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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, 2001
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
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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. _______
There were 4,509,734 Units of limited partnership interest held by
non-affiliates of the Registrant as of March 20, 2002. 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, 2001.
PART I
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ITEM 1. BUSINESS
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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
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performance, events or developments that the Company anticipates will occur in
the future, 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 such a difference include, but are not limited
to, the competition with 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 91% of the estimated total future cash inflows
related to the Company's oil and gas reserves as of December 31, 2001 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 259 (net)
wells. The Company serves as the operator of approximately 76% of the gross
wells and 86% 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 32
prospects in various stages of maturity representing approximately 700 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
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develop, oil and gas or conduct other activities associated with the ownership
of oil and gas production.
FUNDING FOR ACTIVITIES. The Company finances its current operations,
including undeveloped leasehold acquisition activities, through cash generated
from operations and the proceeds of borrowings. 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 a
revolving credit facility with Bank One, N.A., pursuant to which it had no
borrowings in 2001 and no principal indebtedness was outstanding as of March 20,
2002. 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 for the acquisition of undeveloped acreage for future
drilling and development and to fund the Company's costs of drilling and
completing wells. In addition, the Company could borrow funds 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 which
have not been pledged as collateral for its existing loans. 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,
2001, which aggregate $45,094,000 (Standardized Measure of Discounted Future Net
Cash Flows) with no bank debt outstanding under the revolving credit facility as
of December 31, 2001.
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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 $33.25 in September 2000. As of
March 20, 2002, the posted field price in the Appalachian Basin area, the
Company's principal area of operation, was $21.25 per barrel of oil. There can
be no assurance that prices will not be subject to continual fluctuations.
Future oil prices are difficult to predict because of the impact of worldwide
economic trends, supply and demand variables, and such non-economic factors as
the political impact on pricing policies by the Organization of Petroleum
Exporting Countries ("OPEC") and the possibility of supply interruptions. To the
extent the prices that the Company receives for its crude oil production decline
or remain at current levels, the Company's revenues from oil production will be
reduced accordingly.
Since January 1993, the Company has sold substantially all of its
crude oil production to Ergon Oil Purchasing, Inc.
NATURAL GAS. The deliverability and price of natural gas is subject
to various factors affecting the supply and demand of natural gas as well as the
effect of federal regulations. Prior to 2000, there had been a surplus of
natural gas available for delivery to pipelines and other purchasers. During
2000, decreases in worldwide energy production capability and increases in
energy consumption brought about a shortage in natural gas supplies. This
resulted in increases in natural gas prices throughout the United States,
including the Appalachian Basin. However, more recently during 2001, lower
energy consumption and increased natural gas supplies have reduced prices to
historical levels. 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 past ten years, 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 short-term contracts, 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 the
Company's gas purchase contracts with Dominion follows:
November 2001 through March 2002
The first 40,000 MCF per month is priced at $3.51 per MCF.
The next 50,000 MCF per month is priced at $4.73 per MCF.
The next 50,000 MCF per month is priced at $5.35 per MCF.
All gas in excess of 140,000 MCF per month is priced at the NYMEX
settled price plus $.10 up to the first 250,000 MCF in the aggregate
during the period.
All gas in excess of the above volumes is priced at the NYMEX settled
price plus $.45.
April 2002 through October 2002
The first 50,000 MCF per month is priced at $4.73 per MCF.
The next 50,000 MCF per month is priced at $5.35 per MCF.
The next 20,000 MCF per month is priced at $3.35 per MCF.
In the event the 250,000 MCF in the November 2001 through March 2002
period is not met, any remaining balance is priced at the NYMEX settled
price plus $.10 during the period.
All gas in excess of the above volumes is priced at the NYMEX settled
price plus $.45.
November 2002 through October 2003
The first 20,000 MCF per month is priced at $3.35 per MCF.
The next 20,000 MCF per month is priced at $4.00 per MCF.
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The next 20,000 MCF per month is priced at $4.10 per MCF.
All gas in excess of the above volumes is priced at NYMEX settled price
plus $.45.
November 2003 through March 2004
The first 20,000 MCF per month is priced at $4.05 per MCF.
Gas in excess of the above volumes has not been committed.
The Company also has short-term contracts with Interstate Gas Supply,
Inc. ("IGS"), which obligate IGS to purchase, and the Company to sell and
deliver certain quantities of natural gas production on a monthly basis
throughout the contract periods. A summary of the Company's gas purchase
contracts with IGS follows:
November 2001 through October 2002
The first 50,000 MCF per month is priced at $4.56 per MCF.
All gas in excess of the above volumes is priced at NYMEX settled price
plus $.42.
April 2002 through October 2002 and April 2003 through October 2003
The first 20,000 MCF per month is priced at $3.19 per MCF.
All gas in excess of the above volumes is priced at the NYMEX settled
price plus $.27.
November 2002 through March 2003
The first 20,000 MCF per month is priced at $3.19 per MCF.
The next 20,000 MCF per month is priced at $4.01 per MCF.
All gas in excess of the above volumes is priced at the NYMEX settled
price plus $.57.
November 2003 through March 2004
The first 20,000 MCF per month is priced at $4.10 per MCF.
All gas in excess of the above volumes is priced at the NYMEX settled
price plus $.57.
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. As of December 31, 2001, natural gas purchased by Dominion covers
production from approximately 420 gross wells, while natural gas purchased by
IGS covers production from approximately 190 gross
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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, 2001, with the exception of Dominion
and IGS, which accounted for approximately 50% and 27%, 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 2002.
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.
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
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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 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
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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 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
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possible discharge of oil into navigable waters; and the EPA will further
require permits to authorize the discharge of pollutants into navigable waters.
State and local permits or approvals may also be needed with respect to
waste-water discharges and air pollutant emissions. Violations of
environment-related lease conditions or environmental permits can result in
substantial civil and criminal penalties as well as potential court injunctions
curtailing operations. Such enforcement liabilities can result from prosecution
by public or private entities.
Various state and governmental agencies are considering, and some
have adopted, other laws and regulations regarding environmental protection
which could adversely affect the proposed business activities of the Company.
The Company cannot predict what effect, if any, current and future regulations
may have on the operations of the Company.
In addition, from time to time, prices for either oil or natural gas
have been regulated by the federal government, and such price regulation could
be reimposed at any time in the future.
OPERATING HAZARDS AND UNINSURED RISKS
The Company's oil and gas operations are subject to all operating
hazards and risks normally incident to drilling for and producing oil and gas,
such as encountering unusual formations and pressures, blow-outs, environmental
pollution and personal injury. The Company maintains such insurance coverage as
it believes to be appropriate taking into account the size of the Company and
its operations. Losses can occur from an uninsurable risk or in 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.
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CONFLICTS OF INTEREST
The Partnership Agreement grants the General Partner broad
discretionary authority to make decisions on matters such as the Company's
acquisition of or participation in a drilling prospect or a producing property.
To limit the General Partner's management discretion might prevent it from
managing the Company properly. However, because the business activities of the
affiliates of the General Partner on the one hand and the Company on the other
hand are the same, potential conflicts of interest are likely to exist, and it
is not possible to completely mitigate such conflicts.
The Partnership Agreement contains certain restrictions designed to
mitigate, to the extent practicable, these conflicts of interest. The agreement
restricts, among other things, (i) the cost at which the General Partner or its
affiliates may acquire properties from or sell properties to the Company; (ii)
loans between the General Partner, its affiliates and the Company, and interest
and other charges incurred in connection therewith; and (iii) the use and
handling of the Company's funds by the General Partner.
EMPLOYEES
As of March 20, 2002, the Company (either directly or indirectly
through EEI) had 16 full-time and two 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.
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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, 2001.
OIL (BBLS) GAS (MCF)
---------- ---------
Proved Developed 719,000 41,925,000
Proved Undeveloped -- --
---------- ----------
Total 719,000 41,925,000
========== ==========
-------------------------
(1) The Company has not determined proved reserves associated
with its proved undeveloped acreage. 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, 2001, 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 $138,032
Future production and development costs 57,159
Future income tax expense 1,675
--------
Future net cash flows 79,198
Effect of discounting future net cash flows
at 10% per annum 34,104
--------
Standardized measure of discounted future
net cash flows $ 45,094
========
---------------------------------
(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)
---------- --------- ------- ------- ------------------
2001 76,000 3,583,000 $ 22.57 $ 3.93 $ .60
2000 92,000 4,196,000 27.82 3.32 .47
1999 97,000 4,245,000 16.08 3.08 .55
----------------------
(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, 2001.
GROSS WELLS NET WELLS
--------------------------------------------------------------------------------------------
(1) (1) (1) (1)
Oil Gas Total Oil Gas Total
--------------------------------------------------------------------------------------------
80 946 1,026 56 667 723
----------------------------
(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 45,207 gross developed acres and 32,310 net
developed acres as of December 31, 2001. Developed acreage is that acreage
assignable to productive wells. The Company had approximately 700 gross and net
undeveloped acres as of December 31, 2001.
-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
--------------- --------------- --------------- ---------------
2001 33 15.14 - -
2000 26 11.28 1 .14
1999 22 12.40 2 .20
----------------------
(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 4 gross and 1.64 net
development wells since December 31, 2001. As of March 20, 2002, the Company had
2 gross and 0.70 net wells in the process of being drilled.
DELIVERY COMMITMENTS. The Company entered into various contracts with
Dominion and IGS which, subject to certain restrictions and adjustments,
obligate Dominion and IGS to purchase and the Company to sell all natural gas
production from certain contract wells. The contract wells comprise 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.
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, 2001,
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, 2002, there were 5,771,174 Units held by 1,443
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. Based upon the current number of Units outstanding, each
quarterly distribution of $0.125 per Unit would be approximately $730,000. The
Company made a quarterly distribution of $0.25 per Unit in January 2002 and
currently intends to make a quarterly distribution of $0.25 per Unit in April
2002 and quarterly distributions of at least $0.125 per Unit in July and October
2002.
REPURCHASE RIGHT.
- ----------------
The Partnership Agreement provides, that beginning in 1992 and
annually thereafter, the Company will 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 77,344, 206,531 and 117,488 of its Units of limited partnership
interest at a price of $5.79, $6.11 and $9.73 per Unit pursuant to the terms of
the Company's Offers to Purchase dated April 30, 1999, 2000 and 2001,
respectively. See Note 4 in the Company's financial statement for additional
information on the Repurchase Right.
-16-
ITEM 6. SELECTED FINANCIAL DATA
- -----------------------------------------------
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------------
2001 2000 1999 1998 1997
---------------------------------------------------------------------
Revenue ................................... $16,261,220 $16,921,139 $15,063,170 $16,558,366 $15,932,197
Net Income ................................ 7,842,162 8,590,757 5,445,941 6,897,089 5,696,407
Net Income Per Unit ....................... 1.33 1.42 .88 1.10 .90
Total Assets .............................. 52,254,265 55,043,294 55,422,986 56,612,953 54,760,106
Debt(1) ................................... 512,014 637,822 692,289 2,255,898 4,589,143
Cash Distributions Per Unit ............... 1.50 1.25 .625 .50 .50
- ------------------------------
(1) Debt includes the Company's long-term debt and borrowings under the
Company's revolving credit facility.
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 $7.0 million as of December 31, 2001
represented a $1.0 million decrease from December 31, 2000 due primarily to
decreases in cash and equivalents of $869 thousand and accounts receivable from
oil and gas production of $603
-17-
thousand during 2001. These were partially offset by a decrease in accounts
payable of $514 thousand. In August 2001, the Company entered into an agreement
that modified its prior credit agreement. The agreement provides for a revolving
line of credit in the amount of $4,000,000, all of which is available. The
revolving line of credit provides for interest payable quarterly at LIBOR plus
150 basis points with the principal due at maturity, May 31, 2003. The Company
anticipates renewing the facility on an every other year basis to minimize debt
origination, carrying and interest costs associated with long-term bank
commitments. The Company made no borrowings under the revolving credit
facilities during 2001. 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 117,488 Units at a price of $9.73 per Unit, or $1,143,158, on June
30, 2001. The Company also used cash flows to make quarterly Cash Distributions,
which totaled $8.8 million.
The following table summarizes the Company's financial position at
December 31, 2001 and December 31, 2000:
(Amounts in Thousands) DECEMBER 31, 2001 DECEMBER 31, 2000
--------------------- ---------------------
AMOUNT % AMOUNT %
------- ------- ------- -------
Working capital $ 6,985 14% $ 7,931 15%
Property and equipment (net) 44,325 86 45,639 85
Other 110 -- 103 --
------- ------- ------- -------
Total $51,420 100% $53,673 100%
======= ======= ======= =======
Long-term debt $ 458 1% $ 579 1%
Deferred income taxes 50 -- 50 --
Partners' equity 50,912 99 53,044 99
------- ------- ------- -------
Total $51,420 100% $53,673 100%
======= ======= ======= =======
CASH FLOWS FROM OPERATING, INVESTING AND FINANCING ACTIVITIES
The Company generated almost all of its cash sources from operating
activities. During the years ended 2001 and 2000, 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, 2001 and 2000:
(Amounts in Thousands) 2001 2000
---------------------------------------------------
DOLLARS % DOLLARS %
---------------------------------------------------
Operating Activities:
Net income before adjustments $ 7,842 59% $ 8,591 60%
Adjustments 4,709 35 4,968 35
-------- -------- -------- --------
Cash flow from operations
before working capital
changes 12,551 94 13,559 95
Changes in working capital (77) (1) (2,818) (20)
-------- -------- -------- --------
Net cash provided by
operating activities 12,474 93 10,741 75
Investing Activities:
Proceeds received on receivables
from officers and employees 274 2 249 2
Advances disbursed to officers
and employees (122) (1) (130) (1)
Purchase of property and
equipment (3,395) (25) (2,594) (18)
Purchase of other assets -- -- (64) --
Proceeds on sale of other assets
and equipment -- -- 1 --
-------- -------- -------- --------
Net cash (used) by investing
activities (3,243) (24) (2,538) (18)
Financing Activities:
Distributions (8,831) (66) (7,574) (53)
Repurchase of Units (1,143) (8) (1,262) (9)
Debt proceeds -- -- -- --
Debt repayments (126) (1) (54) --
-------- -------- -------- --------
Net cash (used) by financing
activities (10,100) (75) (8,890) (62)
-------- -------- -------- --------
Increase (decrease) in cash
and equivalents (869) (6) (687) (5)
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 cash equivalents.
-19-
As the above table indicates, the Company's cash flow from operations
before working capital changes during the twelve months of 2001 and 2000
represented 94% and 95% of total cash sources, respectively. Changes in working
capital other than cash and equivalents decreased cash by $77 thousand and
$2,818 thousand during 2001 and 2000, respectively. The decrease in accounts
receivable at December 31, 2001 compared to December 31, 2000 is the result of
lower production volumes. Total production revenues receivable as of December
31, 2001 amounted to $2.5 million compared to $3.1 million at December 31, 2000.
Due to lower production volumes, accounts payable relating to production as of
December 31, 2001 was also lower. Accounts payable amounted to $505 thousand as
of December 31, 2001 compared to $1,019 thousand at December 31, 2000. The
Company had investments in short-term marketable corporate debt securities of
$3.8 million and $3.6 million at December 31, 2001 and 2000, respectively.
The Company's cash flows used by investing activities increased $706
thousand, or 28%, during 2001 as compared with 2000. The Company's cash flows
used by investing activities decreased $464 thousand, or 15%, during 2000 as
compared with 1999. The primary reason for the increase in cash flows used by
investing activities in 2001 was an increase in the purchase of property and
equipment. The purchase of property and equipment increased $801 thousand, or
31%, during 2001 as compared with 2000. The purchase of property and equipment
decreased $821 thousand, or 24%, during 2000 as compared with 1999.
The Company's cash flows used by financing activities increased
$1,210 thousand, or 14%, during 2001 as compared with 2000. The primary reason
for this increase was that distributions to Unitholders increased $1,257
thousand. Payments on debt increased $71 thousand to $126 thousand during 2001.
The Company's cash flows used by financing activities increased $2,998 thousand,
or 51%, during 2000 as compared with 1999. The primary reason for this increase
was that distributions to Unitholders increased $3,693 thousand. Proceeds from
the issuance of debt decreased $2,175 thousand and payments on debt decreased
$3,684 thousand to $54 thousand during 2000. Additionallly, payments on the
repurchase of Units increased $814 thousand, or 182%, during 2000 as compared
with 1999.
The Company's ending cash and equivalents balance of $1.1 million and
short-term investments balance of $3.8 million at December 31, 2001, 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 2002. The Company has paid a quarterly distribution every quarter since
July 1991. Minimum cash distributions are estimated to be $730 thousand per
quarter ($.125 per Unit). The Company intends to distribute $1.5 million ($.25
per Unit) in April 2002 using the proceeds from its investments in marketable
corporate debt securities.
Capital expenditures for the development of oil and gas properties in
the Company and the acquisition of undeveloped leasehold acreage have decreased
compared with historical levels. The Company drilled or participated in the
drilling of an additional 33 drillsites in 2001. The Company's share of these
drillsites amounts to 15.14 net developed properties. The Company's share of
proved gas reserves decreased by 6.6 million MCFs, or 14%, between
-20-
December 31, 2000 and 2001, while proved oil reserves decreased by 195 thousand
barrels, or 21%, between December 31, 2000 and 2001. The Company continues to
develop primarily natural gas fields, as represented by the discovery and
addition of 1.9 million MCFs of natural gas versus 35 thousand barrels of crude
oil during 2001. The Standardized Measure of Discounted Future Net Cash Flows of
the Company's reserves decreased by $36.9 million between December 31, 2000 and
2001. The primary reason for this decrease was due to decreases in natural gas
and crude oil prices between December 31, 2000 and 2001. Management believes the
Company should be able to drill or participate in the drilling of 7 to 15 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 117,488, 206,531 and 77,344 Units during
2001, 2000 and 1999 pursuant to the Repurchase Right at a price of $9.73, $6.11
and $5.79 per Unit, respectively. The Company has, in the past, borrowed against
its credit facility to meet such obligations and could do so again in 2002,
although current cash flows would reduce borrowing requirements. The Repurchase
Right to be conducted in 2002 will result in Unitholders being offered a price
of $5.66 per Unit. The Company estimates it could need to borrow up to $3.3
million in the event the 2002 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, 2001, 2000 and 1999.
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,
----------------------------------
2001 2000 1999
------ ------ ------
Revenues:
Oil and gas sales 97% 97% 97%
Well management and operating 3 3 3
------ ------ ------
Total Revenues 100 100 100
Expenses:
Production costs 15 13 18
Well management and operating 1 1 1
Depreciation, depletion and amortization 28 27 32
Abandonment and write down
of oil and gas properties 1 2 4
General and administrative 8 8 11
Other expense (income) (1) (2) (1)
Income taxes -- -- (1)
------ ------ ------
Total Expenses 52 49 64
------ ------ ------
Net income 48% 51% 36%
====== ====== ======
Revenues for the year ended December 31, 2001 decreased $686
thousand, or 4%, compared to the same period in 2000. Revenues for the year
ended December 31, 2000 increased $1,858 thousand, or 12%, compared to the same
period in 1999. These changes were due primarily to changes in crude oil and
natural gas sales between the periods involved.
Oil and gas sales decreased $660 thousand, or 4%, from 2000 to 2001.
The primary reason for this decrease was the result of lower natural gas
production and lower crude oil production and oil prices. The Company's gas
production decreased by 613 thousand MCF. The primary reason for this decrease
was due to declining production from the Company's existing oil and gas
properties caused by numerous events including production restrictions resulting
from a warmer than usual fourth quarter in the Appalachian Basin. The average
price received per MCF increased from $3.32 to $3.93 from 2000 to 2001. Oil
sales were lower due primarily to a decrease in the average sales price of oil
from $27.82 to $22.57 per barrel from 2000 to 2001. Additionally, oil production
decreased by 16 thousand barrels. Gas sales accounted for 89%, 84% and 89% of
total oil and gas sales in 2001, 2000 and 1999, respectively. Oil and gas sales
increased $1.9 million, or 13%, from 1999 to 2000. The primary reason for this
increase in oil and gas sales between 1999 and 2000 was higher natural gas and
crude oil prices. The Company's gas production decreased by 49 thousand MCF, and
the average price received per MCF increased from $3.08 to $3.32.
Production costs increased $174 thousand, or 8%, and decreased $393
thousand, or 15%, during 2001 and 2000, respectively. The primary reason for the
increase in 2001 was an increase in the number of producing wells. Depreciation,
depletion and amortization decreased $61 thousand, or 1%, between 2000 and 2001.
The primary reason for this decrease is lower production volumes, although the
impact of the decrease in production volumes was offset by
-22-
lower reserves. Depreciation, depletion and amortization decreased $252
thousand, or 5%, between 1999 and 2000.
Well management and operating revenues increased $25 thousand, or 6%,
from 2000 to 2001. Well management and operating costs increased $45 thousand,
or 37%, from 2000 to 2001. The reason for these increases in well management and
operating revenues and costs was due to the increase in Company operated oil and
gas interests. Well management and operating revenues increased $7 thousand, or
2%, from 1999 to 2000. Well management and operating costs increased $16
thousand, or 15%, from 1999 to 2000.
Abandonments and write downs of oil and gas properties decreased $200
thousand between 2000 and 2001 and decreased $249 thousand between 1999 and
2000. These decreases were attributable to a reduction in the write down of oil
and gas properties and abandonments of oil and gas properties. During 2001 and
2000, the Company had no impairment on its oil and gas properties. During 1999,
the Company wrote down oil and gas properties by approximately $601 thousand to
provide for impairment on certain of its oil and gas properties.
General and administrative expenses increased $37 thousand, or 3%,
between 2000 and 2001, and decreased $294 thousand, or 18%, between 1999 and
2000. The primary reason for the increase during 2001 was an increase in
overhead costs associated with ongoing operations of the Company. In addition,
the decrease in general and administrative expenses between 1999 and 2000 was
the result of a reduction in personnel and related costs due to a decrease in
the level of activity in acquiring leasehold prospects and drilling activity.
Net other income amounted to $178 thousand, $271
thousand, and $77 thousand in 2001, 2000 and 1999, respectively. In 2001,
interest income decreased as a result of lower interest rates.
The Company is not a tax paying entity, and the net taxable income or
loss, other than the taxable income or loss attributable to EEI, is allocated
directly to its respective partners.
Net income decreased $749 thousand, or 9%, between 2000 and 2001. The
decrease was primarily the result of a decrease in oil and gas sales. Net income
increased $3.1 million, or 58%, between 1999 and 2000. The increase resulted
from increased oil and gas sales and the decreases in direct costs and general
and administrative expenses. Net income represented 48%, 51% and 36% of total
revenues during the years ended December 31, 2001, 2000 and 1999, respectively.
-23-
NEW ACCOUNTING STANDARDS
In June 1998, SFAS No. 133, "Accounting for Derivative Instruments
and Hedging Activities," was issued. SFAS No. 133 establishes accounting and
reporting standards for derivative instruments and hedging activities. SFAS No.
133, as amended by SFAS No. 137, is effective for all fiscal quarters of all
fiscal years beginning after June 15, 2000. In June 2001, the Financial
Accounting Standards Board ("FASB") issued SFAS No. 141, "Business
Combinations." SFAS No. 141 requires the purchase method of accounting for
business combinations initiated after June 30, 2001 and eliminates the
pooling-of-interest method and further clarifies the criteria to recognize
intangible assets separately from goodwill. The adoption of SFAS Nos. 133 and
141 had no material effect on the Company's financial statements.
In June 2001, FASB issued SFAS No. 142, "Goodwill and Other
Intangible Assets." Under SFAS No. 142, goodwill and intangible assets deemed to
have indefinite lives will no longer be amortized but will be subject to
periodic impairment tests. Other intangible assets will continue to be amortized
over their useful lives. SFAS No. 142 is effective for fiscal years beginning
after December 15, 2001. In June 2001, FASB issued SFAS No. 143, "Accounting for
Asset Retirement Obligations," which is effective the first quarter of fiscal
year 2003. SFAS 143 addresses financial accounting and reporting for obligations
associated with the retirement of long-lived assets and the associated asset
retirement cost. In August 2001, FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-lived Assets," which is effective the first
quarter of fiscal year 2002. SFAS No. 144 modifies and expands the financial
accounting and reporting for the impairment or disposal of long-lived assets
other than goodwill. The Company is still evaluating the impact of these new
standards, but at this time does not believe their adoption will have a
significant impact on its 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 $33.25 in September 2000. As of March 20,
2002, the posted field price in the Appalachian Basin area, the Company's
principal area of operation, was $21.25 per barrel of oil. Although the
Company's sales are affected by this type of price instability, the impact on
the Company is not as dramatic as might be expected since less than 9% of the
Company's total future cash inflows related to oil and gas reserves as of
December 31, 2001 are comprised of oil reserves.
Natural gas prices have also fluctuated more recently. Under the
various gas purchase agreements with Dominion Field Services, Inc. and its
affiliates (including The East Ohio Gas Company), adjustments to the price of
gas paid to the Company were based on 80% of the increase or decrease in
Dominion's average GCR rates. The Company's average price of gas during 1999
amounted to $3.08 per MCF. The Company's average price of gas during 2000
increased $.24 to $3.32 compared to 1999. The Company's average price of gas
during 2001
-24-
increased $.61 to $3.93 compared to 2000. 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. The Company's gas is currently sold under
short-term contracts where the price is determined using a monthly strip price.
The Company at times will lock-in a monthly strip 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, 2001, the
current one-year strip price for Henry Hub Natural Gas on the NYMEX is $3.42 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 increasing from $53.7 million at December 31, 1999 to $82.0 million at
December 31, 2000, and then decreasing to $45.1 million at December 31, 2001.
The Company's Standardized Measure of Discounted Future Net Cash
Flows decreased by $36.9 million from December 31, 2000 to December 31, 2001 and
increased by $28.3 million from December 31, 1999 to December 31, 2000. A
reconciliation of the Changes in the Standardized Measures of Discounted Future
Net Cash Flows is included in the Company's consolidated financial statements.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
- ------------------------------------------------------------------------
The Company is exposed to market risk from changes in interest rates
since it, at times, funds its operations through long-term and short-term
borrowings. The Company's primary interest rate risk exposure results from
floating rate debt with respect to the Company's revolving credit. At December
31, 2001, none of the Company's total long-term debt consisted of floating rate
debt.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
- -----------------------------------------------------
See attached pages F-1 to F-23.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
- -----------------------------------------------------------
ACCOUNTING AND FINANCIAL DISCLOSURE
-----------------------------------
Not applicable.
-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, 2002 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, 2002 are as follows:
Positions and Positions and
Name Age Offices With EEI Offices With EMC
- --------------------- --- ------------------------- --------------------------
Robert F. Sykes 78 Chairman of the Board Chairman of the Board
and Director
Thomas L. Korner 48 President and Director President and Director
David A. Kidder 63 Treasurer None
William A. Siskovic 46 Vice President, Secretary, Vice President, Secretary-
Principal Financial and Treasurer, Principal
Accounting Officer and Financial and Accounting
Director Officer and Director
-26-
.
All directors of EEI are elected to serve by the Company, which is EEI's sole
shareholder. All officers of EEI serve at the pleasure of the Board of
Directors. Directors and officers of EEI receive no compensation or fees for
their services to EEI or their services on behalf of the Company.
All directors and officers of EMC hold their positions with EMC
pursuant to a shareholders' agreement among EMC and such directors and officers.
The shareholders agreement controls the operation of EMC, provides for changes
in share ownership of EMC, and determines the identity of the directors and
officers of EMC as well as their replacement.
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.
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
-27-
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 2001.
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, 2001, 2000 and 1999, of those persons who were,
at December 31, 2001: (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."
-28-
SUMMARY COMPENSATION TABLE
Annual Compensation
----------------------------------------------------
Other
Annual All Other
Name and Compen- Compen-
Principal Position Year Salary Bonus sation sation (1)
------------------ ---- ------ ----- --------- ------------
Thomas L. Korner 2001 $ 83,000 $ 72,500 $ 1,821 $ 54,051(2)
President 2000 80,000 40,000 2,008 47,425(2)
1999 80,000 60,000 1,954 36,710(2)
William A. Siskovic 2001 83,000 72,500 1,544 44,955(3)
Vice President and 2000 80,000 40,000 1,749 40,201(3)
Principal Financial and 1999 80,000 60,000 1,326 28,420(3)
Accounting Officer
- -----------------------------------
No Named Executive Officer received personal benefits or perquisites during
2001, 2000 and 1999 in excess of the lesser of $50,000 or 10% of his aggregate
salary and bonus.
(1) Includes amounts received from participation in certain overriding
royalty interest arrangements organized by EEI. Also 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 50% of the first 6% of a
participant's salary reduction in 1999. Beginning in 2000, 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. The amounts attributable to the
Company's matching contribution vest immediately.
(2) Includes amounts received by Thomas L. Korner from participation in
certain overriding royalty interest arrangements organized by EEI of
$44,721, $40,225 and $28,310 in 2001, 2000 and 1999, respectively.
(3) Includes amounts received by William A. Siskovic from participation
in certain overriding royalty interest arrangements organized by EEI
of $35,625, $33,001 and $20,020 in 2001, 2000 and 1999,
respectively.
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.
-29-
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 1.1493% interest in the Company. The members and their
affiliates currently hold (in addition to the General Partner's interest in the
Company) 1,261,440 Units, representing approximately 21.86% of the outstanding
Units.
The following table sets forth certain information with respect to
the number of Units beneficially owned as of March 20, 2002 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 18.31 66.6666 66.6666
Thomas L. Korner 135,910 2.35 16.6667 16.6667
William A. Siskovic 69,066 1.20 16.6667 16.6667
All officers and directors as
a group (3 persons in EMC) 1,261,440 21.86 100.0000 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
-30-
anticipates that any such participation by individual members of the Company's
management would enable such individuals to participate in the drilling and
development of undeveloped drillsites on an equal basis with the Company or the
particular drilling program acquiring such drillsites, which participation would
be on a uniform basis with respect to all drilling conducted during a specified
time frame, as opposed to selective participation. Frequently, such
participation has been on more favorable terms than the terms which were
available to unrelated investors. Frequently, EEI loaned the officers of the
Company the funds necessary to participate in the drilling and development of
such wells. Such loans currently accrue interest at the rate of LIBOR plus 150
basis points per annum. As of December 31, 2001, the aggregate outstanding
balance of such indebtedness was approximately $4,000 and $73,000 owing from
Thomas L. Korner and William A. Siskovic, respectively.
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.
-31-
PART IV
-------
ITEM 14. 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-23
(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.
-32-
Exhibit Index
-------------
Exhibit No. Description
----------- -----------
4.1 Certificate of Limited Partnership of the (1)
Registrant dated September 13, 1990, as
filed with the Delaware Secretary of State
on September 14, 1990
4.2 Form of Agreement of Limited Partnership of (1)
the Registrant
4.3 General Partnership Agreement of Everflow (1)
Management Company
4.4 Articles of Incorporation of Everflow (1)
Management Corporation
4.5 Code of Regulations of Everflow Management (1)
Corporation
4.6 Shareholders Agreement for Everflow (1)
Management Corporation
4.7 Third Amended and Restated Loan Agreement, (2)
dated as of May 1, 1991 between Everflow
Eastern, Inc., the Registrant and the banks
listed therein, with National Bank of
Detroit as Agent
4.8 First Amendment to Third Amended and (5)
Restated Loan and Security Agreements dated
July 1, 1993, between Everflow Eastern,
Inc. and Everflow Eastern Partners, L.P.
and the banks listed therein, with National
Bank of Detroit as Agent
4.9 Revolving Credit Note to First Amendment to (5)
Third Amended and Restated Loan and
Security Agreement dated as of July 1, 1993
4.10 Credit Agreement dated January 19, 1995 (8)
between Everflow Eastern, Inc. and Everflow
Eastern Partners, L.P. and Bank One, Texas,
National Association
E-1
Exhibit Index
-------------
Exhibit No. Description
----------- -----------
4.11 Amendment to Credit Agreement dated (13)
February 23, 1996 between Everflow Eastern,
Inc. and Everflow Eastern Partners, L.P.
and Bank One, Texas, National Association
4.12 Second Amendment to Credit Agreement dated (13)
December 30, 1996 between Everflow Eastern,
Inc. and Everflow Partners, L.P. and Bank
One, Texas, National Association
4.13 Loan Modification Agreement dated June 16, (14)
1997 between Bank One, N.A., Bank One,
Texas, N.A. and Everflow Eastern, Inc. and
Everflow Eastern Partners, L.P.
4.14 Loan Modification Agreement dated May 29, (15)
1998 between Bank One, N.A., Successor to
Bank One, Texas, N.A., and Everflow
Eastern, Inc. and Everflow Eastern Partners
L.P.
4.15 Articles of Organization of Everflow (17)
Management Limited, LLC
4.16 Operating Agreement of Everflow Management (17)
Limited, LLC dated March 8, 1999
4.17 Loan Modification Agreement dated May 25, (18)
1999 between Bank One, N.A., and Everflow
Eastern, Inc. and Everflow Eastern
Partners, L.P.
4.18 Loan Modification Agreement dated September (19)
19, 2000, between Bank One, N.A., and
Everflow Eastern, Inc. and Everflow Eastern
Partners, L.P.
4.19 Loan Modification Agreement dated August (20)
28, 2001 between Bank One, N.A., and
Everflow Eastern, Inc. and Everflow Eastern
Partners, L.P.
10.1 Lease Agreement dated June 30, 1984 by and (1)
between Village Green Associates, Inc. and
Everflow Eastern, Inc.
10.2 Gas Purchase Agreement dated September 3, (3)
1991 by and between the Registrant and The
East Ohio Gas Company
E-2
Exhibit No. Description
----------- -----------
10.3 Intermediate Term Adjustable Price Gas (4)
Purchase Agreement, contract #10342, dated
October 9, 1992, between The East Ohio Gas
Company and Everflow Eastern Partners, L.P.
10.4 Quaker State Full Load Crude Oil Purchase (4)
Agreement dated January 13, 1993, between
Quaker State Oil Refining Corporation and
Everflow Eastern Partners, L.P.
10.5 Intermediate Term Adjustable Gas Purchase (6)
Agreement, Contract #10461, dated March 10,
1994, between The East Ohio Gas Company and
Everflow Eastern Partners, L.P.
10.6 Intermediate Term Adjustable Gas Purchase (7)
Agreement, Contract #10515, dated August
10, 1994, between The East Ohio Gas Company
and Everflow Eastern Partners, L.P.
10.7 Operating facility lease dated October 3, (9)
1995 between Everflow Eastern Partners,
L.P. and A-1 Storage of Canfield, Ltd.
10.8 Intermediate Term Adjustable Gas Purchase (11)
Agreement, Contract #11245, dated May 29,
1996, between The East Ohio Gas Company and
Everflow Eastern Partners, L.P.
10.9 Intermediate Term Adjustable Gas Purchase (11)
Agreement, Contract #11285, dated May 29,
1996, between The East Ohio Gas Company and
Everflow Eastern Partners, L.P.
10.10 One Year Term Gas Purchase Agreement dated (12)
August 1, 1996, between Everflow Eastern
Partners, L.P. and JDS Energy Corporation
10.11 One Year Term Gas Purchase Agreement dated (13)
January 20, 1997, between Everflow Eastern
Partners, L.P. and JDS Energy Corporation
10.12 Gas Purchase Agreement, Contract #11467, (16)
dated November 1, 1997, between Everflow
Eastern Partners, L.P. and CNG Energy
Services Corporation.
E-3
Exhibit No. Description
----------- -----------
10.13 One Year Term Gas Purchase Agreement dated (16)
November 1, 1998, between Everflow Eastern
Partners, L.P. and JDS Energy Systems, Inc.
22.1 Subsidiaries of the Registrant (10)
- --------------------
(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 Quarterly Report on Form 10-Q for the second quarter
ended June 30, 1991.
(3) Incorporated herein by reference to the appropriate exhibit to
Registrant's Annual Report on Form 10-K for the year ended December
31, 1991 (File No. 0-19279).
(4) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Annual Report on Form 10-K for the year ended December
31, 1992 (File No. 0-19279).
(5) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Quarterly Report on Form 10-Q for the second quarter
ended June 30, 1993.
(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, 1994.
(7) 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, 1994.
(8) 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).
(9) 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.
(10) 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).
(11) 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, 1996.
(12) 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, 1996.
(13) 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).
(14) 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.
(15) 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.
(16) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Annual Report on Form 10-K for the year ended December
31, 1998 (File No. 0-19279).
(17) 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.
(18) 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.
(19) 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.
(20) 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-4
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 27 , 2001
------------------------------ ----
Robert F. Sykes
By: /s/Thomas L. Korner President and Director March 27 , 2001
------------------------------ ----
Thomas L. Korner
By: /s/William A. Siskovic Vice President, March 27 , 2001
------------------------------ Secretary-Treasurer ----
William A. Siskovic and Director (principal
financial and accounting
officer)
EVERFLOW EASTERN PARTNERS, L. P.
2001 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-24
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, 2001 and
2000, and the related consolidated statements of income, partners' equity, and
cash flows for each of the three years in the period ended December 31, 2001.
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, 2001 and
2000, and the consolidated results of their operations and their cash flows for
each of the three years in the period ended December 31, 2001, in conformity
with accounting principles generally accepted in the United States of America.
HAUSSER + TAYLOR LLP
Cleveland, Ohio
March 14, 2002, except for Note 8,
dated March 20, 2002
F-3
EVERFLOW EASTERN PARTNERS, L. P.
CONSOLIDATED BALANCE SHEETS
December 31, 2001 and 2000
- --------------------------------------------------------------------------------
2001 2000
---- ----
ASSETS
------
CURRENT ASSETS
Cash and equivalents $ 1,128,835 $ 1,997,978
Accounts receivable:
Production 2,475,123 3,078,235
Officers and employees 255,448 406,842
Joint venture partners 121,458 114,708
Short-term investments 3,790,562 3,623,374
Other 47,998 79,729
------------ ------------
Total current assets 7,819,424 9,300,866
PROPERTY AND EQUIPMENT
Proved properties (successful efforts accounting method) 114,964,451 112,341,851
Pipeline and support equipment 504,222 504,222
Corporate and other 1,465,910 1,539,824
------------ ------------
116,934,583 114,385,897
Less accumulated depreciation, depletion, amortization
and write down 72,609,314 68,746,486
------------ ------------
44,325,269 45,639,411
OTHER ASSETS 109,572 103,017
------------ ------------
$ 52,254,265 $ 55,043,294
============ ============
The accompanying notes are an integral part of these financial statements.
F-4
EVERFLOW EASTERN PARTNERS, L. P.
CONSOLIDATED BALANCE SHEETS
December 31, 2001 and 2000
- --------------------------------------------------------------------------------
2001 2000
----------- -----------
LIABILITIES AND PARTNERS' EQUITY
--------------------------------
CURRENT LIABILITIES
Current portion of long-term debt $ 53,900 $ 58,595
Accounts payable 505,246 1,018,959
Accrued expenses 275,010 292,684
----------- -----------
Total current liabilities 834,156 1,370,238
LONG-TERM DEBT, NET OF CURRENT PORTION 458,114 579,227
DEFERRED INCOME TAXES 50,000 50,000
COMMITMENTS AND CONTINGENCIES
LIMITED PARTNERS' EQUITY, SUBJECT TO REPURCHASE
RIGHT
Authorized - 8,000,000 units
Issued and outstanding - 5,771,174 and
5,888,662 units, respectively 50,326,874 52,446,234
GENERAL PARTNER'S EQUITY 585,121 597,595
----------- -----------
Total partners' equity 50,911,995 53,043,829
----------- -----------
$52,254,265 $55,043,294
=========== ===========
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, 2001, 2000 and 1999
- --------------------------------------------------------------------------------
2001 2000 1999
---- ---- ----
REVENUES
Oil and gas sales $ 15,805,040 $ 16,490,904 $ 14,639,109
Well management and operating 453,774 428,497 421,799
Other 2,406 1,738 2,262
------------ ------------ ------------
16,261,220 16,921,139 15,063,170
DIRECT COST OF REVENUES
Production costs 2,419,260 2,244,926 2,638,217
Well management and operating 168,937 123,265 106,965
Depreciation, depletion and amortization 4,449,545 4,510,787 4,762,466
Abandonment and write down of oil and gas
properties 200,000 400,000 648,742
------------ ------------ ------------
Total direct cost of revenues 7,237,742 7,278,978 8,156,390
GENERAL AND ADMINISTRATIVE EXPENSE 1,359,378 1,322,260 1,615,932
------------ ------------ ------------
Total cost of revenues 8,597,120 8,601,238 9,772,322
------------ ------------ ------------
INCOME FROM OPERATIONS 7,664,100 8,319,901 5,290,848
OTHER INCOME (EXPENSE)
Interest income 222,764 316,091 157,348
Interest expense (44,702) (46,239) (101,759)
Gain on sale of property and equipment and other
assets -- 1,004 21,504
------------ ------------ ------------
178,062 270,856 77,093
------------ ------------ ------------
INCOME BEFORE CREDIT FOR INCOME TAXES 7,842,162 8,590,757 5,367,941
CREDIT FOR INCOME TAXES
Deferred -- -- (78,000)
------------ ------------ ------------
NET INCOME $ 7,842,162 $ 8,590,757 $ 5,445,941
============ ============ ============
Allocation of Partnership Net Income
Limited Partners $ 7,752,932 $ 8,495,622 $ 5,387,013
General Partner 89,230 95,135 58,928
------------ ------------ ------------
$ 7,842,162 $ 8,590,757 $ 5,445,941
============ ============ ============
Net income per unit $ 1.33 $ 1.42 $ 0.88
============ ============ ============
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, 2001, 2000 and 1999
- --------------------------------------------------------------------------------
2001 2000 1999
---- ---- ----
PARTNERS' EQUITY - JANUARY 1 $ 53,043,829 $ 53,288,759 $ 52,171,076
Net income 7,842,162 8,590,757 5,445,941
Cash distributions ($1.50 per unit in 2001, $1.25 per
unit in 2000 and $.625 per unit in 1999) (8,830,838) (7,573,783) (3,880,436)
Purchase and retirement of Units (1,143,158) (1,261,904) (447,822)
------------ ------------ ------------
PARTNERS' EQUITY - DECEMBER 31 $ 50,911,995 $ 53,043,829 $ 53,288,759
============ ============ ============
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, 2001, 2000 and 1999
- --------------------------------------------------------------------------------
2001 2000 1999
---- ---- ----
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 7,842,162 $ 8,590,757 $ 5,445,941
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 4,508,950 4,569,114 4,819,592
Abandonment and write down of oil and gas
properties 200,000 400,000 648,742
Gain on sale of property and equipment and other
assets -- (1,004) (21,504)
Deferred income taxes -- -- (78,000)
Changes in assets and liabilities:
Accounts receivable 596,362 (678,290) 450,714
Short-term investments (167,188) (2,110,101) 707,783
Other current assets 31,731 9,262 3,364
Other assets (6,555) 41,629 (27,304)
Accounts payable (513,713) (183,646) (464,187)
Accrued expenses (17,674) 103,351 (201,854)
------------ ------------ ------------
Total adjustments 4,631,913 2,150,315 5,837,346
------------ ------------ ------------
Net cash provided by operating activities 12,474,075 10,741,072 11,283,287
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds received on receivables from officers and
employees 273,447 248,692 379,191
Advances disbursed to officers and employees (122,053) (129,504) (165,499)
Purchase of property and equipment (3,394,808) (2,594,116) (3,414,843)
Purchase of other assets -- (64,050) --
Proceeds on sale of property and equipment and
other assets -- 1,433 199,818
------------ ------------ ------------
Net cash used by investing activities (3,243,414) (2,537,545) (3,001,333)
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions (8,830,838) (7,573,783) (3,880,436)
Repurchase of Units (1,143,158) (1,261,904) (447,822)
Proceeds from issuance of debt including revolver -- -- 2,175,000
Payments on debt including revolver (125,808) (54,467) (3,738,609)
------------ ------------ ------------
Net cash used by financing activities (10,099,804) (8,890,154) (5,891,867)
------------ ------------ ------------
NET INCREASE (DECREASE) IN CASH AND
EQUIVALENTS (869,143) (686,627) 2,390,087
CASH AND EQUIVALENTS - JANUARY 1 1,997,978 2,684,605 294,518
------------ ------------ ------------
CASH AND EQUIVALENTS - DECEMBER 31 $ 1,128,835 $ 1,997,978 $ 2,684,605
============ ============ ============
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest $ 42,656 $ 46,239 $ 112,648
Income taxes -- -- --
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,
accounts receivable, short-term investments (based on quoted
market values), 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 debt.
E. Cash Equivalents - For purposes of the statement of cash
flows, 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 cash 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
$4,417,473, $4,477,379 and $4,728,480 for the years ended
December 31, 2001, 2000 and 1999, 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. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of," 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 $200,000, $400,000 and $601,000
during 2001, 2000 and 1999, 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 $1,007,107 - 40 years). Depreciation on
pipeline and support equipment and other corporate property
and equipment amounted to $91,477, $91,735 and $91,112 for the
years ended December 31, 2001, 2000 and 1999, respectively.
Maintenance and repairs of property and equipment are expensed
as incurred. Major renewals and improvements are capitalized,
and the assets replaced are retired.
G. 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.
F-10
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(CONTINUED)
G. Revenue Recognition (Continued)
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.
H. 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 Statement 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.
I. Allocation of Income and Per Unit Data - Under the terms of
the limited partnership agreement, initially, 99% of
revenues and costs were allocated to the unitholders (the
limited partners) and 1% of revenues and costs were
allocated to the general partner. The allocation changes as
unitholders elect to exercise the repurchase right (see Note
4).
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 5,829,918, 5,991,928 and 6,133,865 in
2001, 2000 and 1999, respectively.
F-11
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(CONTINUED)
J. New Accounting Standards - In June 1998, SFAS No. 133,
"Accounting for Derivative Instruments and Hedging
Activities," was issued. SFAS No. 133 establishes accounting
and reporting standards for derivative instruments and
hedging activities. SFAS No. 133, as amended by SFAS No.
137, is effective for all fiscal quarters of all fiscal
years beginning after June 15, 2000. In June 2001, the
Financial Accounting Standards Board ("FASB") issued SFAS
No. 141, "Business Combinations." SFAS No. 141 requires the
purchase method of accounting for business combinations
initiated after June 30, 2001 and eliminates the
pooling-of-interest method and further clarifies the
criteria to recognize intangible assets separately from
goodwill. The adoption of SFAS Nos. 133 and 141 had no
material effect on the Company's financial statements.
In June 2001, FASB issued SFAS No. 142, "Goodwill and Other
Intangible Assets." Under SFAS No. 142, goodwill and
intangible assets deemed to have indefinite lives will no
longer be amortized but will be subject to periodic
impairment tests. Other intangible assets will continue to
be amortized over their useful lives. SFAS No. 142 is
effective for fiscal years beginning after December 15,
2001. In June 2001, FASB issued SFAS No. 143, "Accounting
for Asset Retirement Obligations," which is effective the
first quarter of fiscal year 2003. SFAS 143 addresses
financial accounting and reporting for obligations
associated with the retirement of long-lived assets and the
associated asset retirement cost. In August 2001, FASB
issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-lived Assets," which is effective the first
quarter of fiscal year 2002. SFAS No. 144 modifies and
expands the financial accounting and reporting for the
impairment or disposal of long-lived assets other than
goodwill. The Company is still evaluating the impact of
these new standards, but at this time does not believe their
adoption will have a significant impact on its financial
position and results of operations.
NOTE 2. SHORT-TERM INVESTMENTS
Short-term investments consist principally of marketable corporate
debt securities which are classified as trading. The fair values of
the investments approximate cost.
NOTE 3. CREDIT FACILITIES AND LONG-TERM DEBT
In August 2001, the Company entered into an agreement that modified
(extended) its prior credit agreement. The agreement provides for a
revolving line of credit in the amount of $4,000,000, all of which is
available. The revolving line of credit provides for interest payable
quarterly at LIBOR plus 150 basis points with the principal due at
maturity, May 31, 2003. The Company anticipates renewing the facility
every other year to minimize debt origination, carrying and interest
costs associated with long-term bank commitments. Borrowings under the
facility are unsecured; however, the Company has agreed, if requested
by the bank, to execute any supplements to the agreement including
security and mortgage agreements on the Company's assets. The
agreement contains restrictive covenants requiring the Company to
maintain the following: (i) loan balance not to exceed the borrowing
base of $4,000,000; (ii) tangible net worth of at least $40,000,000;
and (iii) a total debt to tangible net worth ratio of not more than
0.5 to 1.0. In addition, there are restrictions on mergers, sales and
acquisitions, the incurrence of additional debt and the pledge or
mortgage of the Company's assets.
F-12
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 3. CREDIT FACILITIES AND LONG-TERM DEBT (CONTINUED)
There were no borrowings outstanding on revolving credit facilities at
December 31, 2001 and 2000. The following schedule reflects activity
under the Company's revolving credit facilities for the years ended
December 31, 2001, 2000 and 1999. The average amount outstanding under
the facility was calculated using daily balances and a 365 day period.
The weighted average interest rates were calculated by dividing the
interest expense for the year for such borrowings by the average
amounts outstanding during the period.
Weighted
Maximum Average Average
Amount Amount Interest
Outstanding Outstanding Rate
----------- ----------- ----
Year Ended December 31:
2001 $ - $ - -
2000 $ - $ - -
1999 $2,700,000 $ 757,808 6.8%
The Company purchased a building and funded its cost, including
improvements, in part, through mortgage notes. The notes have an
aggregate balance of $512,014 and $637,822 at December 31, 2001 and
2000, respectively, and at December 31, 2001 bear interest at fixed
(with options to adjust or convert to variable in certain subsequent
years) rates ranging from 5.47% - 8.06% and a weighted average rate of
6.51%. The notes at December 31, 2001 require aggregate payments of
principal and interest of $7,175 per month. Maturities on the notes
are expected to be as follows: 2002 - $53,900; 2003 - $57,500; 2004 -
$61,400; 2005 - $65,600; 2006 - $68,100; thereafter - $205,514.
The Company is exposed to market risk from changes in interest rates
since it, at times, funds its operations through long-term and
short-term borrowings. The Company's primary interest rate risk
exposure results from floating rate debt with respect to the Company's
revolving credit. At December 31, 2001, none of the Company's total
long-term debt consisted of floating rate debt.
NOTE 4. 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-13
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 4. PARTNERS' EQUITY (CONTINUED)
The partnership agreement provides that Everflow will repurchase for
cash up to 10% of the then outstanding Units, to the extent
unitholders offer Units to Everflow for repurchase pursuant to the
repurchase right. The repurchase right entitles any unitholder,
between May 1 and June 30 of each year, to notify Everflow that 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, 2001 calculation, is estimated to be $5.66 per Unit, net of the
distributions ($.50 per Unit in total) expected to be made in January
and April 2002.
Units repurchased pursuant to the repurchase right, for each of the
four years in the period ended December 31, 2001, are as follows:
Per Unit
---------------------------------------------------------
Calculated Units
Price for Less Outstanding
Repurchase Premium Interim Net # of Units Following
Year Right Offered Distributions Price Paid Repurchased Repurchase
------- ---------- --------- --------------- ------------ ------------- ----------
1998 $ 5.24 $ -- $ .25 $ 4.99 35,114 6,172,537
1999 $ 6.16 $ -- $ .375 $ 5.79 77,344 6,095,193
2000 $ 6.73 $ -- $ .625 $ 6.11 206,531 5,888,662
2001 $10.35 $ -- $ .625 $ 9.73 117,488 5,771,174
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 5. PROVISION FOR INCOME TAXES
As referred to in Note 1, EEI and its subsidiaries account for current
and deferred income taxes under the provisions of SFAS No. 109. The
deferred taxes are the result of temporary differences arising from
differences in financial reporting and tax reporting methods for EEI's
proved properties.
F-14
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 5. PROVISION FOR INCOME TAXES (CONTINUED)
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,
------------------------------------------------------------------------------
2001 2000 1999
------------------------ ----------------------- ------------------------
Amount % Amount % Amount %
----------- --------- ----------- -------- ----------- --------
Provision based on the
statutory rate (for taxable
income up to $10,000,000) $ 2,666,000 34.0 $ 2,921,000 34.0 $ 1,825,000 34.0
Tax effect of:
Non-taxable status of the
Programs and Everflow (2,654,000) (33.8) (2,965,000) (34.5) (1,866,000) (34.8)
Excess statutory depletion (70,000) (0.9) (83,000) (1.0) (72,000) (1.3)
Graduated tax rates, state
income tax and other - net 58,000 0.7 127,000 1.5 35,000 0.6
----------- --------- ----------- -------- ----------- --------
Total $ -- -- $ -- -- $ (78,000) (1.5)
=========== ========= =========== ======== =========== ========
EEI has percentage depletion deduction carryforwards for tax purposes
of approximately $2,160,000. These carryforwards can be carried
forward indefinitely. For financial reporting purposes, the deferred
tax liability at December 31, 2001 and 2000 has been reduced by
approximately $661,000 and $730,000, respectively, for the tax effect
of carryforwards.
NOTE 6. RETIREMENT PLAN
The Company has a defined contribution plan pursuant to Section 401(k)
of the Internal Revenue Code for all employees who have reached the
age of 21 and completed one year of service. Certain contributions to
the plan are at the discretion of EMC's Board of Directors. The
Company matched employees' contributions to the 401(K) Retirement
Savings Plan to the extent of 50% of the first 6% of a participant's
salary reduction in 1999. Beginning in 2000, 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.
The amounts attributable to the Company's matching contribution vest
immediately. The Company made contributions of $63,275, $52,683 and
$38,879 for the years ended December 31, 2001, 2000 and 1999,
respectively.
F-15
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 7. RELATED PARTY TRANSACTIONS
Since 1989, EEI provided certain employees with an opportunity to
receive assignments of certain overriding royalty interests which were
created at the time EEI generated certain oil and gas leases. Certain
employees of the Company have been given the option of having a
portion of their compensation in the form of an assignment in certain
of such overriding royalty interests. Those employees who elect to
receive a portion of their compensation in this form receive an
assignment of a pro rata portion of each of the overriding royalty
interests selected. During the calendar years ended December 31, 2001,
2000 and 1999, approximately $140,000, $140,000 and $117,000,
respectively, was distributed to such employees from such overriding
royalty interests.
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. Such loans
currently accrue interest at LIBOR plus 150 basis points. Such
receivables are expected to be paid from production revenues
attributable to such interests or through joint interest assessments.
NOTE 8. 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, additional borrowings
or additional equity funds. 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.
F-16
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 8. BUSINESS SEGMENTS, RISKS AND MAJOR CUSTOMERS (CONTINUED)
Gas sales accounted for 89%, 84% and 89% of total oil and gas sales in
2001, 2000 and 1999, respectively. Approximate percentages of total
oil and gas sales from significant purchasers for the years ended
December 31, 2001, 2000 and 1999, respectively, were as follows:
Customer 2001 2000 1999
-------- ---- ---- ----
Dominion Field Services, Inc., its affiliates and its
predecessors ("Dominion") 45 % 53 % 67 %
Ergon Oil Purchasing, Inc. ("Ergon Oil") 11 16 11
Interstate Gas Supply, Inc. ("IGS") 25 11 -
--- --- ---
81 % 80 % 78 %
=== === ===
The Company expects that Dominion, Ergon Oil and IGS will be the only
major customers in 2002.
In 2001 and over the past ten years, 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 agreement terminated during 2001 and was
replaced by short-term contracts, which obligate 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
certain pricing provisions included in gas purchase contracts with
Dominion follows:
Production Period November 2001 through March 2002 (Dominion)
The first 40,000 MCF per month is priced at $3.51 per MCF. The next
50,000 MCF per month is priced at $4.73 per MCF. The next 50,000 MCF
per month is priced at $5.35 per MCF. All gas in excess of 140,000 MCF
per month is priced at the NYMEX settled price plus $.10 up to the
first 250,000 MCF in the aggregate during the period. All gas in
excess of the above volumes is priced at the NYMEX settled price plus
$.45.
Production Period April 2002 through October 2002 (Dominion)
The first 50,000 MCF per month is priced at $4.73 per MCF. The next
50,000 MCF per month is priced at $5.35 per MCF. The next 20,000 MCF
per month is priced at $3.35 per MCF. In the event the 250,000 MCF in
the November 2001 through March 2002 period is not met, any remaining
balance is priced at the NYMEX settled price plus $.10 during the
period. All gas in excess of the above volumes is priced at the NYMEX
settled price plus $.45.
F-17
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 8. BUSINESS SEGMENTS, RISKS AND MAJOR CUSTOMERS (CONTINUED)
Production Period November 2002 through October 2003 (Dominion)
The first 20,000 MCF per month is priced at $3.35 per MCF. The next
20,000 MCF per month is priced at $4.00. The next 20,000 MCF per month
is priced at $4.10. All gas in excess of the above volumes is priced
at NYMEX settled price plus $.45.
Production Period November 2003 through March 2004 (Dominion)
The first 20,000 MCF per month is priced at $4.05 per MCF. Gas in
excess of 20,000 MCF per month has not been committed.
The Company also has short-term contracts with 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 certain pricing provisions included in the gas
purchase contracts with IGS follows:
Production Period November 2001 through October 2002 (IGS)
The first 50,000 MCF per month is priced at $4.56 per MCF. All gas in
excess of 50,000 MCF per month is priced at NYMEX settled price plus
$.42.
Production Period April 2002 through October 2002 and April 2003
through October 2003 (IGS)
The first 20,000 MCF per month is priced at $3.19 per MCF. All gas in
excess of 20,000 MCF per month is priced at the NYMEX settled price
plus $.27.
Production Period November 2002 through March 2003 (IGS)
The first 20,000 MCF per month is priced at $3.19 per MCF. The next
20,000 MCF per month is priced at $4.01 per MCF. All gas in excess of
the above volumes is priced at the NYMEX settled price plus $.57.
Production Period November 2003 through March 2004 (IGS)
The first 20,000 MCF per month is priced at $4.10 per MCF. All gas in
excess of 20,000 MCF per month is priced at the NYMEX settled price
plus $.57.
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. As of December 31, 2001, natural gas purchased by
Dominion covers production from approximately 420 gross wells, while
natural gas purchased by IGS covers production from approximately 190
gross wells.
F-18
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 9. COMMITMENTS AND CONTINGENCIES
Everflow paid a dividend in January 2002 of $.25 per Unit. The
distribution amounted to approximately $1,460,000.
The Company is the general partner in certain oil and gas
partnerships. As general partner, the Company shares in unlimited
liability to third parties with respect to the operations of the
partnerships and may be liable to limited partners for losses
attributable to breach of fiduciary obligations.
NOTE 10. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
The following is a summary of selected quarterly financial data for
the years ended December 31, 2001 and 2000:
Quarters Ended
---------------------------------------------------------------
March 31 June 30 September 30 December 31
---------- --------- ------------- ------------
2001
----
Revenues $4,877,102 $3,773,349 $3,910,598 $3,700,171
Income from operations 2,180,895 1,808,311 1,848,477 1,826,417
Net income 2,243,774 1,869,935 1,876,055 1,852,398
Net income per unit .38 .31 .32 .32
Quarters Ended
---------------------------------------------------------------
March 31 June 30 September 30 December 31
---------- --------- ------------- ------------
2000
----
Revenues $4,584,831 $3,328,253 $3,313,751 $5,694,304
Income from operations 1,782,528 1,403,796 1,241,006 3,892,571
Net income 1,826,116 1,474,780 1,301,405 3,988,456
Net income per unit .30 .24 .22 .67
Quarterly operating results are not necessarily representative of
operations for a full year for various reasons, including the
volatility and seasonality of oil and gas production and prices, the
highly competitive and, at times, seasonal nature of the oil and gas
industry and worldwide economic conditions.
F-19
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 11. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED)
The following supplemental unaudited oil and gas information is
required by SFAS No. 69, "Disclosures About Oil and Gas Producing
Activities."
The tables on the following pages set forth pertinent data with
respect to the Company's oil and gas properties, all of which are
located within the continental United States.
CAPITALIZED COSTS RELATING TO OIL AND GAS
PRODUCING ACTIVITIES
December 31,
------------------------------------------------------
2001 2000 1999
---- ---- ----
Proved oil and gas properties $114,964,451 $112,341,851 $110,483,039
Pipeline and support equipment 504,222 504,222 507,472
------------ ------------ ------------
115,468,673 112,846,073 110,990,511
Accumulated depreciation, depletion,
amortization and write down 72,365,538 68,469,693 64,241,134
------------ ------------ ------------
Net capitalized costs $ 43,103,135 $ 44,376,380 $ 46,749,377
============ ============ ============
COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
December 31,
------------------------------------------------------
2001 2000 1999
---- ---- -----
Property acquisition costs $ 234,786 $ 175,875 $ 292,852
Development costs, including
prepayments 3,135,374 2,333,387 2,614,116
In 2001, 2000 and 1999, development costs include the purchase of
approximately $309,000, $-0- and $1,452,000, respectively, of
producing oil and gas properties.
F-20
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 11. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING
ACTIVITIES (UNAUDITED) (CONTINUED)
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
December 31,
---------------------------------------------------
2001 2000 1999
---- ---- ----
Oil and gas sales $ 15,805,040 $ 16,490,904 $ 14,639,109
Production costs (2,419,260) (2,244,926) (2,638,217)
Depreciation, depletion and
amortization (4,449,545) (4,510,787) (4,762,466)
Abandonment and write down of
oil and gas properties (200,000) (400,000) (648,742)
------------ ------------ ------------
8,736,235 9,335,191 6,589,684
Income tax expense 100,000 100,000 115,000
------------ ------------ ------------
Results of operations for oil and gas
producing activities (excluding
corporate overhead and financing
costs) $ 8,636,235 $ 9,235,191 $ 6,474,684
============ ============ ============
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-21
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 11. 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, 1999 935,000 52,903,000
Extensions, discoveries and other
additions 38,000 4,018,000
Production (97,000) (4,245,000)
Revision of previous estimates (1,000) (1,170,000)
----------- -----------
Balance, December 31, 1999 875,000 51,506,000
Extensions, discoveries and other
additions 3,000 1,195,000
Production (92,000) (4,196,000)
Revision of previous estimates 128,000 29,000
----------- -----------
Balance, December 31, 2000 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
=========== ===========
PROVED DEVELOPED RESERVES:
December 31, 1998 935,000 52,903,000
December 31, 1999 875,000 51,506,000
December 31, 2000 914,000 48,534,000
December 31, 2001 719,000 41,925,000
The Company has not determined proved reserves associated with its
proved undeveloped acreage. At December 31, 2001 and 2000, the Company
had 700 and 780 net proved undeveloped acres, respectively. The
carrying cost of the proved undeveloped acreage that is included in
proved properties amounted to $528,208 and $682,206 at December 31,
2001 and 2000, respectively.
F-22
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 11. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING
ACTIVITIES (UNAUDITED) (CONTINUED)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS
December 31,
--------------------------------------------
2001 2000 1999
---- ---- ----
(Thousands of Dollars)
Future cash inflows from sales of oil
and gas $138,032 $248,711 $166,772
Future production and development
costs 57,159 81,641 64,142
Future income tax expense 1,675 3,971 2,405
-------- -------- --------
Future net cash flows 79,198 163,099 100,225
Effect of discounting future net cash
flows at 10% per annum 34,104 81,125 46,532
-------- -------- --------
Standardized measure of discounted
future net cash flows $ 45,094 $ 81,974 $ 53,693
======== ======== ========
CHANGES IN THE STANDARDIZED MEASURE OF
DISCOUNTED FUTURE NET CASH FLOWS
Year Ended December 31,
-------------------------------------------
2001 2000 1999
---- ---- ----
(Thousands of Dollars)
Balance, beginning of year $ 81,974 $ 53,693 $ 51,479
Extensions, discoveries and other
additions 2,814 2,141 4,486
Development costs incurred 313 245 298
Revision of previous estimates (5,833) 1,133 (2,240)
Sales of oil and gas, net of production
costs (13,386) (14,246) (12,001)
Net change in income taxes 1,042 (708) (55)
Net changes in prices and production
costs (30,076) 28,769 3,304
Accretion of discount 8,197 5,369 5,148
Other 49 5,578 3,274
-------- -------- --------
Balance, end of year $ 45,094 $ 81,974 $ 53,693
======== ======== ========
F-23
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 11. 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 (reduced 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, 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-24