2002, the Financial
Accounting Standards Board ("FASB") issued SFAS No. 148,
"Accounting for Stock-Based, Compensation - Transition and
Disclosure," that, among other provisions, amends SFAS No.
123, "Accounting for Stock-Based Compensation," to provide
alternative methods of transition to the fair value method of
accounting for stock-based employee compensation. SFAS No. 148
also amends the disclosure provisions of SFAS No. 123 and APB
Opinion No. 28, "Interim Financial Reporting." The Statement
does not amend SFAS No. 123 to require companies to account
for employee stock options using the fair value method. The
Statement is effective for fiscal years beginning after
December 15, 2002.

In April 2003, the FASB issued SFAS No. 149, "Amendment of
Statement 133 on Derivative Instruments and Hedging
Activities." This statement amends and clarifies financial
reporting for derivative instruments, including certain
derivative instruments embedded in other contracts and for
hedging activities under SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." This statement
is effective for contracts entered into or modified after June
30, 2003, and for hedging relationships designated after June
30, 2003.

In May 2003, the FASB issued SFAS No. 150, "Accounting for
Certain Financial Instruments with Characteristics of both
Liabilities and Equity." This statement establishes standards
for how an issuer classifies and measures certain financial
instruments with characteristics of both liabilities and
equity. SFAS No. 150 was originally to be effective for
financial instruments entered into or modified after May 31,
2003, and otherwise was to be effective at the beginning of
the first interim period beginning after June 15, 2003. In
November 2003, FASB issued FASB Staff Position 150-3 which
delays or defers indefinitely the effective date of certain
provisions of SFAS No. 150.

F-13

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

K. New Accounting Standards (Continued)

In January 2003, the FASB issued Interpretation No. 46 ("FIN
46"), "Consolidation of Variable Interest Entities", an
interpretation of Accounting Research Bulletin No. 51. FIN 46
requires certain variable interest entities, or VIEs, to be
consolidated by the primary beneficiary of the entity if the
equity investors in the entity do not have the characteristics
of a controlling financial interest or do not have sufficient
equity at risk for the entity to finance its activities
without additional subordinated financial support from other
parties. FIN 46 is effective for all VIEs created or acquired
after January 31, 2003. For VIEs created or acquired prior to
February 1, 2003, the provisions of FIN 46 must be applied for
the first interim or annual period beginning after June 15,
2003. The Company currently has no contractual relationship or
other business relationship with a variable interest entity.

The adoption of the new standards did not, or is not expected
to, materially affect the Company's financial position and
results of operations.

NOTE 2. CREDIT FACILITIES AND LONG-TERM DEBT

The Company had a revolving line of credit that expired on May 31,
2003. The Company anticipates, although there is no assurance it will
be able to, entering into a new credit agreement for the purpose, if
necessary, 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 on the revolving line of credit
during 2003 and 2002. 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.

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.

F-14

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

NOTE 3. PARTNERS' EQUITY (CONTINUED)

The partnership agreement provides that Everflow will repurchase for
cash up to 10% of the then outstanding Units, to the extent unitholders
offer Units to Everflow for repurchase pursuant to the repurchase
right. The repurchase right entitles any unitholder, between May 1 and
June 30 of each year, to notify Everflow that he elects to exercise the
repurchase right and have Everflow acquire certain or all of his 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,
2003 calculation, is estimated to be $12.44 per Unit, net of the
distributions ($1.00 per Unit in total) expected to be made in January
and April 2004.

Units repurchased pursuant to the repurchase right, for each of the
four years in the period ended December 31, 2003, are as follows:

Per Unit
--------------------------------------
Calculated Units
Price for Less Outstanding
Repurchase Interim Net # of Units Following
Year Right Distributions Price Paid Repurchased Repurchase
- ---- ----- ------------- ---------- ----------- ----------

2000 $ 6.73 $.625 $ 6.11 206,531 5,888,662

2001 $ 10.35 $.625 $ 9.73 117,488 5,771,174

2002 $ 6.16 $ .50 $ 5.66 22,401 5,748,773

2003 $ 8.94 $ .50 $ 8.44 34,034 5,714,739

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,
------------------------------------------------------------------------------------
2003 2002 2001
------------------------ ------------------------ --------------------------
Amount % Amount % Amount %
------ - ------ - ------ -

Provision based on the
statutory rate (for taxable
income up to $10,000,000) $ 4,087,000 34.0 $ 2,726,000 34.0 $ 2,666,000 34.0

Tax effect of:
Non-taxable status o f the
Programs and Everflow (3,827,000) (31.8) (2,579,000) (32.2) (2,654,000)
Excess statutory depletion (70,000) (0.6) (60,000) (0.7) (70,000) (0.9)
Graduated tax rates , state
income tax and other - net (120,697) (1.0) (74,207) (1.0) 58,000 0.7
----------- ----- ----------- ----- ----------- ----

Total $ 69,303 0.6 $ 12,793 0.1 $ - -
=========== ===== =========== ===== =========== ====

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, 2003 and 2002, these deferred
tax items resulted in deferred tax liabilities of $537,000 and
$629,000, respectively. These liabilities have been fully offset by
deferred tax assets resulting from the tax benefit of EEI's percentage
depletion carryovers. At December 31, 2003 and 2002, EEI had percentage
depletion deduction carryforwards for tax purposes of approximately
$1,450,000 and $1,860,000, respectively. These carryforwards can be
carried forward indefinitely.

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 $169,035, $217,301 and
$76,275 for the years ended December 31, 2003, 2002 and 2001,
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 to
participate in the drilling and development of such wells. At December
31, 2003, the loans accrue interest at 3.0% 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 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 90%, 90% and 89% of total oil and gas sales in
2003, 2002 and 2001, respectively. Approximate percentages of total oil
and gas sales from significant purchasers for the years ended December
31, 2003, 2002 and 2001, respectively, were as follows:

Customer 2003 2002 2001
-------- ---- ---- ----

Dominion Field Services, Inc., its
affiliates and its predecessors
("Dominion") 48% 49% 45%
Ergon Oil Purchasing, Inc. ("Ergon
Oil") 10 8 11
Interstate Gas Supply, Inc. ("IGS") 23 23 25
-- -- --

81% 80% 81%
== == ==

F-17

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

NOTE 7. BUSINESS SEGMENTS, RISKS AND MAJOR CUSTOMERS (CONTINUED)

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. Credit losses have historically been minimal and
no valuation allowance was deemed necessary at December 31, 2003 and
2002. The Company expects that Dominion, Ergon Oil and IGS will be the
only major customers in 2004.

Over the ten years prior to 2002, the Company had been selling a
significant portion of its natural gas pursuant to Intermediate Term
Adjustable Price Gas Purchase Agreements with Dominion. The Company's
last remaining long-term agreement terminated during 2001 and was
replaced by a short-term contract, which obligates Dominion to
purchase, and the Company to sell and deliver, certain natural gas
production from the Company's wells throughout the contract periods. A
summary of significant gas purchase contracts, including weighted
average pricing provisions, with Dominion follows:

Nov Dec Jan Feb Mar Apr
2003 2003 2004 2004 2004 2004
---- ---- ---- ---- ---- ----

MCF 220,000 160,000 180,000 180,000 180,000 160,000
Price $ 4.82 $ 4.65 $ 4.77 $ 4.77 $ 4.77 $ 4.96

May Jun Jul Aug Sep Oct
2004 2004 2004 2004 2004 2004
---- ---- ---- ---- ---- ----

MCF 160,000 220,000 180,000 180,000 180,000 180,000
Price $ 4.96 $ 5.01 $ 5.00 $ 5.00 $ 5.00 $ 5.00

Nov Dec Jan Feb Mar Apr
2004 2004 2005 2005 2005 2005
---- ---- ---- ---- ---- ----

MCF 180,000 150,000 150,000 150,000 150,000 100,000
Price $ 5.76 $ 5.68 $ 5.68 $ 5.68 $ 5.68 $ 5.54

May Jun Jul Aug Sep Oct
2005 2005 2005 2005 2005 2005
---- ---- ---- ---- ---- ----

MCF 100,000 100,000 100,000 100,000 100,000 100,000
Price $ 5.54 $ 5.54 $ 5.54 $ 5.54 $ 5.54 $ 5.54

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 a short-term contract with IGS, which obligates
IGS to purchase, and the Company to sell and deliver, certain
quantities of natural gas production on a monthly basis throughout the
contract periods. A summary of significant gas purchase contracts,
including weighted average pricing provisions, with IGS follows:

Nov Dec Jan Feb Mar Apr
2003 2003 2004 2004 2004 2004
---- ---- ---- ---- ---- ----

MCF 120,000 80,000 90,000 90,000 90,000 80,000
Price $ 4.53 $ 4.39 $ 4.54 $ 4.54 $ 4.54 $ 4.83

May Jun Jul Aug Sep Oct
2004 2004 2004 2004 2004 2004
---- ---- ---- ---- ---- ----

MCF 80,000 110,000 80,000 80,000 80,000 80,000
Price $ 4.83 $ 4.83 $ 4.83 $ 4.83 $ 4.83 $ 4.83

Nov Dec Jan Feb Mar Apr
2004 2004 2005 2005 2005 2005
---- ---- ---- ---- ---- ----

MCF 120,000 90,000 90,000 90,000 90,000 60,000
Price $ 6.20 $ 6.14 $ 6.14 $ 6.14 $ 6.14 $ 5.72

May Jun Jul Aug Sep Oct
2005 2005 2005 2005 2005 2005
---- ---- ---- ---- ---- ----

MCF 60,000 60,000 60,000 60,000 60,000 60,000
Price $ 5.72 $ 5.72 $ 5.72 $ 5.72 $ 5.72 $ 5.72

As detailed above, the price paid for natural gas purchased by Dominion
and IGS varies based on quantities locked in by the Company from time
to time. Natural gas sold under these contracts in excess of the locked
in prices are sold at the month's closing price plus basis adjustments,
as per the contracts. As of December 31, 2003, natural gas purchased by
Dominion covers production from approximately 480 gross wells, while
natural gas purchased by IGS covers production from approximately 220
gross wells. Production from the Dominion and IGS contract wells
comprises more than 75% of the Company's natural gas sales.

NOTE 8. COMMITMENTS AND CONTINGENCIES

Everflow paid a dividend in January 2004 of $.50 per Unit. The
distribution amounted to approximately $2,891,000.

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 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.

F-19

EVERFLOW EASTERN PARTNERS, L. P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

NOTE 9. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

The following is a summary of selected quarterly financial data
(unaudited) for the years ended December 31, 2003 and 2002:

Quarters Ended
--------------------------------------------------------
March 31 June 30 September 30 December 31
-------- ------- ------------ -----------

2003
Revenues $4,586,731 $4,696,833 $6,127,917 $6,422,965
Income from operations 2,197,554 2,600,607 3,452,866 4,099,925
Income before cumulative
effect of change in
accounting principle 2,222,540 2,626,143 3,462,290 4,111,872
Net income 1,750,995 2,626,143 3,462,290 4,111,872
Income per unit before
cumulative effect of
change in accounting
principle 0.38 0.45 0.60 0.71
Net income per unit 0.30 0.45 0.60 0.71

Quarters Ended
--------------------------------------------------------
March 31 June 30 September 30 December 31
-------- ------- ------------ -----------

2002
Revenues $4,248,354 $3,440,791 $3,838,431 $5,229,842
Income from operations 1,730,635 1,516,254 1,784,596 2,938,430
Net income 1,763,611 1,555,732 1,789,796 2,894,951
Net income per unit .30 .27 .31 .50

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.

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."

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) (CONTINUED)

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

December 31,
----------------------------------------------
2003 2002 2001
---- ---- ----

Proved oil and gas properties $122,422,677 $118,513,983 $114,964,451
Pipeline and support equipment 498,179 514,060 504,222
------------ ------------ ------------
122,920,856 119,028,043 115,468,673
Accumulated depreciation, depletion,
amortization and write down 80,018,796 76,478,321 72,365,538
------------ ------------ ------------

Net capitalized costs $ 42,902,060 $ 42,549,722 $ 43,103,135
============ ============ ============

COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES

December 31,
------------------------------------------
2003 2002 2001
---- ---- ----

Property acquisition costs $ 461,803 $ 230,175 $ 234,786
Development costs 4,239,552 3,728,193 3,135,374

In 2003, 2002 and 2001, development costs include the purchase of
approximately $-0-, $222,000 and $309,000, 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

December 31,
---------------------------------------------
2003 2002 2001
---- ---- ----

Oil and gas sales $21,288,143 $16,254,014 $15,805,040
Production costs (2,855,663) (2,618,399) (2,419,260)
Depreciation, depletion and
amortization (4,943,770) (4,386,745) (4,449,545)
Abandonment of oil and gas
properties (100,000) (200,000) (200,000)
----------- ----------- -----------
13,388,710 9,048,870 8,736,235

Income tax expense 80,000 75,000 100,000
----------- ----------- -----------

Results of operations for oil and gas
producing activities (excluding
corporate overhead and financing
costs) $13,308,710 $ 8,973,870 $ 8,636,235
=========== =========== ===========

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, 2001 914,000 48,534,000
Extensions, discoveries and other
additions 35,000 1,940,000
Production (76,000) (3,583,000)
Revision of previous estimates (154,000) (4,966,000)
-------- ----------

Balance, December 31, 2001 719,000 41,925,000
Extensions, discoveries and other
additions 26,000 1,992,000
Production (73,000) (3,680,000)
Revision of previous estimates 27,000 3,070,000
-------- ----------
Balance, December 31, 2002 699,000 43,307,000
Extensions, discoveries and other
additions 9,000 1,509,000
Production (76,000) (4,053,000)
Revision of previous estimates 71,000 6,306,000
-------- ----------

Balance, December 31, 2003 703,000 47,069,000
======== ==========

PROVED DEVELOPED RESERVES:
December 31, 2000 914,000 48,534,000
December 31, 2001 719,000 41,925,000
December 31, 2002 699,000 43,307,000
December 31, 2003 703,000 47,069,000

The Company has not determined proved reserves associated with its
proved undeveloped acreage. At December 31, 2003 and 2002, the Company
had 430 and 640 net proved undeveloped acres, respectively. The
carrying cost of the proved undeveloped acreage that is included in
proved properties amounted to $417,441 and $372,544 at December 31,
2003 and 2002, 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,
------------------------------------
2003 2002 2001
---- ---- ----
(Thousands of Dollars)

Future cash inflows from sales of oil
and gas $311,816 $212,322 $138,032
Future production and development
costs 95,721 76,048 57,159
Future asset retirement obligations, net of
salvage 3,151 - -
Future income tax expense 4,841 2,782 1,675
-------- -------- --------
Future net cash flows 208,103 133,492 79,198
Effect of discounting future net cash
flows at 10% per annum 106,260 65,558 34,104
-------- -------- --------
Standardized measure of discounted
future net cash flows $101,843 $ 67,934 $ 45,094
======== ======== ========

CHANGES IN THE STANDARDIZED MEASURE OF
DISCOUNTED FUTURE NET CASH FLOWS

Year Ended December 31,
---------------------------------------
2003 2002 2001
---- ---- ----
(Thousands of Dollars)

Balance, beginning of year $ 67,934 $ 45,094 $ 81,974
Extensions, discoveries and other
additions 3,672 3,817 2,814
Development costs incurred 162 617 313
Revision of previous estimates 15,134 5,209 (5,833)
Sales of oil and gas, net of production
costs (18,432) (13,636) (13,386)
Net change in income taxes (933) (467) 1,042
Net changes in prices and production
costs 25,894 22,206 (30,076)
Accretion of discount 6,793 4,509 8,197
Other 1,619 585 49
--------- -------- --------
Balance, end of year $ 101,843 $ 67,934 $ 45,094
========= ======== ========

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)

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

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

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 20, 2004 are Everflow Management Corporation, an
Ohio corporation ("EMC"), Thomas L. Korner and William A. Siskovic, all of whom
are directors and/or officers of EEI, and Sykes Associates, a limited
partnership controlled 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 20, 2004 are as follows:

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

Robert F. Sykes 80 Chairman of the Board Chairman of the Board
and Director

Thomas L. Korner 50 President and Director President and Director

David A. Kidder 65 Treasurer None

William A. Siskovic 48 Vice President, Secretary, Vice President, Secretary-
Principal Financial and Treasurer, Principal
Accounting Officer and Financial and Accounting
Director 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

-28-

receive no compensation or fees for their services to EEI or their services on
behalf of the Company.

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

The directors and officers of EMC act 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.

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

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 of EEI and EMC since November 1995 and the
President and Treasurer of Everflow Nominee. 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 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.

David A. Kidder has been the Treasurer of EEI since June 1986 and has been
employed by EEI since April 1985. From 1983 to 1985, he was Treasurer of LGM
Corporation, Columbus, Ohio, an oil and gas service company; from 1982 to 1983,
he was Treasurer of OPEX, Inc., Columbus, Ohio, a producer of oil and gas; and
from 1980 to 1981, he was Treasurer of United Petroleum, Inc., Columbus, Ohio, a
producer of oil and gas. From 1973 to 1980, Mr. Kidder was involved in the oil
and gas industry in various financial and accounting capacities. Prior to that
time, Mr. Kidder practiced as a certified public accountant with Coopers &
Lybrand, certified public accountants. Mr. Kidder has a Bachelor of Arts Degree
in Accounting from the University of Cincinnati.

-29-

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.

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.

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 2003.

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.

The following table sets forth information concerning the
annual and long-term compensation for services in all capacities to the Company
for the fiscal years ended December 31, 2003, 2002 and 2001, of those persons
who were, at December 31, 2003: (i) the chief executive officer; and (ii) the
other highly compensated executive officer of the Company. The Chief Executive
Officer and such other executive officer are hereinafter referred to
collectively as the "Named Executive Officers."

-30-

SUMMARY COMPENSATION TABLE

Annual Compensation
-------------------------------------------------------
Other
Annual All Other
Name and Compen- Compen-
Principal Position Year Salary Bonus sation(2) sation (1)
------------------ ---- ------ ----- --------- ----------

Thomas L. Korner 2003 $ 96,600 $ 76,000 $ 3,030 $ 27,966
President 2002 84,000 66,000 2,088 19,332
2001 83,000 72,500 1,821 9,330

William A. Siskovic 2003 $ 96,600 $ 76,000 $ 1,891 $ 27,992
Vice President and 2002 84,000 66,000 2,264 19,313
Principal Financial and 2001 83,000 72,500 1,544 9,330
Accounting Officer

- ----------------------------
No Named Executive Officer received personal benefits or perquisites during
2003, 2002 and 2001 in excess of the lesser of $50,000 or 10% of his aggregate
salary and bonus.

(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.

(2) Includes amounts considered taxable wages with respect to the Company's
Group Term Life Insurance Plan.

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 it
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.

None of the officers of the Company has an employment agreement.

-31-

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

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 1.16% 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 22.17% of the outstanding
Units.

The following table sets forth certain information with
respect to the number of Units beneficially owned as of March 20, 2004 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 18.49 66.6666 66.6666
Thomas L. Korner 138,575 2.42 16.6667 16.6667
William A. Siskovic 71,731 1.26 16.6667 16.6667
All officers and directors as
a group (3 persons in EMC) 1,266,770 22.17 100.0000 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 1.15% 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, a New York limited
partnership comprised of Mr. Sykes and his wife as general partners and
four adult children as limited partners, 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.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

In the past, certain officers, directors and more than 10%
Unitholders of the Company have invested, and may in the future invest, in oil
and gas programs sponsored by EEI on the same terms as unrelated investors. 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

-32-

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 unrelated investors. In
the past, EEI loaned the officers of the Company the funds necessary to
participate in the drilling and development of such wells. The Company has
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.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Hausser + Taylor LLC served as the Company's independent
auditor for the year ended December 31, 2003. Aggregate fees for professional
services provided to the Company by Hausser + Taylor LLC for the years ended
December 31, 2003 and 2002 were as follows:

December 31,
-------------------------
2003 2002
---- ----

Audit fees $77,622 $78,051

Audit fees include fees associated with the annual audit and
the reviews of the Company's quarterly reports on Form 10-Q and for services
that are normally provided by the accountants in connection with statutory and
regulatory filings or engagements. Hausser & Taylor LLC did not charge the
Company any audit-related, tax or other fees for these years.

Hausser + Taylor LLC (the "Firm") has a continuing
relationship with American Express Tax and Business Services, Inc. ("TBS") from
which it leases auditing staff who are full time, permanent employees of TBS and
through which its shareholders provide non-audit services. As a result of this
arrangement, the Firm has no full time employees and, therefore, none of the
audit services performed were provided by permanent full time employees of the
Firm. The Firm manages and supervises the audit and audit staff, and is
exclusively responsible for the opinion rendered in connection with its
examination.

-33-

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a) (1) Financial Statements

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

Page(s)
-------

Auditors' Report on Audited Financial Statements 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) Reports on Form 8-K

The Company did not file any reports on Form 8-K during the
last quarter of its year ended December 31, 2003.

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

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

-34-

SIGNATURES

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

EVERFLOW EASTERN PARTNERS, L.P.

By: EVERFLOW MANAGEMENT LIMITED, LLC
General Partner

By: EVERFLOW MANAGEMENT CORPORATION
Managing Member

By: /s/ Robert F. Sykes Director March 26, 2004
--------------------------
Robert F. Sykes

By: /s/ Thomas L. Korner President and Director March 26, 2004
--------------------------
Thomas L. Korner

By: /s/ William A. Siskovic Vice President, March 26, 2004
-------------------------- Secretary-Treasurer
William A. Siskovic and Director (principal
financial and accounting
officer)

Exhibit No. Description
- ----------- -----------

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

3.2 Form of Agreement of Limited Partnership of the (1)
Registrant

3.3 General Partnership Agreement of Everflow (1)
Management Company

3.4 Articles of Incorporation of Everflow Management (1)
Corporation

3.5 Code of Regulations of Everflow Management (1)
Corporation

3.6 Shareholders Agreement for Everflow Management (1)
Corporation

10.1 Credit Agreement dated January 19, 1995 between (2)
Everflow Eastern, Inc. and Everflow Eastern Partners, L.P.
and Bank One, Texas, National Association

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

10.3 Amendment to Credit Agreement dated February 23, 1996 (5)
between Everflow Eastern, Inc. and Everflow Eastern
Partners, L.P. and Bank One, Texas, National Association

10.4 Second Amendment to Credit Agreement dated December 30, (5)
1996 between Everflow Eastern, Inc. and Everflow Partners,
L.P. and Bank One, Texas, National Association

10.5 Loan Modification Agreement dated June 16, 1997 between (6)
Bank One, N.A., Bank One, Texas, N.A. and Everflow
Eastern, Inc. and Everflow Eastern Partners, L.P.

10.6 Loan Modification Agreement dated May 29, 1998 between (7)
Bank One, N.A., Successor to Bank One, Texas, N.A., and
Everflow Eastern, Inc. and Everflow Eastern Partners L.P.

10.7 Articles of Organization of Everflow Management (8)
Limited, LLC

E-1

Exhibit No. Description
- ----------- -----------

10.8 Operating Agreement of Everflow Management Limited, (8)
LLC dated March 8, 1999

10.9 Loan Modification Agreement dated May 25, 1999 between (9)
Bank One, N.A., and Everflow Eastern, Inc. and Everflow
Eastern Partners, L.P.

10.10 Loan Modification Agreement dated September 19, 2000, (10)
between Bank One, N.A., and Everflow Eastern, Inc.
and Everflow Eastern Partners, L.P.

10.11 Loan Modification Agreement dated August 28, 2001 (11)
between Bank One, N.A., and Everflow Eastern, Inc.
and Everflow Eastern Partners, L.P.

14.1 Code of Ethics

21.1 Subsidiaries of the Registrant (4)

31.1 Certification of CEO

31.2 Certification of CFO

32.1 Certification of CEO Pursuant To 18 U.S.C. Section 1350,
As Adopted Pursuant To Section 906 Of The Sarbanes-Oxley
Act of 2002

32.2 Certification of CFO Pursuant To 18 U.S.C. Section 1350,
As Adopted 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.

(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.

(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.

(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.

(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.

E-2

Exhibit Index

(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.

(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.

E-3