Back to GetFilings.com
================================================================================
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
COMMISSION FILE NO. 0-19279
EVERFLOW EASTERN PARTNERS, L.P.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 34-1659910
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
585 WEST MAIN STREET
P.O. BOX 629
CANFIELD, OHIO 44406
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 330-533-2692
Securities registered pursuant to Section 12(b) of the Act.
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
------------------- -------------------
None
Securities registered pursuant to Section 12(g) of the Act:
UNITS OF LIMITED PARTNERSHIP INTEREST
-------------------------------------
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
--- ---
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K.
---
Indicate by check mark whether the registrant is an accelerated filer
(as defined in Exchange Act Rule 12b-2). Yes No X
--- ---
There were 4,487,333 Units of limited partnership interest held by
non-affiliates of the Registrant as of March 20, 2003. 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, 2002.
PART I
ITEM 1. BUSINESS
Introduction
Everflow Eastern Partners, L.P. (the "Company"), a Delaware
limited partnership, engages in the business of oil and gas exploration and
development. The Company was formed for the purpose of consolidating the
business and oil and gas properties of Everflow Eastern, Inc., an Ohio
corporation ("EEI"), and the oil and gas properties owned by certain limited
partnerships and working interest programs managed or operated by EEI (the
"Programs"). Everflow Management Limited, LLC (the "General Partner"), an Ohio
limited liability company, is the general partner of the Company.
Exchange Offer. The Company made an offer (the "Exchange
Offer") to acquire the common shares of EEI (the "EEI Shares") and the interests
of investors in the Programs (collectively the "Interests") in exchange for
units of limited partnership interest (the "Units"). The Exchange Offer was made
pursuant to a Registration Statement on Form S-1 declared effective by the
Securities and Exchange Commission on December 19, 1990 (the "Registration
Statement") and the Prospectus dated December 19, 1990, as filed with the
Commission pursuant to Rule 424(b).
The Exchange Offer terminated on February 15, 1991 and holders
of Interests with an aggregate value (as determined by the Company for purposes
of the Exchange Offer) of $66,996,249 accepted the Exchange Offer and tendered
their Interests. Effective on such date, the Company acquired such Interests,
which included partnership interests and working interests in the Programs, and
all of the outstanding EEI Shares. Of the Interests tendered in the Exchange
Offer, $28,565,244 was represented by the EEI Shares and $38,431,005 by the
remaining Interests.
The parties who accepted the Exchange Offer and tendered their
Interests received an aggregate of 6,632,464 Units. Everflow Management Company,
a predecessor of the General Partner of the Company, contributed Interests with
an aggregate Exchange Value of $670,980 in exchange for a 1% interest in the
Company.
The Company. The Company was organized in September 1990. The
principal executive offices of the Company, the General Partner and EEI are
located at 585 West Main Street, Canfield, Ohio 44406 (telephone number
330-533-2692).
General
This Annual Report on Form 10-K contains forward-looking
statements which involve risks and uncertainties. The Company's actual results
may differ significantly from the results discussed in the forward-looking
statements. All statements that address operating performance, events or
developments that the Company anticipates will occur in the future,
1
including statements related to future revenue, profits, expenses, and income or
statements expressing general optimism about future results, are forward-looking
statements within the meaning of Section 21E of the Securities Exchange Act of
1934, as amended ("Exchange Act"). In addition, words such as "expects,"
"anticipates," "intends," "plans," "believes," "estimates," variations of such
words, and similar expressions are intended to identify forward-looking
statements. Forward-looking statements are subject to the safe harbors created
in the Exchange Act.
Factors that may cause differences in the Company's actual
results versus results discussed in forward-looking statements include, but are
not limited to, the competition within the oil and gas industry, the price of
oil and gas in the Appalachian Basin area, the number of Units tendered pursuant
to the Repurchase Right and the ability to locate productive oil and gas
prospects for development by the Company. The Company undertakes no obligation
to update publicly any forward-looking statements, whether as a result of new
information, future events or otherwise.
Description of the Business
General. The Company has participated on an on-going basis in
the acquisition and development of undeveloped oil and gas properties and has
pursued the acquisition of producing oil and gas properties.
Subsidiaries. The Company has two subsidiaries. EEI was
organized as an Ohio corporation in February 1979 and, since the consummation of
the Exchange Offer, has been a wholly-owned subsidiary of the Company. EEI is
engaged in the business of drilling, developing and operating oil and gas
properties and maintains a leasehold inventory from which the Company selects
prospects for development.
A-1 Storage of Canfield, Ltd. ("A-1 Storage") was organized as
an Ohio limited liability company in late 1995 and is 99% owned by the Company
and 1% owned by EEI. A-1 Storage's business includes leasing of office space to
the Company as well as rental of storage units to non-affiliated parties.
Current Operations. The properties of the Company consist in
large part of fractional undivided working interests in properties containing
Proved Reserves of oil and gas located in the Appalachian Basin region of Ohio
and Pennsylvania. Approximately 91% of the estimated total future cash inflows
related to the Company's oil and gas reserves as of December 31, 2002 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 272
(net) wells. The Company serves as the operator of approximately 75% of the
gross wells and 85% of the net wells which comprise the Company's properties.
2
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 20 prospects in various stages of maturity representing
approximately 640 net acres under lease.
In choosing oil and gas prospects for the Company, the General
Partner does not attempt to manage the risks of drilling through a policy of
selecting diverse prospects in various geographic areas or with the potential of
oil and gas production from different geological formations. Rather,
substantially all prospects are expected to be located in the Appalachian Basin
of Ohio (and, to a lesser extent, Pennsylvania) and to be drilled primarily to
the Clinton/Medina Sands geological formation or closely related oil and gas
formations in such area.
Acquisition of Producing Properties. As a potential means of
increasing its reserve base, the Company expects to evaluate opportunities which
it may be presented with to acquire oil and gas producing properties from third
parties in addition to its ongoing leasehold acquisition and development
activities. The Company has acquired a limited amount of producing oil and gas
properties.
The Company will continue to evaluate properties for
acquisition. Such properties may include, in addition to working interests,
royalty interests, net profit interests and production payments, other forms of
direct or indirect ownership interests in oil and gas production, and properties
associated with the production of oil and gas. The Company also may acquire
general or limited partner interests in general or limited partnerships and
interests in joint ventures, corporations or other entities that have, or are
formed to acquire, explore for or develop, oil and gas or conduct other
activities associated with the ownership of oil and gas production.
3
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 during 2002 and no principal indebtedness was outstanding as of March
20, 2003. 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,
2002, which aggregate $67,934,000 (Standardized Measure of Discounted Future Net
Cash Flows) with no bank debt outstanding under the revolving credit facility as
of December 31, 2002.
4
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 $34.25 in March 2003. As
of March 20, 2003, the posted field price in the Appalachian Basin area, the
Company's principal area of operation, was $26.50 per barrel of oil. There can
be no assurance that prices will not be subject to continual fluctuations.
Future oil prices are difficult to predict because of the impact of worldwide
economic trends, supply and demand variables, and such non-economic factors as
the political impact on pricing policies by the Organization of Petroleum
Exporting Countries ("OPEC") and the possibility of supply interruptions. To the
extent the prices that the Company receives for its crude oil production decline
or remain at current levels, the Company's revenues from oil production will be
reduced accordingly.
Since January 1993, the Company has sold substantially all of
its crude oil production to Ergon Oil Purchasing, Inc.
Natural Gas. The deliverability and price of natural gas is
subject to various factors affecting the supply and demand of natural gas as
well as the effect of federal regulations. Prior to 2000, there had been a
surplus of natural gas available for delivery to pipelines and other purchasers.
During 2000, decreases in worldwide energy production capability and increases
in energy consumption brought about a shortage in natural gas supplies. This
resulted in increases in natural gas prices throughout the United States,
including the Appalachian Basin. During 2001, lower energy consumption and
increased natural gas supplies reduced prices to historical levels. More
recently, during 2002, shortages in natural gas supplies once again have
resulted from increased energy consumption due to harsh weather conditions. From
time to time, especially in summer months, seasonal restrictions on natural gas
production have occurred as a result of distribution system restrictions.
Certain of the Company's wells have been subject to these limited, seasonal
shut-ins and restrictions.
Over the ten years prior to 2002, the Company had followed a
practice of selling a significant portion of its natural gas pursuant to
Intermediate Term Adjustable Price Gas Purchase Agreements (the "East Ohio
Contracts") with Dominion Field Services, Inc. and its
5
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
significant gas purchase contracts, including weighted average pricing
provisions, with Dominion follows:
November 2002 through March 2003
The first 200,000 MCF per month is priced at $4.18 per MCF. An
additional 100,000 MCF is priced at $4.39 per MCF for November 2002.
All gas in excess of these volumes is priced at the NYMEX settled price
plus $.45 per MCF.
April 2003 through October 2003
The first 140,000 MCF per month is priced at $4.10 per MCF. An
additional 30,000 MCF is priced at $8.05 per MCF for April 2003. An
additional 60,000 MCF is priced at $4.31 per MCF for June 2003. All gas
in excess of these volumes is priced at the NYMEX settled price plus
$.45 per MCF.
November 2003 through March 2004
The first 160,000 MCF per month is priced at $4.65 per MCF. An
additional 60,000 MCF is priced at $5.27 per MCF for November 2003. All
gas in excess of these volumes is priced at 100% (DTI) Inside FERC plus
$.25 per MCF.
April 2004 through October 2004
The first 100,000 MCF per month is priced at $4.42 per MCF. An
additional 20,000 MCF is priced at $4.18 per MCF for June 2004. All gas
in excess of these volumes is priced at 100% (DTI) Inside FERC plus
$.25 per MCF.
The Company also has a short-term contract with Interstate Gas
Supply, Inc. ("IGS"), which obligate IGS to purchase, and the Company to sell
and deliver certain quantities of natural gas production on a monthly basis
throughout the contract periods. A summary of significant gas purchase
contracts, including weighted average pricing provisions, with IGS follows:
6
November 2002 through March 2003
The first 100,000 MCF per month is priced at $4.12 per MCF. An
additional 40,000 MCF is priced at $4.53 per MCF for November 2002. All
gas in excess of these volumes is priced at the NYMEX settled price
plus $.57 per MCF.
April 2003 through October 2003
The first 60,000 MCF per month is priced at $4.00 per MCF. An
additional 20,000 MCF is priced at $8.05 per MCF for April 2003. An
additional 30,000 MCF is priced at $4.18 per MCF for June 2003. All gas
in excess of these volumes is priced at the NYMEX settled price plus
$.27 per MCF.
November 2003 through March 2004
The first 80,000 MCF per month is priced at $4.38 per MCF. An
additional 40,000 MCF is priced at $4.82 per MCF for November 2003. All
gas in excess of these volumes is priced at the NYMEX settled price
plus $.45 per MCF.
April 2004 through October 2004
The first 60,000 MCF per month is priced at $4.48 per MCF. An
additional 20,000 MCF is priced at $4.22 per MCF for June 2004. All gas
in excess of these volumes is priced at the NYMEX settled price plus
$.45 per MCF.
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, 2002, natural gas purchased by Dominion covers
production from approximately 430 gross wells, while natural gas purchased by
IGS covers production from approximately 220 gross wells. See "MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -
Inflation and Changes in Prices."
For the year ended December 31, 2002, with the exception of
Dominion and IGS, which accounted for approximately 55% and 25%, respectively,
of the Company's natural gas sales, no one natural gas purchaser has accounted
for more than 10% of the Company's gas sales. The Company expects that Dominion
and IGS will be the only material natural gas customers for 2003.
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.
7
Title to Properties
As is customary in the oil and gas industry, the Company
performs a limited investigation as to ownership of leasehold acreage at the
time of acquisition and conducts a title examination and necessary curative work
prior to the commencement of drilling operations on a tract. Title examinations
have been performed for substantially all of the producing oil and gas
properties owned by the Company with regard to (i) substantial tracts of land
forming a portion of such oil and gas properties and (ii) the wellhead location
of such properties. The Company believes that title to its properties is
acceptable although such properties may be subject to royalty, overriding
royalty, carried and other similar interests in contractual arrangements
customary in the oil and gas industry. Also, such properties may be subject to
liens incident to operating agreements and liens for current taxes not yet due,
as well as other comparatively minor encumbrances.
Competition
The oil and gas industry is highly competitive in all its
phases. The Company will encounter strong competition from major and independent
oil companies in acquiring economically desirable prospects as well as in
marketing production therefrom and obtaining external financing. Major oil and
gas companies, independent concerns, drilling and production purchase programs
and individual producers and operators are active bidders for desirable oil and
gas properties, as well as the equipment and labor required to operate those
properties. Many of the Company's competitors have financial resources,
personnel and facilities substantially greater than those of the Company.
The availability of a ready market for the oil and gas
production of the Company depends in part on the cost and availability of
alternative fuels, the level of consumer demand, the extent of other domestic
production of oil and gas, the extent of importation of foreign oil and gas, the
cost of and proximity to pipelines and other transportation facilities,
regulations by state and federal authorities and the cost of complying with
applicable environmental regulations. The volatility of prices for oil and gas
and the continued oversupply of domestic natural gas have, at times, resulted in
a curtailment in exploration for and development of oil and gas properties.
There is also extensive competition in the market for gas
produced by the Company. Decreases in worldwide energy production capability and
increases in energy consumption have brought about a shortage in energy supplies
recently. This, in turn, has resulted in substantial competition for markets
historically served by domestic natural gas resources both with alternate
sources of energy, such as residual fuel oil, and among domestic gas suppliers.
As a result, at times there has been volatility in oil and gas prices,
widespread curtailment of gas production and delays in producing and marketing
gas after it is discovered. Changes in government regulations relating to the
production, transportation and marketing of natural gas have also resulted in
significant changes in the historical marketing patterns of the industry.
Generally, these changes have resulted in the abandonment by many pipelines of
long-term contracts for the purchase of natural gas, the development by gas
producers of their own marketing programs to take advantage of new regulations
requiring pipelines to transport gas for
8
regulated fees, and an increasing tendency to rely on short-term sales contracts
priced at spot market prices. See "Marketing" above.
Gas prices, which were once effectively determined by
government regulations, are now influenced largely by the effects of
competition. Competitors in this market include other producers, gas pipelines
and their affiliated marketing companies, independent marketers, and providers
of alternate energy supplies.
Regulation of Oil and Gas Industry
The exploration, production and sale of oil and natural gas
are subject to numerous state and federal laws and regulations. Such laws and
regulations govern a wide variety of matters, including the drilling and spacing
of wells, allowable rates of production, marketing, pricing and protection of
the environment. Such regulations may restrict the rate at which the Company's
wells produce oil and natural gas below the rate at which such wells could
produce in the absence of such regulations. In addition, legislation and
regulations concerning the oil and gas industry are constantly being reviewed
and proposed. Ohio and Pennsylvania, the states in which the Company owns
properties and operates, have statutes and regulations governing a number of the
matters enumerated above. Compliance with the laws and regulations affecting the
oil and gas industry generally increases the Company's costs of doing business
and consequently affects its profitability. Inasmuch as such laws and
regulations are frequently amended or reinterpreted, the Company is unable to
predict the future cost or impact of complying with such regulations.
The interstate transportation and sale for resale of natural
gas is regulated by the Federal Energy Regulatory Commission (the "FERC") under
the Natural Gas Act of 1938 ("NGA"). The wellhead price of natural gas is also
regulated by FERC under the authority of the Natural Gas Policy Act of 1978
("NGPA"). Subsequently, the Natural Gas Wellhead Decontrol Act of 1989 (the
"Decontrol Act") was enacted on July 26, 1989. The Decontrol Act provided for
the phasing out of price regulation under the NGPA commencing on the date of
enactment and completely eliminated all such gas price regulation on January 1,
1993. In addition, FERC recently has adopted and proposed several rules or
orders concerning transportation and marketing of natural gas. The impact of
these rules and other regulatory developments on the Company cannot be
predicted. It is expected that the Company will sell natural gas produced by its
oil and gas properties to a number of purchasers, including various industrial
customers, pipeline companies and local public utilities, although the majority
will be sold to East Ohio as discussed earlier.
As a result of the NGPA and the Decontrol Act, the Company's
gas production is no longer subject to price regulation. Gas which has been
removed from price regulation is subject only to that price contractually agreed
upon between the producer and purchaser. Under current market conditions,
deregulated gas prices under new contracts tend to be substantially lower than
most regulated price ceilings originally prescribed by the NGPA. FERC recently
has proposed and enacted several rules or orders concerning transportation and
marketing of natural gas. In 1992, the FERC finalized Order 636, a rule
pertaining to the restructuring of interstate pipeline services. This rule
requires interstate pipelines to unbundle transportation and sales
9
services by separately pricing the various components of their services, such as
supply, gathering, transportation and sales. These pipeline companies are
required to provide customers only the specific service desired without regard
to the source for the purchase of the gas. Although the Partnership is not an
interstate pipeline, it is likely that this regulation may indirectly impact the
Partnership by increasing competition in the marketing of natural gas, possibly
resulting in an erosion of the premium price historically available for
Appalachian natural gas. The impact of these rules and other regulatory
developments on the Company cannot be predicted.
Regulation of the production, transportation and sale of oil
and gas by federal and state agencies has a significant effect on the Company
and its operating results. Certain states, including Ohio and Pennsylvania, have
established rules and regulations requiring permits for drilling operations,
drilling bonds and reports concerning the spacing of wells.
Environmental Regulation
The activities of the Company are subject to various federal,
state and local laws and regulations designed to protect the environment. The
Company does not conduct activities offshore. Operations of the Company on
onshore oil properties may generally be liable for clean-up costs to the federal
government under the Federal Clean Water Act for up to $50,000,000 for each
incident of oil or hazardous pollution substance and for up to $50,000,000 plus
response costs under the Comprehensive Environmental Response, Compensation, and
Liability Act of 1980 ("Superfund") for hazardous substance contamination.
Liability is unlimited in cases of willful negligence or misconduct, and there
is no limit on liability for environmental clean-up costs or damages with
respect to claims by the state or private persons or entities. In addition, the
Company is required by the Environmental Protection Agency ("EPA") to prepare
and implement spill prevention control and countermeasure plans relating to the
possible discharge of oil into navigable waters; and the EPA will further
require permits to authorize the discharge of pollutants into navigable waters.
State and local permits or approvals may also be needed with respect to
waste-water discharges and air pollutant emissions. Violations of
environment-related lease conditions or environmental permits can result in
substantial civil and criminal penalties as well as potential court injunctions
curtailing operations. Such enforcement liabilities can result from prosecution
by public or private entities.
Various state and governmental agencies are considering, and
some have adopted, other laws and regulations regarding environmental protection
which could adversely affect the proposed business activities of the Company.
The Company cannot predict what effect, if any, current and future regulations
may have on the operations of the Company.
In addition, from time to time, prices for either oil or
natural gas have been regulated by the federal government, and such price
regulation could be reimposed at any time in the future.
10
Operating Hazards and Uninsured Risks
The Company's oil and gas operations are subject to all
operating hazards and risks normally incident to drilling for and producing oil
and gas, such as encountering unusual formations and pressures, blow-outs,
environmental pollution and personal injury. The Company maintains such
insurance coverage as it believes to be appropriate taking into account the size
of the Company and its operations. Losses can occur from an uninsurable risk or
in amounts in excess of existing insurance coverage. The occurrence of an event
which is not insured or not fully insured could have an adverse impact on the
Company's revenues and earnings.
In certain instances, the Company may continue to engage in
exploration and development operations through drilling programs formed with
non-industry investors. In addition, the Company also will conduct a significant
portion of its operations with other parties in connection with the drilling
operations conducted on properties in which it has an interest. In these
arrangements, all joint interest parties, including the Company, may be fully
liable for their proportionate share of all costs of such operations. Further,
if any joint interest party defaults on its obligations to pay its share of
costs, the other joint interest parties may be required to fund the deficiency
until, if ever, it can be collected from the defaulting party. As a result of
the foregoing or similar oilfield circumstances, the Company could become liable
for amounts significantly in excess of amounts originally anticipated to be
expended in connection with such operations. In addition, financial difficulty
for an operator of oil and gas properties could result in the Company's and
other joint interest owners' interests in properties and the wells and equipment
located thereon becoming subject to liens and claims of creditors,
notwithstanding the fact that non-defaulting joint interest owners and the
Company may have previously paid to the operator the amounts necessary to pay
their share of such costs and expenses.
Conflicts of Interest
The Partnership Agreement grants the General Partner broad
discretionary authority to make decisions on matters such as the Company's
acquisition of or participation in a drilling prospect or a producing property.
To limit the General Partner's management discretion might prevent it from
managing the Company properly. However, because the business activities of the
affiliates of the General Partner on the one hand and the Company on the other
hand are the same, potential conflicts of interest are likely to exist, and it
is not possible to completely mitigate such conflicts.
The Partnership Agreement contains certain restrictions
designed to mitigate, to the extent practicable, these conflicts of interest.
The agreement restricts, among other things, (i) the cost at which the General
Partner or its affiliates may acquire properties from or sell properties to the
Company; (ii) loans between the General Partner, its affiliates and the Company,
and interest and other charges incurred in connection therewith; and (iii) the
use and handling of the Company's funds by the General Partner.
11
Employees
As of March 20, 2003, the Company had 15 full-time and four
part-time employees. These employees primarily are engaged in the following
areas of business operations: three in land and lease acquisition, five in field
operations, five in accounting, and six in administration.
12
ITEM 2. PROPERTIES.
Set forth below is certain information regarding the oil and
gas properties of the Company.
In the following discussion, "gross" refers to the total acres
or wells in which the Company has a working interest and "net" refers to gross
acres or wells multiplied by the Company's percentage of working interests
therein. Because royalty interests held by the Company will not affect the
Company's working interests in its properties, neither gross nor net acres or
wells reflect such royalty interests.
Proved Reserves.(1) The following table reflects the estimates
of the Company's Proved Reserves which are based on the Company's report as of
December 31, 2002.
Oil (BBLS) Gas (MCF)
---------- ---------
Proved Developed 699,000 43,307,000
Proved Undeveloped - -
------- ----------
Total 699,000 43,307,000
======= ==========
-----------------
(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, 2002, 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 $ 212,322
Future production and development costs 76,048
Future income tax expense 2,782
----------
133,492
Future net cash flows
Effect of discounting future net cash flows
at 10% per annum 65,558
----------
Standardized measure of discounted future
net cash flows $ 67,934
==========
-----------------
(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)
---------- --------- ------- ------- ---------------------
2002 73,000 3,680,000 $ 22.33 $ 3.98 $ .64
2001 76,000 3,583,000 22.57 3.93 .60
2000 92,000 4,196,000 27.82 3.32 .47
-----------------
(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, 2002.
Gross Wells Net Wells
----------------------------------------------------------------------------
(1) (1) (1) (1)
Oil Gas Total Oil Gas Total
----------------------------------------------------------------------------
73 998 1,071 52 691 743
-----------------
(1) Oil wells are those wells which generate the majority
of their revenues from oil production; gas wells are
those wells which generate the majority of their
revenues from gas production.
Acreage. The Company had approximately 47,000 gross developed
acres and 33,000 net developed acres as of December 31, 2002. Developed acreage
is that acreage assignable to productive wells. The Company had approximately
640 gross and net undeveloped acres as of December 31, 2002.
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
----------- ----------- ----------- -----------
2002 29 14.00 2 .33
2001 33 15.14 - -
2000 26 11.28 1 .14
-----------------
(1) All wells are located in the United States. All wells
are development wells; no exploratory wells were
drilled.
Present Activities. The Company has drilled 15 gross and 6.38
net development wells since December 31, 2002. As of March 20, 2003, the Company
had no wells in the process of being drilled.
Delivery Commitments. The Company entered into various
contracts with Dominion and IGS which, subject to certain restrictions and
adjustments, obligate Dominion and IGS to purchase and the Company to sell all
natural gas production from certain contract wells. The contract wells comprise
more than 75% of the Company's natural gas sales. In addition, the Company has
entered into various short-term contracts which obligate the purchasers to
purchase and the Company to sell and deliver certain quantities of natural gas
production on a monthly basis throughout the term of the contracts.
Company Headquarters. The Company owns an approximately 5,400
square foot building located in Canfield, Ohio.
ITEM 3. LEGAL PROCEEDINGS
There are no material pending legal proceedings to which the
Company is a party or to which any of its property is subject.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the fourth quarter of the fiscal year ended December
31, 2002, 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, 2003, there were 5,748,773 Units held by
1,434 holders of record.
Distribution History
The Company commenced operations with the consummation of the
Exchange Offer in February 1991. Management's stated intention was to make
quarterly cash distributions equal to $0.125 per Unit (or $0.50 per Unit on an
annualized basis) for the first eight quarters following the closing date of the
Exchange Offer. The Company has paid a quarterly distribution every quarter
since July 1991. The Company paid total cash distributions of $1.25 and $1.50
per Unit during 2002 and 2001, respectively. Based upon the current number of
Units outstanding, each quarterly distribution of $0.125 per Unit would be
approximately $727,000. The Company made a quarterly distribution of $0.25 per
Unit in January 2003 and currently intends to make a quarterly distribution of
$0.25 per Unit in April 2003 and quarterly distributions of at least $0.125 per
Unit in July and October 2003.
Repurchase Right
The Partnership Agreement provides, that beginning in 1992 and
annually thereafter, the Company offers to repurchase for cash up to 10% of the
then outstanding Units, to the extent Unitholders offer Units to the Company for
repurchase (the "Repurchase Right"). The Repurchase Right entitles any
Unitholder, between May 1 and June 30 of each year, to notify the Company that
he elects to exercise the Repurchase Right and have the Company acquire certain
or all of his Units. The price to be paid for any such Units is calculated based
on the method provided for in the Partnership Agreement. The Company accepted an
aggregate of 206,531, 117,488 and 22,401 of its Units of limited partnership
interest at a price of $6.11, $9.73 and $5.66 per Unit pursuant to the terms of
the Company's Offers to Purchase dated April 30, 2000, 2001 and 2002,
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,
--------------------------------------------------------------------------
2002 2001 2000 1999 1998
--------------------------------------------------------------------------
Revenue . . . . . . . . . . . . . . . $16,757,418 $16,261,220 $16,921,139 $15,063,170 $16,558,366
Net Income . . . . . . . . . . . . . . 8,004,090 7,842,162 8,590,757 5,445,941 6,897,089
Net Income Per Unit . . . . . . . . . 1.37 1.33 1.42 .88 1.10
Total Assets . . . . . . . . . . . . . 52,579,304 52,254,265 55,043,294 55,422,986 56,612,953
Debt(1). . . . . . . . . . . . . . . . - 512,014 637,822 692,289 2,255,898
Cash Distributions Per Unit . . . . . 1.25 1.50 1.25 .625 .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 $7.5 million as of December 31,
2002 represented a $0.5 million increase from December 31, 2001 due primarily to
increases in cash and equivalents of $3.6 million and accounts receivable from
oil and gas production of $1.1 million during 2002. This was partially offset by
increases in accounts payable of $0.2 million and decreases in short-term
investments of $3.8 million. In August 2001, the Company entered into an
agreement that
17
modified its prior credit agreement. The agreement provides for a revolving line
of credit in the amount of $4.0 million, 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
is currently in the process of renewing the facility and expects to do so every
two years to minimize debt origination, carrying and interest costs associated
with long-term bank commitments. The Company incurred no borrowings under the
revolving credit facilities during 2002. 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 22,401 Units at a price of $5.66 per Unit on June 30, 2002.
The Company also used cash flows to make cash distributions, which totaled $7.3
million.
The following table summarizes the Company's financial
position at December 31, 2002 and December 31, 2001:
December 31, 2002 December 31, 2001
------------------ ----------------
Amount % Amount %
------------------ ----------------
(Amounts in Thousands) (Amounts in Thousands)
Working capital $ 7,530 15% $ 6,985 14%
Property and equipment (net) 43,848 85 44,325 86
Other 130 -- 110 --
------- ------ ------- ---
Total $51,508 100% $51,420 100%
======= ====== ======= ===
Long-term debt $ -- --% $ 458 1%
Deferred income taxes -- -- 50 --
Partners' equity 51,508 100 50,912 99
------- ------ ------- ---
Total $51,508 100% $51,420 100%
======= ====== ======= ===
Cash Flows from Operating, Investing and Financing Activities
The Company generated almost all of its cash sources from operating
activities. During the years ended 2002 and 2001, 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, 2002 and 2001:
2002 2001
--------------------------------------------------------------------
Dollars % Dollars %
--------------------------------------------------------------------
(Amounts in Thousands)
Operating Activities:
Net income before adjustments $8,004 64% $7,842 59%
Adjustments 4,565 36 4,709 35
---------- ---------- ---------- ---------
Cash flow from operations
before working capital
changes 12,569 100 12,551 94
Changes in working capital 3,015 24 (77) (1)
---------- ---------- --------- --------
Net cash provided by
operating activities 15,584 124 12,474 93
Investing Activities:
Proceeds received on receivables
from officers and employees 197 1 274 2
Advances disbursed to officers
and employees (162) (1) (122) (1)
Purchase of property and
equipment (4,186) (33) (3,395) (25)
Proceeds on sale of other assets
and equipment 48 - - -
---------- ---------- ---------- ---------
Net cash (used) by investing
activities (4,103) (33) (3,243) (24)
Financing Activities:
Distributions (7,281) (58) (8,831) (66)
Repurchase of Units (127) (1) (1,143) (8)
Debt repayments (512) (4) (126) (1)
--------- --------- --------- --------
Net cash (used) by financing
activities (7,920) (63) (10,100) (75)
--------- --------- --------- --------
Increase (decrease) in cash
and equivalents 3,561 28 (869) (6)
Note: All items in the previous table are calculated as a percentage of total
cash sources. Total cash sources include the following items, if
positive: cash flow from operations before working capital changes,
changes in working capital, net cash provided by investing activities
and net cash provided by financing activities, plus any decrease in
cash and equivalents.
As the above table indicates, the Company's cash flow from
operations before working capital changes during the twelve months of 2002 and
2001 represented 100% and 94%
19
of total cash sources, respectively. Changes in working capital other than cash
and equivalents increased cash by $3.0 million during 2002 and decreased cash by
$77,037 during 2001. The decrease in short-term investments at December 31, 2002
compared to December 31, 2001 is the result of the Company's selling of
marketable corporate debt securities and investing excess cash flows in a high
balance savings account. The increase in accounts receivable at December 31,
2002 compared to December 31, 2001 is the result of higher natural gas
production volumes and an increase in gas and oil prices. Total production
revenues receivable as of December 31, 2002 amounted to $3.6 million compared to
$2.5 million at December 31, 2001. As a result of these increased gas production
volumes and an increase in gas and oil prices, accounts payable relating to
production as of December 31, 2002 was also higher. Accounts payable amounted to
$0.7 million as of December 31, 2002 compared to $0.5 million at December 31,
2001. The Company had investments in short-term marketable corporate debt
securities of $3.8 million at December 31, 2001.
The Company's cash flows used by investing activities
increased $0.9 million, or 27%, during 2002 as compared with 2001. The Company's
cash flows used by investing activities increased $0.7 million, or 28%, during
2001 as compared with 2000. The primary reason for the increase in cash flows
used by investing activities in 2002 and 2001 was an increase in the purchase of
property and equipment. The purchase of property and equipment increased $0.8
million, or 23%, during 2002 as compared with 2001. The purchase of property and
equipment increased $0.8 million, or 31%, during 2001 as compared with 2000.
The Company's cash flows used by financing activities
decreased $2.2 million, or 22%, during 2002 as compared with 2001. The primary
reasons for this decrease were that distributions to Unitholders decreased $1.6
million and payments on the repurchase of Units decreased $1.0 million. Payments
on debt increased $0.4 million to $0.5 million during 2002. The Company's cash
flows used by financing activities increased $1.2 million, or 14%, during 2001
as compared with 2000. The primary reason for this increase was that
distributions to Unitholders increased $1.3 million. Payments on debt increased
$71,341 to $125,808 during 2001. Additionally, payments on the repurchase of
Units decreased $118,746, or 9%, during 2001 as compared with 2000.
The Company's ending cash and equivalents balance of $4.7
million at December 31, 2002, 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 2003. The Company has paid a
quarterly distribution every quarter since July 1991. Minimum cash distributions
are estimated to be $0.7 million per quarter ($.125 per Unit). The Company
intends to distribute $1.5 million ($.25 per Unit) in April 2003 from existing
cash and equivalents.
Capital expenditures for the development of oil and gas
properties and the acquisition of undeveloped leasehold acreage have increased
over recent years. The Company drilled or participated in the drilling of an
additional 31 drillsites in 2002. The Company's share of these drillsites
amounts to 14.33 net developed properties. The Company's share of proved gas
reserves increased by 1.4 million MCFs, or 3%, between December 31, 2001 and
2002, while proved oil reserves decreased by 20,000 barrels, or 3%, between
December 31, 2001 and 2002.
20
The Company continues to develop primarily natural gas fields, as represented by
the discovery and addition of 2.0 million MCFs of natural gas versus 26,000
barrels of crude oil during 2002. The Standardized Measure of Discounted Future
Net Cash Flows of the Company's reserves increased by $22.8 million between
December 31, 2001 and 2002. The primary reason for this increase was due to
increases in natural gas and crude oil prices between December 31, 2001 and
2002. Management believes the Company should be able to drill or participate in
the drilling of 10 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 22,401, 117,488 and
206,531 Units during 2002, 2001 and 2000 pursuant to the Repurchase Right at a
price of $5.66, $9.73 and $6.11 per Unit, respectively. The Company has, in the
past, borrowed against its credit facility to meet such obligations and could do
so again in 2003, although current cash flows would reduce borrowing
requirements. The Repurchase Right to be conducted in 2003 will result in
Unitholders being offered a price of $8.44 per Unit. The Company estimates it
could need to borrow up to $3.0 million in the event the 2003 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, 2002, 2001 and
2000. 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,
--------------------------------------------
2002 2001 2000
--------------------------------------------
Revenues:
Oil and gas sales 97% 97% 97%
Well management and operating 3 3 3
----- ---- ----
Total Revenues 100 100 100
Expenses:
Production costs 16 15 13
Well management and operating 1 1 1
Depreciation, depletion and amortization 26 28 27
Abandonment and write down
of oil and gas properties 1 1 2
General and administrative 8 8 8
Other expense (income) - (1) (2)
Income taxes - - -
----- ---- ----
Total Expenses 52 52 49
----- ---- ----
Net income 48% 48% 51%
===== ==== ====
Revenues for the year ended December 31, 2002 increased $0.5
million, or 3%, compared to the same period in 2001. Revenues for the year ended
December 31, 2001 decreased $0.7 million, or 4%, compared to the same period in
2000. These changes were due primarily to changes in crude oil and natural gas
sales between the periods involved.
Oil and gas sales increased $0.4 million, or 3%, from 2001 to
2002. This increase was the result of increased natural gas production and
slightly higher natural gas prices. The Company's gas production increased by
97,000 MCF. The primary reason for this increase was due to increased production
resulting from the Company developing additional oil and gas properties. The
average price received per MCF increased from $3.93 to $3.98 from 2001 to 2002.
Oil sales were slightly lower due primarily to a decrease in the average sales
price of oil from $22.57 to $22.33 per barrel from 2001 to 2002. Additionally,
oil production decreased by 3,000 barrels. Gas sales accounted for 90%, 89% and
84% of total oil and gas sales in 2002, 2001 and 2000, respectively. Oil and gas
sales decreased $0.7 million, or 4%, from 2000 to 2001. The primary reasons for
this decrease in oil and gas sales between 2000 and 2001 were lower natural gas
production and lower crude oil production and crude oil prices. The Company's
gas production decreased by 613,000 MCF, although the average price received per
MCF increased from $3.32 to $3.93. The average price received per barrel
decreased from $27.82 to $22.57.
Production costs increased $0.2 million, or 8%, during 2002
and 2001. The primary reason for these increases was an increase in the number
of producing wells. Depreciation, depletion and amortization decreased $62,800,
or 1%, between 2001 and 2002. The primary reason for this decrease is higher oil
and gas reserve estimates resulting from higher natural gas and oil prices. The
result of higher oil and gas reserve estimates at December 31, 2002 reduced
depletion and amortization rates associated with the Company's producing oil and
22
gas properties. Depreciation, depletion and amortization decreased $61,242, or
1%, between 2000 and 2001. This decrease was caused by lower production volumes.
Well management and operating revenues increased $47,787, or
11%, from 2001 to 2002. Well management and operating costs increased $19,301,
or 11%, from 2001 to 2002. The reason for these increases in well management and
operating revenues and costs was due to an increase in Company operated oil and
gas interests. The Company added approximately 20 oil and gas properties to its
existing operations during 2002. Well management and operating revenues
increased $25,277, or 6%, from 2000 to 2001. Well management and operating costs
increased $45,672, or 37%, from 2000 to 2001.
Abandonments and write downs of oil and gas properties
remained constant between 2001 and 2002 and decreased $0.2 million between 2000
and 2001. This decrease was attributable to a reduction in the write down of oil
and gas properties and abandonments of oil and gas properties. During 2002 and
2001, the Company had no impairment on its oil and gas properties.
General and administrative expenses increased $34,743, or 3%,
between 2001 and 2002, and increased $37,118, or 3%, between 2000 and 2001. The
primary reason for these increases was an increase in overhead costs associated
with ongoing operations of the Company.
Net other income amounted to $46,968, $178,062, and $270,856
in 2002, 2001 and 2000, respectively. In 2002 and 2001, interest income and
interest expense 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 increased $161,928, or 2%, between 2001 and 2002.
The increase was primarily the result of an increase in oil and gas sales. Net
income decreased $748,595, or 9%, between 2000 and 2001. The decrease resulted
primarily from a decrease in oil and gas sales. Net income represented 48%, 48%
and 51% of total revenues during the years ended December 31, 2002, 2001 and
2000, respectively.
APPLICATION OF CRITICAL ACCOUNTING POLICIES
Property and Equipment. The Company uses the successful
efforts method of accounting for oil and gas exploration and production
activities. Under successful efforts, costs to acquire mineral interests in oil
and gas properties and to drill and equip development wells are initially
capitalized. Costs of development wells (on properties the Company has no
further interest in) that do not find proved reserves and geological and
geophysical costs are expensed. The Company has not participated in exploratory
drilling and owns no interest in unproved properties.
Capitalized costs of proved properties, after considering
estimated dismantlement and abandonment costs and estimated salvage values, are
amortized by the unit-of-production
23
method based upon estimated proved developed reserves. Depletion, depreciation
and amortization on proved properties amounted to $4,345,208, $4,417,473 and
$4,477,379 for the years ended December 31, 2002, 2001 and 2000, respectively.
On sale or retirement of a unit of a proved property (which
generally constitutes the amortization base), the cost and related accumulated
depreciation, depletion, amortization and write down are eliminated from the
property accounts, and the resultant gain or loss is recognized.
The Company evaluates its oil and gas properties for
impairment annually. SFAS No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets," requires that long-lived assets (including oil and gas
properties) and certain identifiable intangibles be reviewed for impairment
whenever events or changes in circumstances indicate that the carrying amount of
an asset may not be recoverable. Everflow utilizes a field by field basis for
assessing impairment of its oil and gas properties.
Management of the Company believes that the accounting
estimate related to oil and gas property impairment is a "critical accounting
estimate" because it is highly susceptible to change from year to year. It
requires the use of oil and gas reserve estimates that are directly impacted by
future oil and gas prices and future production volumes. Actual oil and gas
prices have fluctuated in the past and are expected to do so in the future.
Oil and gas reserve estimates are prepared annually based on
existing contractual arrangements and current market conditions. Any increases
in estimated future cash flows would have no impact on the reported value of the
Company's oil and gas properties. In contrast, decreases in estimated future
cash flows could require the recognition of an impairment loss equal to the
difference between the fair value of the oil and gas properties (determined by
calculating the discounted value of the estimated future cash flows) and the
carrying amount of the oil and gas properties. Any impairment loss would reduce
property and equipment as well as total assets of the Company. An impairment
loss would also decrease net income.
Revenue Recognition. The Company recognizes revenue from oil
and gas production as it is extracted and sold from the properties. Other
revenue is recognized at the time it is earned and the Company has a contractual
right to such revenue.
The Company participates (and may act as drilling contractor)
with unaffiliated joint venture partners in the drilling, development and
operation of jointly owned oil and gas properties. Each owner, including the
Company, has an undivided interest in the jointly owned property(ies).
Generally, the joint venture partners participate on the same
drilling/development cost basis as the Company and, therefore, no revenue,
expense or income is recognized on the drilling and development of the
properties. Accounts receivable from joint venture partners consist principally
of drilling and development costs the Company has advanced or incurred on behalf
of joint venture partners. The Company earns and receives monthly management and
operating fees from certain joint venture partners after the properties are
completed and placed into production.
24
NEW ACCOUNTING STANDARDS
In June 2001, the Financial Accounting Standards Board
("FASB") issued SFAS No. 142, "Goodwill and Other Intangible Assets." Under SFAS
No. 142, goodwill and intangible assets deemed to have indefinite lives are no
longer amortized but are subject to periodic impairment tests. Other intangible
assets continue to be amortized over their useful lives. SFAS No. 142 was
adopted by the Company in 2002.
In August 2001, the 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 tangible long-lived assets and the associated
asset retirement cost.
In October 2001, the FASB issued SFAS No. 144, "Accounting for
the Impairment or Disposal of Long-lived Assets," which was adopted by the
Company in 2002. SFAS No. 144 supercedes SFAS No. 121 and modifies and expands
the financial accounting and reporting for the impairment or disposal of
long-lived assets other than goodwill.
In April 2002, the FASB issued SFAS No. 145, "Rescission of
FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and
Technical Corrections." Provisions of SFAS No. 145 become effective in 2002 and
2003. Under SFAS No. 145, gains and losses from the extinguishment of debt
should be classified as extraordinary items only if they meet the criteria of
Accounting Principles Board Opinion No. 30. SFAS No. 145 also addresses
financial accounting and reporting for capital leases that are modified in such
a way as to give rise to a new agreement classified as an operating lease.
In June 2002, the FASB issued SFAS No. 146, "Accounting for
Costs Associated with Exit or Disposal Activities," which is effective for exit
or disposal activities initiated after December 31, 2002. SFAS No. 146 nullifies
Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain
Employee Termination Benefits and Other Costs to Exit an Activity (including
Certain Costs Incurred in a Restructuring)." Under SFAS No. 146, a liability is
required to be recognized for costs, including certain lease termination costs
and employee termination benefits, associated with an exit or disposal activity
when the liability is incurred. SFAS No. 146 applies to costs associated with an
exit activity that does not involve an entity newly acquired in a business
combination or with a retirement or disposal activity covered by SFAS Nos. 143
and 144.
In November 2002, the FASB issued FIN 45, which expands
previously issued accounting guidance and disclosure requirements for certain
guarantees. FIN 45 requires the recognition of an initial liability for the fair
value of an obligation assumed by issuing a guarantee. The provision for initial
recognition and measurement of the liability will be applied on a prospective
basis to guarantees issued or modified after December 31, 2002.
In December 2002, the FASB issued SFAS No. 148, "Accounting
for Stock-Based, Compensation - Transition and Disclosure," that amends SFAS No.
123, "Accounting for Stock-Based Compensation," to provide alternative methods
of transition to the fair value
25
method of accounting for stock-based employee compensation. SFAS No. 148 also
amends the disclosure provisions of SFAS No. 123 and APB Opinion No. 28,
"Interim Financial Reporting," to require disclosure in the summary of
significant accounting policies of the effects of an entity's accounting policy
with respect to stock-based employee compensation on reported net income and
earnings per share in annual and interim financial statements. The Statement
does not amend SFAS No. 123 to require companies to account for employee stock
options using the fair value method. The Statement is effective for fiscal years
beginning after December 15, 2002.
The adoption of the new standards did not, or is not expected
to, materially affect the Company's financial position and results of
operations.
INFLATION AND CHANGES IN PRICES
While the cost of operations is affected by inflation, oil and
gas prices have fluctuated in recent years and generally have not matched
inflation. The price of oil in the Appalachian Basin has ranged from a low of
$8.50 per barrel in December 1998 to a high of $34.25 in March 2003. As of March
20, 2003, the posted field price in the Appalachian Basin area, the Company's
principal area of operation, was $26.50 per barrel of oil. Although the
Company's sales are affected by this type of price instability, the impact on
the Company is not as dramatic as might be expected since less than 10% of the
Company's total future cash inflows related to oil and gas reserves as of
December 31, 2002 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 2000
amounted to $3.32 per MCF. The Company's average price of gas during 2001
increased $.61 to $3.93 compared to 2000. The Company's average price of gas
during 2002 increased $.05 to $3.98 compared to 2001. The price of gas in the
Appalachian Basin increased significantly throughout 2000 and reached a high of
more than $10.00 per MCF in January 2001. More recently, the price of natural
gas on the NYMEX settled for the month of March 2003 at $9.13 per MCF. The
Company's gas is currently sold under short-term contracts where the price is
determined using 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, 2003, the current one-year strip price for Henry
Hub Natural Gas on the NYMEX is $5.25 per MCF. The Company's sales are
significantly impacted by pricing instability in the natural gas market. One of
the consequences of these pricing fluctuations is evident in the Company's
Standardized Measure of Discounted Future Net Cash Flows decreasing from $82.0
million at December 31, 2000 to $45.1 million at December 31, 2001, and then
increasing to $67.9 million at December 31, 2002.
The Company's Standardized Measure of Discounted Future Net
Cash Flows increased by $22.8 million from December 31, 2001 to December 31,
2002 and decreased by $36.9 million from December 31, 2000 to December 31, 2001.
A reconciliation of the Changes
26
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, 2002, the Company had no long-term debt outstanding.
The Company is also exposed to market risk from changes in
commodity prices. Realized pricing is primarily driven by the prevailing
worldwide prices for crude oil and spot market prices applicable to United
States natural gas production. Pricing for gas and oil production has been
volatile and unpredictable for many years. These market risks can impact the
Company's results of operations, cash flows and financial position. The
Company's primary commodity price risk exposure results from contractual
delivery commitments with respect to the Company's gas purchase contracts. The
Company periodically makes commitments to sell certain quantities of natural gas
to be delivered in future months at certain contract prices. This affords the
Company the opportunity to "lock in" the sale price for those quantities of
natural gas. Failure to meet these delivery commitments would result in the
Company being forced to purchase any short fall at current market prices. The
Company's risk management objective is to lock in a range of pricing for no more
than 80% to 90% of expected production volumes. This allows the Company to
forecast future cash flows and earnings within a predictable range.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See attached pages F-1 to F-24.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
Not applicable.
27
EVERFLOW EASTERN PARTNERS, L. P.
2002 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, 2002 and 2001, and
the related consolidated statements of income, partners' equity, and cash flows
for each of the three years in the period ended December 31, 2002. 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, 2002 and
2001, and the consolidated results of their operations and their cash flows for
each of the three years in the period ended December 31, 2002, in conformity
with accounting principles generally accepted in the United States of America.
HAUSSER + TAYLOR LLP
Cleveland, Ohio
March 19, 2003
F-3
EVERFLOW EASTERN PARTNERS, L. P.
CONSOLIDATED BALANCE SHEETS
December 31, 2002 and 2001
2002 2001
------------ ------------
ASSETS
CURRENT ASSETS
Cash and equivalents $ 4,689,831 $ 1,128,835
Accounts receivable:
Production 3,557,396 2,475,123
Officers and employees 220,764 255,448
Joint venture partners 30,630 121,458
Short-term investments -- 3,790,562
Other 102,245 47,998
------------ ------------
Total current assets 8,600,866 7,819,424
PROPERTY AND EQUIPMENT
Proved properties (successful efforts accounting method) 118,513,983 114,964,451
Pipeline and support equipment 514,060 504,222
Corporate and other 1,587,219 1,465,910
------------ ------------
120,615,262 116,934,583
Less accumulated depreciation, depletion, amortization
and write down 76,766,803 72,609,314
------------ ------------
43,848,459 44,325,269
OTHER ASSETS 129,979 109,572
------------ ------------
$ 52,579,304 $ 52,254,265
------------ ------------
The accompanying notes are an integral part of these financial statements.
F-4
EVERFLOW EASTERN PARTNERS, L. P.
CONSOLIDATED BALANCE SHEETS
December 31, 2002 and 2001
2002 2001
----------- -----------
LIABILITIES AND PARTNERS' EQUITY
CURRENT LIABILITIES
Current portion of long-term debt $ -- $ 53,900
Accounts payable 746,421 505,246
Accrued expenses 324,627 275,010
----------- -----------
Total current liabilities 1,071,048 834,156
LONG-TERM DEBT, NET OF CURRENT PORTION -- 458,114
DEFERRED INCOME TAXES -- 50,000
COMMITMENTS AND CONTINGENCIES
LIMITED PARTNERS' EQUITY, SUBJECT TO REPURCHASE
RIGHT
Authorized - 8,000,000 units
Issued and outstanding - 5,748,773 and 5,771,174 units,
respectively 50,914,003 50,326,874
GENERAL PARTNER'S EQUITY 594,253 585,121
----------- -----------
Total partners' equity 51,508,256 50,911,995
----------- -----------
$52,579,304 $52,254,265
=========== ===========
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, 2002, 2001 and 2000
2002 2001 2000
------------ ------------ ------------
REVENUES
Oil and gas sales $ 16,254,014 $ 15,805,040 $ 16,490,904
Well management and operating 501,561 453,774 428,497
Other 1,843 2,406 1,738
------------ ------------ ------------
16,757,418 16,261,220 16,921,139
DIRECT COST OF REVENUES
Production costs 2,618,399 2,419,260 2,244,926
Well management and operating 188,238 168,937 123,265
Depreciation, depletion and amortization 4,386,745 4,449,545 4,510,787
Abandonment and write down of oil and gas
properties 200,000 200,000 400,000
------------ ------------ ------------
Total direct cost of revenues 7,393,382 7,237,742 7,278,978
GENERAL AND ADMINISTRATIVE EXPENSE 1,394,121 1,359,378 1,322,260
------------ ------------ ------------
Total cost of revenues 8,787,503 8,597,120 8,601,238
------------ ------------ ------------
INCOME FROM OPERATIONS 7,969,915 7,664,100 8,319,901
OTHER INCOME (EXPENSE)
Interest income 69,515 222,764 316,091
Interest expense (28,521) (44,702) (46,239)
Gain on sale of property and equipment and other
assets 5,974 -- 1,004
------------ ------------ ------------
46,968 178,062 270,856
------------ ------------ ------------
INCOME BEFORE INCOME TAXES 8,016,883 7,842,162 8,590,757
INCOME TAXES 12,793 -- --
------------ ------------ ------------
NET INCOME $ 8,004,090 $ 7,842,162 $ 8,590,757
------------ ------------ ------------
Allocation of Partnership Net Income
Limited Partners $ 7,911,924 $ 7,752,932 $ 8,495,622
General Partner 92,166 89,230 95,135
------------ ------------ ------------
$ 8,004,090 $ 7,842,162 $ 8,590,757
------------ ------------ ------------
Net income per unit $ 1.37 $ 1.33 $ 1.42
------------ ------------ ------------
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, 2002, 2001 and 2000
2002 2001 2000
---- ---- ----
PARTNERS' EQUITY - JANUARY 1 $ 50,911,995 $ 53,043,829 $ 53,288,759
Net income 8,004,090 7,842,162 8,590,757
Cash distributions ($1.25 per unit in 2002, $1.50 per
unit in 2001 and $1.25 per unit in 2000) (7,281,039) (8,830,838) (7,573,783)
Purchase and retirement of Units (126,790) (1,143,158) (1,261,904)
------------ ------------ ------------
PARTNERS' EQUITY - DECEMBER 31 $ 51,508,256 $ 50,911,995 $ 53,043,829
============ ============ ============
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, 2002, 2001 and 2000
2002 2001 2000
---- ---- ----
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 8,004,090 $ 7,842,162 $ 8,590,757
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 4,421,028 4,508,950 4,569,114
Abandonment and write down of oil and gas
properties 200,000 200,000 400,000
Gain on sale of property and equipment and other
assets (5,974) -- (1,004)
Deferred income taxes (50,000) -- --
Changes in assets and liabilities:
Accounts receivable (991,445) 596,362 (678,290)
Short-term investments 3,790,562 (167,188) (2,110,101)
Other current assets (54,247) 31,731 9,262
Other assets (20,407) (6,555) 41,629
Accounts payable 241,175 (513,713) (183,646)
Accrued expenses 49,617 (17,674) 103,351
------------ ------------ ------------
Total adjustments 7,580,309 4,631,913 2,150,315
------------ ------------ ------------
Net cash provided by operating activities 15,584,399 12,474,075 10,741,072
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds received on receivables from officers and
employees 197,364 273,447 248,692
Advances disbursed to officers and employees (162,680) (122,053) (129,504)
Purchase of property and equipment (4,185,744) (3,394,808) (2,594,116)
Purchase of other assets -- -- (64,050)
Proceeds on sale of property and equipment and
other assets 47,500 -- 1,433
------------ ------------ ------------
Net cash used by investing activities (4,103,560) (3,243,414) (2,537,545)
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions (7,281,039) (8,830,838) (7,573,783)
Repurchase of Units (126,790) (1,143,158) (1,261,904)
Payments on debt including revolver (512,014) (125,808) (54,467)
------------ ------------ ------------
Net cash used by financing activities (7,919,843) (10,099,804) (8,890,154)
------------ ------------ ------------
NET INCREASE (DECREASE) IN CASH AND
EQUIVALENTS 3,560,996 (869,143) (686,627)
CASH AND EQUIVALENTS - JANUARY 1 1,128,835 1,997,978 2,684,605
------------ ------------ ------------
CASH AND EQUIVALENTS - DECEMBER 31 $ 4,689,831 $ 1,128,835 $ 1,997,978
------------ ------------ ------------
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest $ 28,521 $ 42,656 $ 46,239
Income taxes 80,000 -- --
The accompanying notes are an integral part of these financial statements.
F-8
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Organization - Everflow Eastern Partners, L. P. ("Everflow") is a
Delaware limited partnership which was organized in September
1990 to engage in the business of oil and gas exploration and
development. Everflow was formed to consolidate the business and
oil and gas properties of Everflow Eastern, Inc. ("EEI") and
subsidiaries and the oil and gas properties owned by certain
limited partnership and working interest programs managed or
sponsored by EEI ("EEI Programs" or "the Programs").
Everflow Management Limited, LLC, an Ohio limited liability
company, is the general partner of Everflow and, as such, is
authorized to perform all acts necessary or desirable to carry
out the purposes and conduct of the business of Everflow. The
members of Everflow Management Limited, LLC are Everflow
Management Corporation ("EMC"), two individuals who are Officers
and Directors of EEI and Sykes Associates, a limited partnership
controlled by Robert F. Sykes, the Chairman of the Board of EEI.
EMC is an Ohio corporation formed in September 1990 and is the
managing member of Everflow Management Limited, LLC.
B. Principles of Consolidation - The consolidated financial
statements include the accounts of Everflow, its wholly-owned
subsidiaries, including EEI and EEI's wholly-owned subsidiaries,
and investments in oil and gas drilling and income partnerships
(collectively, the "Company") which are accounted for under the
proportional consolidation method. All significant accounts and
transactions between the consolidated entities have been
eliminated.
C. Use of Estimates - The preparation of financial statements in
conformity with accounting principles generally accepted in the
United States of America requires management to make estimates
and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities
at the date of the financial statements and the reported amounts
of revenues and expenses during the reporting period. Actual
results could differ from those estimates.
D. Fair Value of Financial Instruments - The fair values of cash and
equivalents, accounts receivable, 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 and 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 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
$4,345,208, $4,417,473 and $4,477,379 for the years ended
December 31, 2002, 2001 and 2000, respectively.
On sale or retirement of a unit of a proved property (which
generally constitutes the amortization base), the cost and
related accumulated depreciation, depletion, amortization and
write down are eliminated from the property accounts, and the
resultant gain or loss is recognized.
SFAS No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets," requires that long-lived assets (including
oil and gas properties) and certain identifiable intangibles be
reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may
not be recoverable. Everflow utilizes a field by field basis for
assessing impairment of its oil and gas properties. The Company
wrote down oil and gas properties by approximately $200,000,
$200,000 and $400,000 during 2002, 2001 and 2000, 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
$992,051 - 40 years). Depreciation on pipeline and support
equipment and other corporate property and equipment amounted to
$75,820, $91,477 and $91,735 for the years ended December 31,
2002, 2001 and 2000, 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 5,759,974, 5,829,918 and 5,991,928 in
2002, 2001 and 2000, 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 2001, the Financial Accounting
Standards Board ("FASB") issued SFAS No. 142, "Goodwill and Other
Intangible Assets." Under SFAS No. 142, goodwill and intangible
assets deemed to have indefinite lives are no longer amortized
but are subject to periodic impairment tests. Other intangible
assets continue to be amortized over their useful lives. SFAS No.
142 was adopted by the Company in 2002.
In August 2001, the 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 tangible long-lived assets and the associated asset
retirement cost.
In October 2001, the FASB issued SFAS No. 144, "Accounting for
the Impairment or Disposal of Long-lived Assets," which was
adopted by the Company in 2002. SFAS No. 144 supercedes SFAS No.
121 and modifies and expands the financial accounting and
reporting for the impairment or disposal of long-lived assets
other than goodwill.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB
Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13,
and Technical Corrections." Provisions of SFAS No. 145 become
effective in 2002 and 2003. Under SFAS No. 145, gains and losses
from the extinguishment of debt should be classified as
extraordinary items only if they meet the criteria of Accounting
Principles Board Opinion No. 30. SFAS No. 145 also addresses
financial accounting and reporting for capital leases that are
modified in such a way as to give rise to a new agreement
classified as an operating lease.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities," which is effective
for exit or disposal activities initiated after December 31,
2002. SFAS No. 146 nullifies Emerging Issues Task Force Issue No.
94-3, "Liability Recognition for Certain Employee Termination
Benefits and Other Costs to Exit an Activity (including Certain
Costs Incurred in a Restructuring)." Under SFAS No. 146, a
liability is required to be recognized for costs, including
certain lease termination costs and employee termination
benefits, associated with an exit or disposal activity when the
liability is incurred. SFAS No. 146 applies to costs associated
with an exit activity that does not involve an entity newly
acquired in a business combination or with a retirement or
disposal activity covered by SFAS Nos. 143 and 144.
In November 2002, the FASB issued FIN 45, which expands
previously issued accounting guidance and disclosure requirements
for certain guarantees. FIN 45 requires the recognition of an
initial liability for the fair value of an obligation assumed by
issuing a guarantee. The provision for initial recognition and
measurement of the liability will be applied on a prospective
basis to guarantees issued or modified after December 31, 2002.
F-12
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 (Continued)
In December 2002, the FASB issued SFAS No. 148, "Accounting for
Stock-Based, Compensation - Transition and Disclosure," that
amends SFAS No. 123, "Accounting for Stock-Based Compensation,"
to provide alternative methods of transition to the fair value
method of accounting for stock-based employee compensation. SFAS
No. 148 also amends the disclosure provisions of SFAS No. 123 and
APB Opinion No. 28, "Interim Financial Reporting," to require
disclosure in the summary of significant accounting policies of
the effects of an entity's accounting policy with respect to
stock-based employee compensation on reported net income and
earnings per share in annual and interim financial statements.
The Statement does not amend SFAS No. 123 to require companies to
account for employee stock options using the fair value method.
The Statement is effective for fiscal years beginning after
December 15, 2002.
The adoption of the new standards did not, or is not expected to,
materially affect the Company's financial position and results of
operations.
NOTE 2. SHORT-TERM INVESTMENTS
Short-term investments as of December 31, 2001 consisted 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.
There were no borrowings outstanding on revolving credit facilities
during 2002 and 2001.
The Company purchased a building and funded its cost, including
improvements, in part, through mortgage notes. The notes had an
aggregate balance of $512,014 at December 31, 2001 and bore interest
at a weighted average rate of 6.51%. The notes were paid in full in
2002.
F-13
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 3. CREDIT FACILITIES AND LONG-TERM DEBT (CONTINUED)
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.
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.
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,
2002 calculation, is estimated to be $8.44 per Unit, net of the
distributions ($.50 per Unit in total) expected to be made in
January and April 2003.
F-14
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 4. PARTNERS' EQUITY (CONTINUED)
Units repurchased pursuant to the repurchase right, for each of
the four years in the period ended December 31, 2002, are as
follows:
Per Unit
--------------------------------------------
Calculated Units
Price for Less Outstanding
Repurchase Interim Net # of Units Following
Year Right Distributions Price Paid Repurchased Repurchase
---- ----- ------------- ---------- ----------- ----------
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
2002 $ 6.16 $ .50 $ 5.66 22,401 5,748,773
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.
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,
-----------------------------------------------------------------------------
2002 2001 2000
------------------------- ------------------------- -------------------------
Amount % Amount % Amount %
------ ----- ------- --- ------- ---
Provision based on the
statutory rate (for taxable
income up to $10,000,000) $ 2,726,000 34.0 $ 2,666,000 34.0 $ 2,921,000 34.0
Tax effect of:
Non-taxable status of the
Programs and Everflow (2,579,000) (32.2) (2,654,000) (33.8) (2,965,000) (34.5)
Excess statutory depletion (60,000) (0.7) (70,000) (0.9) (83,000) (1.0)
Graduated tax rates, state
income tax and other - net (74,207) (1.0) 58,000 0.7 127,000 1.5
---------- ----- ----------- ----- ----------- -----
Total $ 12,793 0.1 $ - - $ - -
========== ===== =========== ===== =========== =====
EEI has percentage depletion deduction carryforwards for tax purposes
of approximately $1,860,000. These carryforwards can be carried
forward indefinitely. For financial reporting purposes, the deferred
tax liability at December 31, 2002 and 2001 has been reduced by
approximately $629,000 and $661,000, respectively, for the tax effect
of carryforwards.
F-15
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 6. RETIREMENT PLAN
The Company has a defined contribution plan pursuant to Section
401(k) of the Internal Revenue Code for all employees who have
reached the age of 21 and completed one year of service. The
Company matches employees' contributions to the 401(K) Retirement
Savings Plan as annually determined by EMC's Board of Directors.
Additionally, the plan has a profit sharing component which
provides for contributions to the plan at the discretion of EMC's
Board of Directors. Amounts contributed to the plan vest
immediately. The Company's total matching and profit sharing
contributions to the plan amounted to $217,301, $76,275 and
$52,683 for the years ended December 31, 2002, 2001 and 2000,
respectively.
NOTE 7. RELATED PARTY TRANSACTIONS
The Company's Officers, Directors, Affiliates and certain
employees have frequently participated, and will likely
participate in the future, as working interest owners in wells in
which the Company has an interest. Frequently, the Company has
loaned the funds necessary to participate in the drilling and
development of such wells. 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 90%, 89% and 84% of total oil and gas
sales in 2002, 2001 and 2000, respectively. Approximate
percentages of total oil and gas sales from significant
purchasers for the years ended December 31, 2002, 2001 and 2000,
respectively, were as follows:
Customer 2002 2001 2000
-------- ---- ---- ----
Dominion Field Services, Inc., its affiliates and
its predecessors ("Dominion") 49% 45% 53%
Ergon Oil Purchasing, Inc. ("Ergon Oil") 8 11 16
Interstate Gas Supply, Inc. ("IGS") 23 25 11
-- -- --
80% 81% 80%
== == ==
A significant portion of the Company's production accounts
receivable is due from the Company's major customers. The Company
does not view such concentration as an unusual credit risk.
However, the Company does not require collateral from its
customers and could incur losses if its customers fail to pay.
Credit losses have historically been minimal and no valuation
allowance was deemed necessary at December 31, 2002 and 2001. The
Company expects that Dominion, Ergon Oil and IGS will be the only
major customers in 2003.
Over the ten years prior to 2002, the Company had been selling a
significant portion of its natural gas pursuant to Intermediate
Term Adjustable Price Gas Purchase Agreements with Dominion. The
Company's last remaining long-term agreement terminated during
2001 and was replaced by 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 significant gas
purchase contracts, including weighted average pricing
provisions, with Dominion follows:
Production Period November 2002 through March 2003 (Dominion)
The first 200,000 MCF per month is priced at $4.18 per MCF. An
additional 100,000 MCF is priced at $4.39 per MCF for November
2002. All gas in excess of these volumes is priced at the NYMEX
settled price plus $.45.
Production Period April 2003 through October 2003 (Dominion)
The first 140,000 MCF per month is priced at $4.10 per MCF. An
additional 30,000 MCF is priced at $8.05 per MCF for June 2003.
An additional 60,000 MCF is priced at $4.31 per MCF for June
2003. All gas in excess of these volumes is priced at the NYMEX
settled price plus $.45.
Production Period November 2003 through March 2004 (Dominion)
The first 160,000 MCF per month is priced at $4.65 per MCF. An
additional 60,000 MCF is priced at $5.27 per MCF for November
2003. All gas in excess of these volumes is priced at 100% (DTI)
Inside FERC plus $.25.
F-17
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 8. BUSINESS SEGMENTS, RISKS AND MAJOR CUSTOMERS (CONTINUED)
Production Period April 2004 through October 2004 (Dominion)
The first 100,000 MCF is priced at $4.42 per MCF. An additional
20,000 MCF is priced at $4.18 per MCF for June 2004. All gas in
excess of these volumes is priced at 100% (DTI) Inside FERC plus
$.25.
The Company also has a short-term contract with IGS, which
obligates IGS to purchase, and the Company to sell and deliver,
certain quantities of natural gas production on a monthly basis
throughout the contract periods. A summary of significant gas
purchase contracts, including weighted average pricing
provisions, with IGS follows:
Production Period November 2002 through March 2003 (IGS)
The first 100,000 MCF per month is priced at $4.12 per MCF. An
additional 40,000 MCF is priced at $4.53 per MCF for November
2002. All gas in excess of these volumes is priced at the NYMEX
settled price plus $.57.
Production Period April 2003 through October 2003 (IGS)
The first 60,000 MCF per month is priced at $4.00 per MCF. An
additional 20,000 MCF is priced at $8.05 per MCF for April 2003.
An additional 30,000 MCF is priced at $4.18 per MCF for June
2003. All gas in excess of these volumes is priced at the NYMEX
settled price plus $.27.
Production Period November 2003 through March 2004 (IGS)
The first 80,000 MCF per month is priced at $4.38 per MCF. An
additional 40,000 MCF is priced at $4.82 per MCF for November
2003. All gas in excess of these volumes is priced at the NYMEX
settled price plus $.45.
Production Period April 2004 through October 2004 (IGS)
The first 60,000 MCF per month is priced at $4.48 per MCF. An
additional 20,000 MCF is priced at $4.22 per MCF for June 2004.
All gas in excess of these volumes is priced at the NYMEX settled
price plus $.45.
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, 2002, natural gas
purchased by Dominion covers production from approximately 430
gross wells, while natural gas purchased by IGS covers production
from approximately 220 gross wells. Production from the Dominion
and IGS contract wells comprise more than 75% of the Company's
natural gas sales.
F-18
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 9. COMMITMENTS AND CONTINGENCIES
Everflow paid a dividend in January 2003 of $.25 per Unit. The
distribution amounted to approximately $1,454,000.
As described in Note 8, the Company has significant natural gas
delivery commitments to Dominion and IGS, its major customers.
Management believes the Company can meet its delivery commitments
based on estimated production. If, however, the Company cannot
meet its delivery commitments, it will purchase gas at market
prices to meet such commitments which will result in a gain or
loss for the difference between the delivery commitment price and
the price the Company is able to purchase the gas for redelivery
(resale) to its customers.
NOTE 10. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
The following is a summary of selected quarterly financial data
for the years ended December 31, 2002 and 2001:
Quarters Ended
----------------------------------------------------------------------
March 31 June 30 September 30 December 31
-------- ------- ------------ -----------
2002
Revenues $ 4,248,354 $ 3,440,791 $ 3,838,431 $ 5,229,842
Income from operations 1,730,635 1,516,254 1,784,596 2,938,430
Net income 1,763,611 1,555,732 1,789,796 2,894,951
Net income per unit .30 .27 .31 .50
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
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,
---------------------------------------------------------
2002 2001 2000
---- ---- ----
Proved oil and gas properties $ 118,513,983 $ 114,964,451 $ 112,341,851
Pipeline and support equipment 514,060 504,222 504,222
------------- ------------ ------------
119,028,043 115,468,673 112,846,073
Accumulated depreciation, depletion,
amortization and write down 76,478,321 72,365,538 68,469,693
------------- ------------ ------------
Net capitalized costs $ 42,549,722 $ 43,103,135 $ 44,376,380
============= ============ ============
COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
December 31,
---------------------------------------------------
2002 2001 2000
---- ---- ----
Property acquisition costs $ 230,175 $ 234,786 $ 175,875
Development costs, including
prepayments 3,728,193 3,135,374 2,333,387
In 2002, 2001 and 2000, development costs include the purchase of approximately
$222,000, $309,000 and $-0-, 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,
------------------------------------------------
2002 2001 2000
------------ ------------ ------------
Oil and gas sales $ 16,254,014 $ 15,805,040 $ 16,490,904
Production costs (2,618,399) (2,419,260) (2,244,926)
Depreciation, depletion and
amortization (4,386,745) (4,449,545) (4,510,787)
Abandonment and write down of
oil and gas properties (200,000) (200,000) (400,000)
------------ ------------ ------------
9,048,870 8,736,235 9,335,191
Income tax expense 75,000 100,000 100,000
------------ ------------ ------------
Results of operations for oil and gas
producing activities (excluding
corporate overhead and financing
costs) $ 8,973,870 $ 8,636,235 $ 9,235,191
============ ============ ============
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, 2000 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
Extensions, discoveries and other
additions 26,000 1,992,000
Production (73,000) (3,680,000)
Revision of previous estimates 27,000 3,070,000
-------- -----------
Balance, December 31, 2002 699,000 43,307,000
======== ===========
PROVED DEVELOPED RESERVES:
December 31, 1999 875,000 51,506,000
December 31, 2000 914,000 48,534,000
December 31, 2001 719,000 41,925,000
December 31, 2002 699,000 43,307,000
The Company has not determined proved reserves associated with its proved
undeveloped acreage. At December 31, 2002 and 2001, the Company had 640 and 700
net proved undeveloped acres, respectively. The carrying cost of the proved
undeveloped acreage that is included in proved properties amounted to $372,544
and $528,208 at December 31, 2002 and 2001, 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,
----------------------------------
2002 2001 2000
-------- -------- --------
(Thousands of Dollars)
Future cash inflows from sales of oil
and gas $212,322 $138,032 $248,711
Future production and development
costs 76,048 57,159 81,641
Future income tax expense 2,782 1,675 3,971
-------- -------- --------
Future net cash flows 133,492 79,198 163,099
Effect of discounting future net cash
flows at 10% per annum 65,558 34,104 81,125
-------- -------- --------
Standardized measure of discounted
future net cash flows $ 67,934 $ 45,094 $ 81,974
======== ======== ========
CHANGES IN THE STANDARDIZED MEASURE OF
DISCOUNTED FUTURE NET CASH FLOWS
Year Ended December 31,
------------------------------------
2002 2001 2000
-------- -------- --------
(Thousands of Dollars)
Balance, beginning of year $ 45,094 $ 81,974 $ 53,693
Extensions, discoveries and other
additions 3,817 2,814 2,141
Development costs incurred 617 313 245
Revision of previous estimates 5,209 (5,833) 1,133
Sales of oil and gas, net of production
costs (13,636) (13,386) (14,246)
Net change in income taxes (467) 1,042 (708)
Net changes in prices and production
costs 22,206 (30,076) 28,769
Accretion of discount 4,509 8,197 5,369
Other 585 49 5,578
-------- -------- --------
Balance, end of year $ 67,934 $ 45,094 $ 81,974
======== ======== ========
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 (adjusted for
periods beyond the contract period to year-end market prices)
applicable to expected natural gas production, estimated
production of proved crude oil and natural gas reserves,
estimated future production and development costs of reserves,
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
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, 2003 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, 2003 are as follows:
Positions and Positions and
Name Age Offices with EEI Offices with EMC
- --------------------------- --- ----------------------------- ----------------------------
Robert F. Sykes 79 Chairman of the Board Chairman of the Board
and Director
Thomas L. Korner 49 President and Director President and Director
David A. Kidder 64 Treasurer None
William A. Siskovic 47 Vice President, Secretary, Vice President, Secretary-
Principal Financial and Treasurer, Principal
Accounting Officer and Financial and Accounting
Director Officer and Director
All directors of EEI are elected to serve by the Company, which is EEI's sole
shareholder. All officers of EEI serve at the pleasure of the Board of
Directors. Directors and officers of EEI
28
receive no compensation or fees for their services to EEI or their services on
behalf of the Company.
All directors and officers of EMC hold their positions with
EMC pursuant to a shareholders' agreement among EMC and such directors and
officers. The shareholders agreement controls the operation of EMC, provides for
changes in share ownership of EMC, and determines the identity of the directors
and officers of EMC as well as their replacements.
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 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
29
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 2002.
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, 2002, 2001 and 2000, of those persons
who were, at December 31, 2002: (i) the chief executive officer; and (ii) the
other highly compensated executive officer of the Company. The Chief Executive
Officer and such other executive officer are hereinafter referred to
collectively as the "Named Executive Officers."
30
SUMMARY COMPENSATION TABLE
Annual Compensation
----------------------------------------------------------
Other
Annual All Other
Name and Compen- Compen-
Principal Position Year Salary Bonus sation(2) sation(1)
------------------ ---- ------ ----- -------- -----------
Thomas L. Korner 2002 $ 84,000 $ 66,000 $ 2,088 $ 19,332
President 2001 83,000 72,500 1,821 9,330
2000 80,000 40,000 2,008 7,200
William A. Siskovic 2002 $ 84,000 $ 66,000 2,264 19,313
Vice President and 2001 83,000 72,500 1,544 9,330
Principal Financial and 2000 80,000 40,000 1,749 7,200
Accounting Officer
- ----------
No Named Executive Officer received personal benefits or perquisites during
2002, 2001 and 2000 in excess of the lesser of $50,000 or 10% of his aggregate
salary and bonus.
(1) Includes amounts contributed under the Company's 401(K) Retirement Savings
Plan. The Company matched employees' contributions to the 401(K) Retirement
Savings Plan to the extent of 100% of the first 6% of a participant's
salary reduction. Also includes amounts contributed under the profit
sharing component of the Company's 401(K) Retirement Savings Plan. The
amounts attributable to the Company's matching and profit sharing
contributions vest immediately.
(2) Includes amounts considered taxable wages with respect to the Company's
Group Term Life Insurance Plan.
The General Partner, EMC and the members do not receive any separate
compensation or reimbursement for their management efforts on behalf of the
Company. All direct and indirect costs incurred by the Company are borne by the
General Partner of the Company and the Unitholders as Limited Partners of the
Company in proportion to their respective interest in the Company. The members
are not entitled to any fees or other compensation as a result of the
acquisition or operation of oil and gas properties by the Company. The members,
in their individual capacities, are not entitled to share in distributions from
or income of the Company on an ongoing basis, upon liquidation or otherwise. The
members only share in the revenues, income and distributions of the Company
indirectly through their ownership of the General Partner of the Company. The
General Partner is entitled to share in the income and expense of the Company on
the basis of its interests in the Company. The General Partner through it
predecessor, Everflow Management Company, contributed Interests (as defined and
described in "Item 1. Business" above) with an Exchange value of $670,980 for
its interest as a general partner in the Company.
None of the officers of the Company has an employment
agreement.
31
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The General Partner is a limited liability company of which
EMC, an Ohio corporation is the Managing Member. The members of the General
Partner are Thomas L. Korner and William A. Siskovic, both of whom are directors
and officers of EEI, and Sykes Associates, a limited partnership controlled by
Robert F. Sykes, Chairman of the Board of EEI and EMC. The General Partner of
the Company, owns a 1.15% 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 21.94% of the outstanding
Units.
The following table sets forth certain information with
respect to the number of Units beneficially owned as of March 20, 2003 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 18.38 66.6666 66.6666
Thomas L. Korner 135,910 2.36 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 21.94 100.0000 100.0000
- ----------
(1) Does not include the interest in the Company owned indirectly by such
individuals as a result of their ownership in (i) the General Partner
(based on its 1.15% interest in the Company) or (ii) EMC (based on EMC's 1%
managing member's interest in the General Partner).
(2) Includes the interest in the General Partner owned indirectly by such
individuals as a result of their share ownership in EMC resulting from
EMC's 1% managing member's interest in the General Partner.
(3) Includes 732,855 Units held by Sykes Associates, a New York limited
partnership comprised of Mr. Sykes and his wife as general partners and
four adult children as limited partners, 162,462 Units of the Company held
by the Robert F. Sykes Annuity Trust and 161,147 Units held by the
Catherine Sykes Annuity Trust.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In the past, certain officers, directors and more than 10%
Unitholders of the Company have invested, and may in the future invest, in oil
and gas programs sponsored by EEI on the same terms as unrelated investors. In
the past, certain officers, directors and/or more than 10% Unitholders of the
Company have frequently participated and will likely participate in the future
as working interest owners in wells in which the Company has an interest. The
Company anticipates that any such participation by individual members of the
Company's management would enable such individuals to participate in the
drilling and development of undeveloped
32
drillsites on an equal basis with the Company or the particular drilling program
acquiring such drillsites, which participation would be on a uniform basis with
respect to all drilling conducted during a specified time frame, as opposed to
selective participation. Frequently, such participation has been on more
favorable terms than the terms which were available to unrelated investors.
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. The
largest aggregate amount of indebtedness outstanding at any time during 2002 was
approximately $96,000 from William A. Siskovic. As of December 31, 2002, the
aggregate outstanding balance of such indebtedness was approximately $88,000
owing from William A. Siskovic. The Company has ceased making these loans in
compliance with the Sarbanes-Oxley Act of 2002.
Certain officers and directors of EMC own oil and gas
properties and, as such, contract with the Company to provide field operations
on such properties. These ownership interests are charged per well fees for such
services on the same basis as all other working interest owners.
ITEM 14. CONTROLS AND PROCEDURES
Within 90 days prior to the date of the filing of this report,
the Company's Chief Executive Officer and Chief Financial Officer conducted an
evaluation of the effectiveness of the design and operation of the Company's
disclosure controls and procedures pursuant to Exchange Act Rule 13a-14. Based
upon that evaluation, such officers concluded that the Company's disclosure
controls and procedures are effective to ensure that information required to be
disclosed by the Company in the reports it files or submits under the Exchange
Act is recorded, processed, summarized and reported, within the time periods
specified in the Commission's rules and forms.
There have been no significant changes in the Company's
internal controls or in other factors that could significantly affect these
controls subsequent to the date of the evaluation referred to above.
33
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K
(a) (1) Financial Statements
The following Consolidated Financial Statements of the
Registrant and its subsidiaries are included in Part II, Item 8:
Page(s)
-------
Auditors' Report on Audited Financial Statements F-3
Balance Sheets F-4 - F-5
Statements of Income F-6
Statements of Partners' Equity F-7
Statements of Cash Flows F-8
Notes to Financial Statements F-9 - F-24
(a) (2) Financial Statements Schedules
All schedules for which provision is made in the applicable
accounting regulation of the Securities and Exchange Commission are not required
under the related instructions or are inapplicable, and therefore have been
omitted.
(a) (3) Exhibits
See the Exhibit Index at page E-1 of this Annual Report on
Form 10-K.
(b) Reports on Form 8-K
The Company did not file any reports on Form 8-K during the
last quarter of its year ended December 31, 2002.
34
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, this Report has been signed below by the following persons on behalf of
the Registrant and in the capacities and on the dates indicated.
EVERFLOW EASTERN PARTNERS, L.P.
By: EVERFLOW MANAGEMENT LIMITED, LLC
General Partner
By: EVERFLOW MANAGEMENT CORPORATION
Managing Member
By: /s/Robert F. Sykes Director March 27, 2003
--------------------------------------------
Robert F. Sykes
By: /s/Thomas L. Korner President and Director March 27, 2003
--------------------------------------------
Thomas L. Korner
By: /s/William A. Siskovic Vice President, March 27, 2003
-------------------------------------------- Secretary-Treasurer
William A. Siskovic and Director (principal
financial and accounting
officer)
CERTIFICATIONS
I, Thomas L. Korner, Chief Executive Officer, certify that:
1. I have reviewed this annual report on Form 10-K of Everflow Eastern
Partners, L.P.;
2. Based on my knowledge, this annual report does not contain any
untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this
annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report is
being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing
date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's ability
to record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves
management or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in
this annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Dated: March 27, 2003
/s/Thomas L. Korner
------------------------------------------------------
Thomas L. Korner
Chief Executive Officer
I, William A. Siskovic, Chief Financial Officer, certify that:
1. I have reviewed this annual report on Form 10-K of Everflow Eastern
Partners, L.P.;
2. Based on my knowledge, this annual report does not contain any
untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this
annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report is
being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing
date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's ability
to record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves
management or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in
this annual report whether there were significant changes in internal controls
or in other factors that could
significantly affect internal controls subsequent to the date of our most
recent evaluation, including any corrective actions with regard to significant
deficiencies and material weaknesses.
Dated: March 27, 2003
/s/William A. Siskovic
---------------------------------------
William A. Siskovic
Chief Financial Officer
Exhibit Index
Exhibit No. Description
----------- -----------
3.1 Certificate of Limited Partnership of the Registrant (1)
dated September 13, 1990, as filed with the Delaware
Secretary of State on September 14, 1990
3.2 Form of Agreement of Limited Partnership of the (1)
Registrant
3.3 General Partnership Agreement of Everflow (1)
Management Company
3.4 Articles of Incorporation of Everflow Management (1)
Corporation
3.5 Code of Regulations of Everflow Management (1)
Corporation
3.6 Shareholders Agreement for Everflow Management (1)
Corporation
10.1 Credit Agreement dated January 19, 1995 between (2)
Everflow Eastern, Inc. and Everflow Eastern Partners, L.P.
and Bank One, Texas, National Association
10.2 Operating facility lease dated October 3, 1995 between (3)
Everflow Eastern Partners, L.P. and A-1 Storage of
Canfield, Ltd.
10.3 Amendment to Credit Agreement dated February 23, 1996 (5)
between Everflow Eastern, Inc. and Everflow Eastern
Partners, L.P. and Bank One, Texas, National Association
10.4 Second Amendment to Credit Agreement dated December 30, (5)
1996 between Everflow Eastern, Inc. and Everflow Partners,
L.P. and Bank One, Texas, National Association
10.5 Loan Modification Agreement dated June 16, 1997 between (6)
Bank One, N.A., Bank One, Texas, N.A. and Everflow
Eastern, Inc. and Everflow Eastern Partners, L.P.
10.6 Loan Modification Agreement dated May 29, 1998 between (7)
Bank One, N.A., Successor to Bank One, Texas, N.A., and
Everflow Eastern, Inc. and Everflow Eastern Partners L.P.
10.7 Articles of Organization of Everflow Management (8)
Limited, LLC
E-1
Exhibit No. Description
----------- -----------
10.8 Operating Agreement of Everflow Management Limited, (8)
LLC dated March 8, 1999
10.9 Loan Modification Agreement dated May 25, 1999 between (9)
Bank One, N.A., and Everflow Eastern, Inc. and Everflow
Eastern Partners, L.P.
10.10 Loan Modification Agreement dated September 19, 2000, (10)
between Bank One, N.A., and Everflow Eastern, Inc.
and Everflow Eastern Partners, L.P.
10.11 Loan Modification Agreement dated August 28, 2001 (11)
between Bank One, N.A., and Everflow Eastern, Inc.
and Everflow Eastern Partners, L.P.
21.1 Subsidiaries of the Registrant (4)
99.1 Certification Pursuant To 18 U.S.C. Section 1350, As Adopted
Pursuant To Section 906 Of The Sarbanes-Oxley Act of 2002
99.2 Certification Pursuant To 18 U.S.C. Section 1350, As Adopted
Pursuant To Section 906 Of The Sarbanes-Oxley Act of 2002
- ----------------
(1) Incorporated herein by reference to the appropriate exhibit to Registrant's
Registration Statement on Form S-1 (Reg. No. 33-36919).
(2) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Annual Report on Form 10-K for the year ended December 31,
1994 (File No. 0-19279).
(3) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Quarterly Report on Form 10-Q for the third quarter ended
September 30, 1995.
(4) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Annual Report on Form 10-K for the year ended December 31,
1995 (File No. 0-19279).
(5) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Annual Report on Form 10-K for the year ended December 31,
1996 (File No. 0-19279).
(6) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Quarterly Report on Form 10-Q for the second quarter ended
June 30, 1997.
(7) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Quarterly Report on Form 10-Q for the second quarter ended
June 30, 1998.
(8) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Quarterly Report on Form 10-Q for the first quarter ended
March 31, 1999.
(9) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Quarterly Report on Form 10-Q for the second quarter ended
June 30, 1999.
(10) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Quarterly Report on Form 10-Q for the third quarter ended
September 30, 2000.
(11) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Quarterly Report on Form 10-Q for the third quarter ended
September 30, 2001.
E-2