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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 (FEE REQUIRED)
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
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
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Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
--- ---
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K.
----
There are 4,772,080 Units of limited partnership interest held by
non-affiliates of the Registrant as of March 20, 1999. 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, 1998.
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PART I
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ITEM 1. BUSINESS
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Introduction
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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, 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, Everflow Management Limited, LLC and
EEI are located at 585 West Main Street, Canfield, Ohio 44406 (telephone number
(330)533-2692).
General
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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, 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 ("Exchange Act"). In addition, words such as "expects," "anticipates,"
"intends," "plans," "believes," "estimates" variations of such words, and
similar expressions are intended to identify forward-looking statements. Forward
looking statements are subject to the safe harbors created in the Exchange Act.
Factors that may cause such a difference include, but are
not limited to, the competition 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.
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Description of the Business
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GENERAL. Following the consummation of the Exchange Offer, 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 acting as the general partner or sponsor of the Programs. Prior
to the consummation of the Exchange Offer, EEI had acted as general contractor
in the drilling and completion of more than 550 wells and had served as operator
of more than 650 producing wells, the substantial majority of which are located
in the State of Ohio.
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 acquired in the Exchange
Offer 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 94% of the estimated future
gross cash flow from the oil and gas properties owned by the Company 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, following
consummation of the Exchange Offer, primarily involve the production and sale of
oil and gas from the properties acquired pursuant to the Exchange Offer and the
drilling and development of an additional 219 (net) wells. The Company serves as
the operator of approximately 78% of the gross wells and 88% of the net wells
which comprise the Company's properties.
The Company expects to hold its producing properties acquired
pursuant to the Exchange Offer 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 intends to conduct its business to
enable it to maintain and possibly expand its reserve base. In order to further
this plan, the Company
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primarily intends to acquire and subsequently drill and develop non-producing
oil and gas properties and possibly acquire producing oil and gas properties.
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. As a result of the number of recent transactions involving the
purchase and sale of Appalachian Basin oil and gas companies and properties,
management of the Company decided to explore and evaluate the possible sale of
the Company. The Company intends to continue to evaluate this and other
alternatives to maximize Unitholder's value. 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 ongoing basis.
The Company may also acquire leases from third parties. Historically, EEI
generated approximately 90% of the prospects which were drilled by the Programs.
EEI's current leasehold inventory consists of approximately 107 prospects in
various stages of maturity representing approximately 1,600 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.
FUNDING FOR ACTIVITIES. The Company finances its current
operations, including undeveloped leasehold acquisition activities, through cash
generated from operations and the proceeds of borrowings. Prior to the Exchange
Offer, EEI relied upon the formation of investor
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drilling programs to fund a portion of its operations; but to date, the Company
has elected not to pursue such activities. 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 borrowed up
to $4,100,000 in 1998 with a principal indebtedness of $2,200,000 outstanding as
of March 20, 1999. 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,
1998, which aggregate $51,479,000 (Standardized Measure of Discounted Future Net
Cash Flows) with $1,800,000 of bank debt outstanding under the revolving credit
facility (as of such date).
Marketing
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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
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market prices, although there have been substantial fluctuations in crude
oil prices in recent years.
The price of crude oil has decreased since the end of the
conflict in the Persian Gulf in March 1991, dropping from a high of $28.50 per
barrel in January 1991 to a low of $8.50 in December 1998. As of March 20, 1999
the posted field price in the Appalachian Basin area, the Company's principal
area of operation, was $12.00 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., formerly Quaker State
Refining Corporation.
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. During the past several years, there
has been a surplus of natural gas available for delivery to pipelines and other
purchasers. This oversupply, reduced demand due to economic conditions and
several mild winters have resulted in volatility in prices for natural gas
throughout the U.S., including the Appalachian Basin. 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
wells acquired by the Company in the Exchange Offer have been subject to these
limited, seasonal shut-ins and restrictions.
Prior to the execution of the East Ohio Contracts (discussed
below), EEI's historical practice had been to generally sell natural gas
pursuant to various purchase contracts with a number of natural gas brokerage
firms, pipeline companies or end-user customers. The provisions of these
contracts, both as to term and price, varied significantly. The term of these
contracts varied from short term, month-to-month arrangements up to the life of
a particular well. Most of these natural gas purchase contracts were for a term
of one year, expiring each October, and enabled the purchaser to renew the
contracts for additional one-year terms during the fourth quarter of the year.
Pricing provisions varied materially among the contracts.
The Company has various Intermediate Term Adjustable Price Gas
Purchase Agreements (the "East Ohio Contracts") with The East Ohio Gas Company
("East Ohio"). Pursuant to the East Ohio Contracts and subject to certain
restrictions and adjustments, including termination clauses, East Ohio is
obligated to purchase, and the Company is obligated to sell, all natural gas
production from a specified list of wells (the "Contract Wells"). A summary of
the Company's principal East Ohio Contracts at December 31, 1998 follows:
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Contract Period Number Required Shut-In Limitation
Date Covered of Wells Purchases Provisions Provisions
---- ------- -------- --------- ---------- ----------
9/3/91 11/91-10/01 426 275 days/year Maximum of May-Oct. - 50%
60 days (Nov.- of production
April) from prior 6
month period
3/10/94 4/94-3/00 52 275 days/year Maximum of May-Oct. - 50%
60 days (Nov.- of production
April) from prior 6
month period
8/10/94 11/94-10/00 27 Nov.-March April-Oct. Shut-in provisions
Net Price per MCF
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Contract Date Adjusted Prices
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11/96-4/97 5/97-10/97 11/97-4/98 5/98-10/98 11/98-4/99 5/99-10/99
---------- ---------- ---------- ---------- ---------- ----------
9/3/91 $3.31 $2.68 $3.90 $3.27 $3.71 $3.08
3/10/94 $2.95 $2.25 $3.54 $2.84 $3.35 $2.65
8/10/94 $3.55 N/A $4.14 N/A $3.95 N/A
As detailed above, the price paid for natural gas purchased
under the East Ohio Contracts varies with the production period. Pricing under
the East Ohio Contracts is adjusted annually, up or down, by an amount equal to
80% of the increase or decrease in East Ohio's average Gas Cost Recovery ("GCR")
rates. Additionally, the August 10, 1994 contract provides for a price cap equal
to the quarterly GCR, which amounted to $3.84, $4.20 and $4.05 in November 1998,
1997 and 1996, respectively. Price caps related to this contract are not
included in the table above. The net price per MCF includes $.20 per MCF for
transportation less a $.02 per MCF metering charge.
In addition to the East Ohio Contracts described above, the
Company has various short-term contracts (covering production from 72 gross
wells at December 31, 1998) which have a primary term of one year. Sixty-seven
of the wells are covered by fixed price contracts that provide for the sale of
the Company's gas at $2.65 to $2.82 per MCF. The remaining five wells are
covered by a fixed rate contract that provides for the sale of the Company's gas
based on monthly gas deliveries, with price provisions ranging from $2.66 for
gas production in the month of July to $3.32 in January (including
transportation allowances). There are no significant production restrictions
under the Company's short-term contracts as they relate to the Company's
existing wells. Future wells can be added to certain of the contracts subject to
gross production restrictions under the contracts. See "MANAGEMENT'S DISCUSSION
AND ANALYSIS OF
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS Inflation and Changes in Prices."
For the year ended December 31, 1998, with the exception of
The East Ohio Gas Company, which accounted for approximately 80% 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 East Ohio will be
the only material natural gas customer for 1999.
Seasonality
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The East Ohio Contract (i) provides that certain wells can be
shut-in for a period of time and (ii) limits the obligation of East Ohio to
purchase natural gas during the May to October production period. These
production restrictions, and the nature of the Company's business, result in
seasonal fluctuations in the Company's revenue, with the Company receiving more
income in the first and fourth quarters of its fiscal year.
Title to Properties
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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
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The oil and gas industry is highly competitive in all its
phases. The Company will encounter strong competition from major and independent
oil companies in acquiring economically desirable prospects as well as in
marketing production therefrom and obtaining external financing. Major oil and
gas companies, independent concerns, drilling and production purchase programs
and individual producers and operators are active bidders for desirable oil and
gas properties, as well as the equipment and labor required to operate those
properties. Many of the Company's competitors have financial resources,
personnel and facilities substantially greater than those of the Company.
The availability of a ready market for the oil and gas
production of the Company depends in part on the cost and availability of
alternative fuels, the level of consumer demand, the extent of other domestic
production of oil and gas, the extent of importation of foreign oil and gas, the
cost of and proximity to pipelines and other transportation facilities,
regulations by
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state and federal authorities and the cost of complying with applicable
environmental regulations. The volatility of prices for oil and gas and the
continued oversupply of domestic natural gas has, at times, resulted in a
curtailment in exploration for and development of oil and gas properties.
There is also extensive competition in the market for gas
produced by the Company. Increases in worldwide energy production capability and
decreases in energy consumption as a result of conservation efforts have brought
about substantial surpluses in energy supplies in recent years. This, in turn,
has resulted in substantial competition for markets historically served by
domestic natural gas resources both with alternate sources of energy, such as
residual fuel oil, and among domestic gas suppliers. As a result, at times there
has been volatility in oil and gas prices, widespread curtailment of gas
production and delays in producing and marketing gas after it is discovered.
Changes in government regulations relating to the production, transportation and
marketing of natural gas have also resulted in significant changes in the
historical marketing patterns of the industry. Generally, these changes have
resulted in the abandonment by many pipelines of long-term contracts for the
purchase of natural gas, the development by gas producers of their own marketing
programs to take advantage of new regulations requiring pipelines to transport
gas for regulated fees, and an increasing tendency to rely on short-term sales
contracts priced at spot market prices. See "Marketing" above.
In light of these developments, many producers have accepted
prices that are lower than those previously prevailing to sell their production.
As a consequence, 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
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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
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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 The East Ohio Gas Company as discussed
earlier.
As a result of the NGPA and the Decontrol Act, the Company's
gas production is no longer subject to price regulation. Gas which has been
removed from price regulation is subject only to that price contractually agreed
upon between the producer and purchaser. Under current market conditions,
deregulated gas prices under new contracts tend to be substantially lower than
most regulated price ceilings originally prescribed by the NGPA. FERC recently
has proposed and enacted several rules or orders concerning transportation and
marketing of natural gas. In 1992, the FERC finalized Order 636, a rule
pertaining to the restructuring of interstate pipeline services. This rule
requires interstate pipelines to unbundle transportation and sales services by
separately pricing the various components of their services, such as supply,
gathering, transportation and sales. These pipeline companies are required to
provide customers only the specific service desired without regard to the source
for the purchase of the gas. Although the Partnership is not an interstate
pipeline, it is likely that this regulation may indirectly impact the
Partnership by increasing competition in the marketing of natural gas, possibly
resulting in an erosion of the premium price historically available for
Appalachian natural gas. The impact of these rules and other regulatory
developments on the Company cannot be predicted.
Regulation of the production, transportation and sale of oil
and gas by federal and state agencies has a significant effect on the Company
and its operating results. Certain states, including Ohio and Pennsylvania, have
established rules and regulations requiring permits for drilling operations,
drilling bonds and reports concerning the spacing of wells.
Environmental Regulation
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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 to prepare and
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implement spill prevention control and countermeasure plans relating to the
possible discharge of oil into navigable waters; and the Environmental
Protection Agency will further require permits to authorize the discharge of
pollutants into navigable waters. State and local permits or approvals may also
be needed with respect to waste-water discharges and air pollutant emissions.
Violations of environment-related lease conditions or environmental permits can
result in substantial civil and criminal penalties as well as potential court
injunctions curtailing operations. Such enforcement liabilities can result from
prosecution by public or private entities.
Various state and governmental agencies are considering, and
some have adopted, other laws and regulations regarding environmental protection
which could adversely affect the proposed business activities of the Company.
The Company cannot predict what effect, if any, current and future regulations
may have on the operations of the Company.
In addition, from time to time, prices for either oil or
natural gas have been regulated by the federal government, and such price
regulation could be reimposed at any time in the future.
Operating Hazards and Uninsured Risks
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The Company's oil and gas operations are subject to all
operating hazards and risks normally incident to drilling for and producing oil
and gas, such as encountering unusual formations and pressures, blow-outs,
environmental pollution and personal injury. The Company maintains such
insurance coverage as it believes to be appropriate taking into account the size
of the Company and its operations. Losses can occur from an uninsurable risk or
in amounts in excess of existing insurance coverage. The occurrence of an event
which is not insured or not fully insured could have an adverse impact on the
Company's revenues and earnings.
In certain instances, the Company may continue to engage in
exploration and development operations through drilling programs formed with
non-industry investors. In addition, the Company also will conduct a significant
portion of its operations with other parties in connection with the drilling
operations conducted on properties in which it has an interest. In these
arrangements, all joint interest parties, including the Company, may be fully
liable for their proportionate share of all costs of such operations. Further,
if any joint interest party defaults on its obligations to pay its share of
costs, the other joint interest parties may be required to fund the deficiency
until, if ever, it can be collected from the defaulting party. As a result of
the foregoing or similar oilfield circumstances, the Company could become liable
for amounts significantly in excess of amounts originally anticipated to be
expended in connection with such operations. In addition, financial difficulty
for an operator of oil and gas properties could result in the Company's and
other joint interest owners' interests in properties and the wells and equipment
located thereon becoming subject to liens and claims of creditors,
notwithstanding the fact that non-defaulting joint interest owners and the
Company may have previously paid to the operator the amounts necessary to pay
their share of such costs and expenses.
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Conflicts of Interest
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The Partnership Agreement grants Everflow Management Limited,
LLC, the General Partner, broad discretionary authority to make decisions on
matters such as the Company's acquisition of or participation in a drilling
prospect or a producing property. To limit the General Partner's management
discretion might prevent it from managing the Company properly. However, because
the business activities of the affiliates of the General Partner on the one hand
and the Company on the other hand are the same, potential conflicts of interest
are likely to exist, and it is not possible to completely mitigate such
conflicts.
The Partnership Agreement contains certain restrictions
designed to mitigate, to the extent practicable, these conflicts of interest.
The agreement restricts, among other things, (i) the cost at which the General
Partner or its affiliates may acquire properties from or sell properties to the
Company; (ii) loans between the General Partner, its affiliates and the Company,
and interest and other charges incurred in connection therewith; and (iii) the
use and handling of the Company's funds by the General Partner.
Employees
- ---------
As of March 20, 1999, the Company (either directly or
indirectly through EEI) had 27 full-time employees. These employees primarily
are engaged in the following areas of business operations: six in land and lease
acquisition, seven in field operations, seven in accounting, and seven in
administration.
-11-
13
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 reflects 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, 1998.
Oil (BBLS) Gas (MCF)
---------- ----------
Proved Developed 935,000 52,903,000
Proved Undeveloped - -
------ ---------
Total 935,000 52,903,000
======= ==========
----------------------
(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 (page
F-23).
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS.(1)
The following table summarizes, as of December 31, 1998, 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 $ 153,538
Future production and development costs 57,255
Future income tax expense 2,253
----------
Future net cash flows 94,030
Effect of discounting future net cash flows
at 10% per annum 42,551
----------
Standardized measure of discounted future
net cash flows $ 51,479
==========
-------------------
(1) See the Notes to the Financial Statements for
additional information (pages F-20 to F-25).
-12-
14
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)
---------- --------- ------- ------- ---------------------
1998 94,000 4,575,000 $ 12.20 $ 3.26 $ .50
1997 126,000 4,322,000 17.10 3.07 .48
1996 112,000 4,264,000 19.88 2.78 .44
- ---------------------
(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, 1998.
Gross Wells Net Wells
---------------------------------------------------------------------
(1) (1) (1) (1)
Oil Gas Total Oil Gas Total
---------------------------------------------------------------------
62 950 1012 34 616 650
---------------
(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 49,600 gross developed acres and
32,600 net developed acres as of December 31, 1998. Developed acreage is that
acreage assignable to productive wells. The Company had approximately 1,600
gross and net undeveloped acres as of December 31, 1998.
-13-
15
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
----- --- ----- ---
1998 30 19.09 1 .91
1997 35 19.80 - -
1996 40 23.39 1 .23
------------------
(1) All wells are located in the United States. All wells
are development wells; no exploratory wells were
drilled.
PRESENT ACTIVITIES. The Company has drilled 7 gross and 3.18
net development wells since December 31, 1998. As of March 20, 1999, the Company
had no wells in the process of being drilled.
DELIVERY COMMITMENTS. The Company entered into various East
Ohio contracts with East Ohio which, subject to certain restrictions and
adjustments, obligates East Ohio 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.
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, 1998, there were no matters submitted to a vote of security holders through
the solicitation of proxies or otherwise.
-14-
16
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 Company's Units of Limited Partnership. 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,
1999, there were 6,172,537 Units of limited partnership interest held by 1,630
holders of record.
Distribution History.
- ---------------------
The Company commenced operations with the consummation of the
Exchange Offer in February 1991. Management's stated intention was to make
quarterly cash distributions equal to $0.125 per Unit (or $0.50 per Unit on an
annualized basis) for the first eight quarters following the closing date of the
Exchange Offer. The Company has paid a quarterly distribution every quarter
since July 1991. Based upon the current number of Units outstanding, each
quarterly distribution of $0.125 per Unit is expected to be approximately
$780,000. The Company currently intends to make a quarterly distribution of
$0.25 per Unit in April 1999 and quarterly distributions of $0.125 per Unit in
July and October 1999.
Repurchase Right.
- -----------------
The Partnership Agreement provides, that beginning in 1992 and
annually thereafter, the Company will repurchase for cash up to 10% of the then
outstanding Units, to the extent Unitholders offer Units to the Company for
repurchase. The Repurchase Right 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 53,103, 172,290 and
35,114 of its Units of limited partnership interest at a price of $4.50, $5.21,
and $4.99 per Unit pursuant to the terms of the Company's Offers to Purchase
dated April 30, 1996, 1997 and 1998, respectively. See Note 4 in the Company's
financial statement for additional information on the Repurchase Right.
-15-
17
ITEM 6. SELECTED FINANCIAL DATA
- ---------------------------------
Year Ended December 31,
-------------------------------------------------------------------------
1998 1997 1996 1995 1994
-------------------------------------------------------------------------
Revenue .......................... $16,558,366 $15,932,197 $14,557,405 $14,478,954 $15,363,555
Net Income ....................... 6,897,089 5,696,407 4,227,854 5,247,086 5,915,578
Net Income Per Unit .............. 1.10 .90 .65 .80 .90
Total Assets ..................... 56,612,953 54,760,106 53,188,337 52,756,474 50,454,294
Debt(1) .......................... 2,255,898 4,589,143 4,405,834 4,718,207 3,800,000
Cash Distributions Per Unit ...... .50 .50 .50 .50 .50
- ------------------
(1) Debt includes the Company's long-term debt and borrowings under the
Company's revolving credit facility.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
- -----------------------------------------------------------------------------
AND RESULTS OF OPERATIONS
- -------------------------
GENERAL
The Company was organized in September 1990 as a limited
partnership under the laws of the State of Delaware. Everflow Management
Limited, LLC, an Ohio limited liability company, is the general partner of the
Company. The Company was formed to engage in the business of oil and gas
exploration and development through a proposed consolidation of the business and
oil and gas properties of EEI, and the oil and gas properties owned by certain
limited partnerships and working interest programs managed or operated by the
Programs.
Effective February 15, 1991, pursuant to the Exchange Offer to
acquire the EEI shares and the Interests in exchange for Units of the Company's
limited partnership interest, the Company acquired the Interests and the EEI
Shares and EEI become a wholly-owned subsidiary of the Company.
Everflow Management Limited, LLC, the General Partner of the
Company, is a limited liability company. The members of Everflow Management
Limited, LLC are EMC, three individuals who are currently directors and/or
officers of EEI, David T. Matak, 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 $2.4 million as of December 31,
1998 represented a $4.0 million increase from December 31, 1997 due primarily to
a $2.2 million increase in
-16-
18
investments in marketable corporate dept securities and a $2.3 million reduction
in borrowings under the Company's revolving credit facility. In May 1998, the
Company modified its revolving credit facility. The facility provides for a
revolving line of credit in the amount of $7,000,000, all of which is available.
The revolving line of credit provides for interest payable quarterly at LIBOR
plus 175 basis points with the principal due at maturity, May 31, 1999. The
Company anticipates renewing the facility on a year to year basis to minimize
debt origination, carrying and interest costs associated with long-term bank
commitments. The Company paid down $5.2 million of debt under the revolving
credit facilities during 1998, most of which was paid during the winter and
spring months when cash flows from production were higher. The Company borrowed
$2.9 million under its revolving credit facilities during 1998. These borrowings
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 35,114 Units at a price of
$4.99 per Unit, or $175,219, on June 30, 1998. The Company also used its credit
facility to make quarterly Cash Distributions during the summer and fall months.
The following table summarizes the Company's financial
position at December 31, 1998 and December 31, 1997:
(Amounts in Thousands) December 31, 1998 December 31, 1997
------------------- --------------------
Amount % Amount %
------------------ ---------------------
Working capital $ 2,424 5% $(1,576) (3)%
Property and equipment (net) 50,246 95 50,240 102
Other 54 - 503 1
------- --- ------- ---
Total $52,724 100% $49,167 100%
======= === ======= ===
Long-term debt $ 425 1% $ 461 1%
Deferred income taxes 128 - 128 -
Partners' equity 52,171 99 48,578 99
------- --- ------- ---
Total $52,724 100% $49,167 100%
======= === ======= ===
Cash Flows from Operating, Investing and Financing Activities
- -------------------------------------------------------------
The Company generated almost all of its cash sources from operating
activities. During the years ended 1998 and 1997, cash provided by operations
was used to fund the development of additional oil and gas properties and
distributions to partners.
-17-
19
The following table summarizes the Company's Statements of
Cash Flows for the years ended December 31, 1998 and 1997:
(Amounts in Thousands) 1998 1997
---------------------------------------
Dollars % Dollars %
Operating Activities:
Net income before adjustments $ 6,897 57% $ 5,696 48%
Adjustments 4,770 39 5,692 48
------- ------- ------- -------
Cash flow from operations
before working capital
changes 11,667 96 11,388 96
Changes in working capital ( 2,096) ( 17) 417 4
------- ------- ------- -------
Net cash provided by
operating activities 9,571 79 11,805 100
Investing Activities:
Proceeds received on receivables
from officers and employees 541 4 637 6
Advances disbursed to officers
and employees ( 545) ( 5) ( 719) ( 6)
Purchase of property and
equipment ( 5,905) ( 49) ( 7,809) ( 66)
Purchase of other assets ( 271) ( 2) ( 102) ( 1)
Proceeds on sale of other assets
and equipment 1,862 16 23 -
------- ------- ------- -------
Net cash (used) by investing
activities ( 4,319) ( 36) ( 7,970) ( 67)
Financing Activities:
Distributions ( 3,129) ( 26) ( 3,180) ( 27)
Repurchase of Units ( 175) ( 2) ( 898) ( 8)
Long-term debt issuance 2,900 24 4,500 38
Long-term debt repayments ( 5,233) ( 43) ( 4,317) ( 36)
------- ------- ------- -------
Net cash (used) by financing
activities ( 5,637) ( 47) ( 3,895) ( 33)
------- ------- ------- -------
Increase (decrease) in cash
and equivalents ( 385) ( 3) ( 60) ( 1)
Note: All items in the previous table are calculated as a percentage of total
cash sources. Total cash sources include the following items, if
positive: cash flow from operations before working capital changes,
changes in working capital, net cash provided by investing activities
and net cash provided by financing activities, plus any decrease in
cash and cash equivalents.
-18-
20
As the above table indicates, the Company's cash flow from
operations before working capital changes during the twelve months of 1998 and
1997 represented 96% of total cash sources. Changes in working capital other
than cash and equivalents decreased cash by $2,096 thousand and increased cash
by $417 thousand during 1998 and 1997, respectively. The increase in accounts
receivable at December 31, 1998 compared to December 31, 1997 is the result of
higher production volumes and timing of production revenues resulting in higher
production revenues receivable as of December 31, 1998. Total production
revenues receivable as of December 31, 1998 amounted to $2.3 million compared to
$2.0 million at December 31, 1997. Additionally, the Company had $2.2 million of
cash invested in short-term marketable corporate debt securities at December 31,
1998 and no such investment at December 31, 1997.
The Company's cash flows used by investing activities
decreased $3.7 million, or 46%, during 1998 as compared with 1997. The Company's
cash flows used by investing activities increased $2.3 million, or 39%, during
1997 as compared with 1996. The primary reason for the decrease in cash flows
used by investing activities in 1998 was the decrease in the purchase of
property and equipment and proceeds received on the sale of other assets. The
purchase of property and equipment decreased $1.9 million, or 24%, during 1998
as compared with 1997, and proceeds received from the sale of property and
equipment and other assets increased from $23 thousand to $1,862 thousand from
1997 to 1998. The primary reason for the increase in 1997 was due to the
Company's increased activity in the purchase of property and equipment. The
purchase of property and equipment increased $2.3 million, or 42%, during 1997
as compared with 1996. In addition to the drilling and development of 20 net
wells during 1997, the Company made prepayments on undrilled wells of $1.3
million and purchased producing properties of $1.1 million.
The Company's cash flows used by financing activities
increased $1.7 million, or 45%, during 1998 as compared with 1997. The primary
reason for this increase was that proceeds from the issuance of long-term debt
decreased $1.6 million and payments on long-term debt increased $916 thousand to
$5.2 million during 1998. Additionally, payments on the Repurchase of Units
decreased $722 thousand, or 80%, during 1998 as compared with 1997. The
Company's cash flows used by financing activities increased $107 thousand, or
3%, during 1997 as compared with 1996. The primary reason for this increase was
that the payments on the Repurchase of Units increased $659 thousand during 1997
and payments on long-term debt decreased $495 thousand to $4.3 million during
1997.
The Company's ending cash and equivalents balance of $295
thousand and investments balance of $2.2 million at December 31, 1998, as well
as ongoing 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 1999. The Company has paid a quarterly distribution every quarter since
July 1991. Total cash distributions are estimated to be $780 thousand per
quarter ($.125 per Unit). The Company intends to distribute $1,560 thousand
($.25 per Unit) on April 1, 1999 using the proceeds from its investments in
marketable corporate debt securities resulting from the sale of other assets.
-19-
21
Capital expenditures for the development of oil and gas
properties in the Company and the acquisition of undeveloped leasehold acreage
continue to be ongoing priorities of the Company. The Company drilled or
participated in the drilling of an additional 30 drillsites in 1998. The
Company's share of these drillsites amounts to 19.1 net developed wells. The
Company also made prepayments of intangible drilling costs on 11 gross and 7.5
net wells to be drilled by March 31, 1999. Proved reserves associated with the
prepaid wells have not been determined. The Company's share of proved gas
reserves has increased by 12.2 million MCF's, or 30%, between December 31, 1997
and 1998, while proved oil reserves have increased by 113 thousand barrels, or
14%, between December 31, 1997 and 1998. The Company continues to develop
primarily natural gas fields, as represented by the discovery and addition of
4.8 million MCF's of natural gas versus 67 thousand barrels of crude oil during
1998. The Standardized Measure of Discounted Future Net Cash Flows of the
Company's reserves increased by $5.4 million between December 31, 1997 and 1998.
The primary reasons for this increase was an upward revision of previous gas and
oil reserve estimates. Management of the Company believes the Company should be
able to drill or participate in the drilling of 15 to 25 net wells each year for
the next few years. Management believes it is necessary to meet this annual
objective in order to maintain its reserve base. At the point where the Company
can no longer generate adequate and sufficient drillsite locations, debt
reductions and/or additional distributions to partners may be made by the
Company at the discretion of management. 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. Additionally,
because of the number of recent transactions involving the purchase and sale of
Appalachian Basin oil and gas companies and properties, management of the
Company and the Company's investment banker continue to evaluate the possible
sale of the Company and other alternatives to maximize Unitholder value.
However, management cannot predict whether any sales transaction would be a
viable alternative for the Company in the immediate future.
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
-20-
22
actual number of Units to be acquired during any such period. The Company
repurchased 35,114, 172,290 and 53,103 Units during 1998, 1997 and 1996 pursuant
to the Repurchase Right at a price of $4.99, $5.21 and $4.50 per Unit,
respectively. The Company borrowed against its credit facility to meet such
obligations and would expect to do so again in 1999. The Repurchase Right to be
conducted in 1999 will result in Unitholders being offered a price of $5.79 per
Unit. The Company estimates it would need to borrow $3.6 million in the event
the 1999 offering pursuant to the Repurchase Right is fully subscribed.
In the fall of 1998, there was a $.19 per MCF decrease in the
price received for natural gas pursuant to the pricing adjustments contained in
the Company's Intermediate Term Adjustable Price Gas Purchase Agreements with
The East Ohio Gas Company. These pricing adjustments should decrease the
Company's cash flows from operations during 1999, assuming similar production
levels. Recent oil prices have declined and will reduce the Company's cash flows
from oil production should pricing remain at such levels.
RESULTS OF OPERATIONS
The following table and discussion is a review of the results
of operations of the Company for the twelve months ended December 31, 1998, 1997
and 1996. All items in the table are calculated as a percentage of total
revenues. This table should be read in conjunction with the discussions of each
item below:
Year Ended December 31,
--------------------------
1998 1997 1996
--------------------------
Revenues:
Oil and gas sales 97% 97% 97%
Well management and operating 3 3 3
-- --- ---
Total Revenues 100 100 100
Expenses:
Production costs 15 15 15
Well management and operating - 1 1
Depreciation, depletion and amortization 30 33 35
Abandonment and write down
of oil and gas properties 6 3 5
General and administrative 13 12 13
Other expense (income) ( 6) 1 2
Income taxes - ( 1) -
--- ---
Total Expenses 58 64 71
--- --- ---
Net income 42% 36% 29%
=== === ===
Revenues for the year ended December 31, 1998 increased $626
thousand, or 4%, compared to the same period in 1997. Revenues for the year
ended December 31, 1997 increased
-21-
23
$1,375 thousand, or 9%, compared to the same period in 1996. These increases
were due primarily to changes in oil and gas sales and production volumes
between the periods involved.
Oil and gas sales increased $639 thousand, or 4%, from 1997 to
1998. The primary reason for this increase was the result of higher gas prices
and increased production volumes for natural gas. The increase in gas prices
received during November 1997 of $.59 per MCF was responsible for increasing
natural gas sales during much of 1998. The Company's gas production increased by
253 thousand MCF, and the average price received per MCF increased from $3.07 to
$3.26 from 1997 to 1998. Although the Company's revenues from gas sales were
significantly higher in 1998, revenues from oil sales decreased by 53% to $1.1
million as compared to 1997 oil sales of $2.1 million. The primary reasons for
the decrease in oil sales were a decrease in average sales price of oil from
$17.10 to $12.20 per barrel from 1997 to 1998, and a decrease in oil production
of 32 thousand barrels from 1997 to 1998. Gas sales accounted for 93%, 86% and
84% of total oil and gas sales in 1998, 1997 and 1996, respectively. Oil and gas
sales increased $1.3 million, or 10%, from 1996 to 1997. The primary reason for
this increase in oil and gas sales between 1996 and 1997 was an increase in oil
and gas production and natural gas prices. In addition, the Company's gas
production increased by 58 thousand MCF and oil production increased by 14
thousand barrels from 1996 to 1997. In the fall of 1998, there was a $.19 per
MCF decrease in the price received for natural gas pursuant to the pricing
adjustments contained in the Company's Intermediate Term Adjustable Price Gas
Purchase Agreements with The East Ohio Gas Company. These pricing adjustments
should decrease the Company's cash flow from operation during 1999, assuming
similar production levels.
Production costs increased $124 thousand, or 5%, and $235
thousand, or 11%, during 1998 and 1997, respectively. The primary reasons for
these increases include increased operating costs relating to older wells and
the Company's increasing costs due to placing newly drilled wells into
production. Depreciation, depletion and amortization decreased $383 thousand, or
7%, between 1997 and 1998. This decrease was the result of the upward revisions
of reserve estimates on certain properties between 1997 and 1998. Depreciation,
depletion and amortization increased $131 thousand, or 3%, between 1996 and
1997. This increase was the result of an increase in wells placed into
production and the downward revision of reserve estimates on certain properties.
Well management and operating revenues decreased $13 thousand,
or 2%, from 1997 to 1998. Well management and operating costs decreased $30
thousand, or 23%, from 1997 to 1998. The reason for the decreases in well
management and operating revenues and costs was due to the purchase of Company
operated oil and gas interests. These purchases decreased the third party share
of oil and gas properties managed and operated by the Company. Well management
and operating revenues increased $35 thousand, or 7%, from 1996 to 1997. Well
management and operating costs decreased $75 thousand, or 36%, from 1996 to
1997.
Abandonments and write downs of oil and gas properties
increased $441 thousand between 1997 and 1998 and decreased $148 thousand
between 1996 and 1997. These fluctuations were attributable to the write down of
oil and gas properties, abandonments of oil
-22-
24
and gas properties and leasehold impairments. During 1998, the Company wrote
down oil and gas properties by approximately $426 thousand to provide for
impairment on certain of its oil and gas properties. The Company also recognized
dry hole costs of approximately $538 thousand in 1998. During 1997 and 1996, the
Company wrote down oil and gas properties by approximately $199 thousand and
$262 thousand, respectively, to provide for impairment on certain of its oil and
gas properties. The Company recognized leasehold impairment provisions of
approximately $325 thousand in 1997. Additionally, in 1996, the Company wrote
off approximately $210 thousand of costs associated with an unsuccessful and
abandoned water flood project.
General and administrative expenses increased $222 thousand,
or 12%, between 1997 and 1998, and increased $21 thousand, or 1%, between 1996
and 1997. The increase in general and administrative expenses between 1997 and
1998 is the result of increases in professional fees associated with the
Company's efforts in evaluating the feasibility of the sale of the Company and
costs associated with discussions with prospective purchasers.
Net other income (expenses) amounted to $1,044 thousand,
($124) thousand and ($241) thousand in 1998, 1997 and 1996, respectively. The
change between 1997 and 1998 was primarily attributable to a nonrecurring gain
on sale of other assets associated with the Company's operations. The change
between 1996 and 1997 was partly attributed to a decrease in interest expense
resulting from lower interest rates and a reduction in the level of outstanding
debt relating to the Company's revolving credit facility. In addition, the
Company recognized a decrease in its loss on the sale of oil and gas properties
during 1997 compared with 1996.
Income tax expense attributable to EEI increased $220 thousand
between 1997 and 1998 and decreased $140 thousand between 1996 and 1997. These
changes are due to the effect of the earnings of EEI. The Company is not a tax
paying entity, and the net taxable income or loss, other than the taxable income
or loss allocable to EEI, is allocated directly to its respective partners.
Net income increased $1.2 million, or 21%, between 1997 and
1998. The increase was primarily the result of an increase in total oil and gas
sales, and the nonrecurring gain on sale of other assets which was offset
somewhat by increases in abandonment and write downs of oil and gas properties
and general and administrative expenses. Net income increased $1.5 million, or
35%, between 1996 and 1997. The increase resulted from increased oil and gas
sales. Net income represented 42%, 36% and 29% of total revenues during the
years ended December 31, 1998, 1997 and 1996, respectively.
NEW ACCOUNTING STANDARDS
In June 1997, SFAS 130, "Reporting Comprehensive Income," was
issued. SFAS 130 established new standards for reporting comprehensive income
and its components and is effective for fiscal years beginning after December
15, 1997. In June 1997, the Financial Accounting Standards Board issued SFAS
131, "Disclosure About Segments of an Enterprise and Related Information." SFAS
131 changes the standards for reporting financial results by
-23-
25
operating segments, related products and services, geographical areas and major
customers and is adoptable by December 31, 1998. In February 1998, SFAS 132,
"Employers' Disclosures About Pensions and Other Postretirement Benefits," was
issued. SFAS 132 standardizes the disclosure requirements for pension and other
postretirement benefit plans but does not change the measurement or recognition
of those plans. SFAS 132 is effective for fiscal years beginning after December
15, 1997. In June 1998, SFAS 133, "Accounting for Derivative Instruments and
Hedging Activities," was issued. SFAS 133 establishes accounting and reporting
standards for derivative instruments and hedging activities. SFAS 133 is
effective for fiscal years beginning after June 15, 1999. The effect of adoption
or anticipated adoption of the above standards had no, or is expected to have
no, material effect on the Company's financial statements.
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 during the Persian Gulf
crisis ranged from a low of $18.00 per barrel on July 30, 1990 to a high of
$37.50 per barrel on October 13, 1990. The price of oil in the Appalachian Basin
more recently has ranged from a low of $8.50 per barrel in December 1998 to a
high of $23.50 in January 1997. As of March 20, 1999, the posted field price in
the Appalachian Basin area, the Company's principal area of operation, was
$12.00 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 6% of the Company's total future cash inflows related
to oil and gas reserves as of December 31, 1998 are comprised of oil reserves.
The various gas purchase agreements with The East Ohio Gas
Company negotiated since 1991 have had and will continue to have a significant
effect on the Company's natural gas sales. Under the purchase agreements,
adjustments to the price of gas paid to the Company by The East Ohio Gas Company
are based on 80% of the increase or decrease in East Ohio's Gas Cost Recovery
rates ("GCR") as specified in the contracts. The average price of gas during
1995 amounted to $2.86 per MCF, an $.18 decrease compared to 1994. The November
1995 annual price adjustment was a decrease of $.50 per MCF. The average price
of gas during 1996 amounted to $2.78 per MCF, an $.08 decrease compared to 1995.
The November 1996 annual price adjustment was an increase of $.47 per MCF. The
average price of gas during 1997 amounted to $3.07 per MCF, a $.29 increase
compared to 1996. The November 1997 annual price adjustment was an increase of
$.59 per MCF. The average price of gas during 1998 amounted to $3.26 per MCF, a
$.19 increase compared to 1997. The November 1998 annual price adjustment was a
decrease of $.19 per MCF.
The Company's Standardized Measure of Discounted Future Net
Cash Flows increased by $5.4 million from December 31, 1997 to December 31, 1998
and decreased by $4.4 million from December 31, 1996 to December 31, 1997. A
reconciliation of the Changes in the Standardized Measures of Discounted Future
Net Cash Flows is included on page F-24 of the Company's consolidated financial
statements.
-24-
26
YEAR 2000 READINESS DISCLOSURE
The Year 2000 problem, software, hardware or an embedded chip
that does not correctly process date information for years after 1999, results
from the practice of storing date information with only the last two digits of
the year. The Company began to address Year 2000 issues in 1997. The scope of
the Year 2000 readiness effort includes the Company's internal information
technology ("IT") systems, such as hardware and software; non-IT systems with
date-sensitive characteristics; the status of key third parties, including
suppliers, service providers and customers. The Company's major IT applications
are currently Year 2000 ready. Remediation and testing of the balance of the IT
systems are expected to be completed by fall 1999. The Company is in the early
stages of analyzing the readiness of non-IT systems and anticipates that
remediation and testing of any noncompliant systems will be completed by October
1999. The Company also has taken initial steps to determine the compliance of
key third parties and expects that it will have received and reviewed responses
from the majority of such parties by October 1999. Although the Company expects
to meet the target dates for completion of remediation and testing and for
determining the status of key third parties, the Company will attempt to develop
contingency plans should the programs not be completed when anticipated or
should the third parties not be ready on a timely basis.
Costs of addressing the Year 2000 issue to date approximate
$50,000. It is anticipated that an additional $100,000 will be incurred.
Substantially all of these outlays are expected to result from remediation of
existing systems as opposed to replacing existing systems. Costs are being
funded from operating cash flows. The actual costs of the Company's Year 2000
efforts may vary from current estimates, which are based on information
available at this time.
Although the Company believes that it is taking appropriate
precautions against disruption of its systems due to the Year 2000 issue, there
can be no assurance that the Company will identify all Year 2000 problems in
advance of their occurrence(s) or that the Company will be able to successfully
remedy all problems that are discovered. Furthermore, there can be no assurance
that the Company's third party relationships will not be adversely affected by
Year 2000 issues. The Company is in the process of developing contingency plans
to address the potential effects of problems arising from Year 2000
noncompliance. While the Company does not anticipate that costs of Year 2000
disruptions will have a material adverse effect, Year 2000 disruptions, arising
either from within the Company or through third party relationships, could have
a material adverse effect on the Company's business, operating results and
financial condition.
-25-
27
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
- --------------------------------------------------------------------------
Not applicable.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
- ----------------------------------------------------------
See attached pages F-1 to F-25.
ITEM 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
- --------------------------------------------------------------------
Not applicable.
-26-
28
EVERFLOW EASTERN PARTNERS, L. P.
1998 CONSOLIDATED FINANCIAL REPORT
F-1
29
EVERFLOW EASTERN PARTNERS, L. P.
CONTENTS
- --------------------------------------------------------------------------------
Page
----
AUDITORS' REPORT ON THE FINANCIAL STATEMENTS F-3
FINANCIAL STATEMENTS
Consolidated balance sheets F-4 - F-5
Consolidated statements of income F-6
Consolidated statements of partners' equity F-7
Consolidated statements of cash flows F-8
Notes to consolidated financial statements F-9 - F-25
F-2
30
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, 1998 and
1997, and the related consolidated statements of income, partners' equity, and
cash flows for each of the three years in the period ended December 31, 1998.
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 generally accepted auditing
standards. 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, 1998 and
1997, and the consolidated results of their operations and their cash flows for
each of the three years in the period ended December 31, 1998, in conformity
with generally accepted accounting principles.
HAUSSER + TAYLOR LLP
Cleveland, Ohio
March 16, 1999
F-3
31
EVERFLOW EASTERN PARTNERS, L. P.
CONSOLIDATED BALANCE SHEETS
December 31, 1998 and 1997
--------------------------
1998 1997
---- ----
ASSETS
------
CURRENT ASSETS
Cash and equivalents $ 294,518 $ 679,531
Accounts receivable:
Production 2,323,510 1,984,366
Officers and employees 1,015,458 1,011,203
Joint venture partners 366,121 278,641
Short-term investments 2,221,056 -
Other 92,355 63,418
----------- -----------
Total current assets 6,313,018 4,017,159
PROPERTY AND EQUIPMENT
Proved properties (successful efforts accounting method) 110,178,841 105,080,039
Pipeline and support equipment 506,153 466,717
Corporate and other 1,212,857 1,115,969
----------- -----------
111,897,851 106,662,725
Less accumulated depreciation, depletion, amortization
and write down 61,651,637 56,422,935
----------- -----------
50,246,214 50,239,790
OTHER ASSETS 53,721 503,157
----------- -----------
$56,612,953 $54,760,106
=========== ===========
The accompanying notes are an integral part of these financial statements.
F-4
32
EVERFLOW EASTERN PARTNERS, L. P.
CONSOLIDATED BALANCE SHEETS
December 31, 1998 and 1997
--------------------------
1998 1997
---- ----
LIABILITIES AND PARTNERS' EQUITY
-----------------------------------
CURRENT LIABILITIES
Current portion of long-term debt $ 30,805 $ 27,936
Revolving credit facility 1,800,000 4,100,000
Accounts payable 1,666,792 1,207,268
Accrued expenses 391,187 257,893
----------- -----------
Total current liabilities 3,888,784 5,593,097
LONG-TERM DEBT, NET OF CURRENT PORTION
Term debt 425,093 461,207
DEFERRED INCOME TAXES 128,000 128,000
COMMITMENTS AND CONTINGENCIES
LIMITED PARTNERS' EQUITY, SUBJECT TO REPURCHASE
RIGHT
Authorized - 8,000,000 units
Issued and outstanding - 6,172,537 and 6,207,651 units,
respectively 51,610,054 48,058,020
GENERAL PARTNER'S EQUITY 561,022 519,782
----------- -----------
Total partners' equity 52,171,076 48,577,802
----------- -----------
$56,612,953 $54,760,106
=========== ===========
The accompanying notes are an integral part of these financial statements.
F-5
33
EVERFLOW EASTERN PARTNERS, L. P.
CONSOLIDATED STATEMENTS OF INCOME
Years Ended December 31, 1998, 1997 and 1996
--------------------------------------------
1998 1997 1996
---- ---- ----
REVENUES
Oil and gas sales $16,058,164 $15,418,755 $14,078,491
Well management and operating 497,483 510,039 474,851
Other 2,719 3,403 4,063
---------- ---------- ----------
16,558,366 15,932,197 14,557,405
DIRECT COST OF REVENUES
Production costs 2,550,686 2,427,124 2,192,349
Well management and operating 102,176 132,531 207,951
Depreciation, depletion and amortization 4,904,221 5,287,066 5,155,681
Abandonment and write down of oil and gas
properties 964,226 523,513 671,992
Total direct cost of revenues ---------- ---------- ----------
8,521,309 8,370,234 8,227,973
GENERAL AND ADMINISTRATIVE EXPENSE 2,113,492 1,891,515 1,870,646
Total cost of revenues ---------- ---------- ----------
10,634,801 10,261,749 10,098,619
---------- ---------- ---------
INCOME FROM OPERATIONS 5,923,565 5,670,448 4,458,786
OTHER INCOME (EXPENSE)
Interest income 90,564 86,226 78,668
Interest expense (170,611) (219,896) (262,659)
(Loss) gain on sale of property and equipment (5,613) 9,629 (56,941)
Gain on sale of other assets 1,129,184 - -
---------- ---------- ---------
1,043,524 (124,041) (240,932)
---------- ---------- ---------
INCOME BEFORE INCOME TAXES 6,967,089 5,546,407 4,217,854
PROVISION (CREDIT) FOR INCOME TAXES
Current 70,000 - -
Deferred - (150,000) (10,000)
---------- ---------- ----------
NET INCOME $ 6,897,089 $ 5,696,407 $ 4,227,854
========== ========== ==========
Allocation of Partnership Net Income
Limited Partners $ 6,822,921 $ 5,636,318 $ 4,184,053
General Partner 74,168 60,089 43,801
---------- ---------- ----------
$ 6,897,089 $ 5,696,407 $ 4,227,854
========== ========== ==========
Net income per unit $ 1.10 $ .90 $ .65
========== ========== ==========
The accompanying notes are an integral part of these financial statements.
F-6
34
EVERFLOW EASTERN PARTNERS, L. P.
CONSOLIDATED STATEMENTS OF PARTNERS' EQUITY
Years Ended December 31, 1998, 1997 and 1996
--------------------------------------------
1998 1997 1996
---- ---- ----
PARTNERS' EQUITY - JANUARY 1 $48,577,802 $46,959,473 $46,207,378
Net income 6,897,089 5,696,407 4,227,854
Cash distributions ($.50 per unit each year) (3,128,596) (3,180,447) (3,236,795)
Purchase and retirement of Units (175,219) (897,631) (238,964)
---------- ---------- ----------
PARTNERS' EQUITY - DECEMBER 31 $52,171,076 $48,577,802 $46,959,473
========== ========== ==========
The accompanying notes are an integral part of these financial statements.
F-7
35
EVERFLOW EASTERN PARTNERS, L. P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31, 1998, 1997 and 1996
--------------------------------------------
1998 1997 1996
---- ---- ----
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 6,897,089 $ 5,696,407 $ 4,227,854
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 4,929,023 5,327,791 5,202,435
Abandonment and write down of oil and gas
properties 964,226 523,513 671,992
Loss (gain) on sale of property and equipment 5,613 (9,629) 56,941
Gain on sale of other assets (1,129,184) - -
Deferred income taxes - (150,000) (10,000)
Changes in assets and liabilities:
Accounts receivable (426,624) 472,370 (348,299)
Purchase of short-term investments (2,221,056) - -
Other current assets (28,937) 19,406 (6,925)
Other assets (12,255) 5,070 18,374
Accounts payable 459,524 (38,782) 2,220
Accrued expenses 133,294 (41,087) (79)
Total adjustments ---------- ----------- ----------
2,673,624 6,108,652 5,586,659
Net cash provided by operating activities ---------- ----------- ----------
9,570,713 11,805,059 9,814,513
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds received on receivables from officers and
employees 540,914 637,434 517,652
Advances disbursed to officers and employees (545,169) (719,180) (477,500)
Purchase of property and equipment (5,905,286) (7,809,435) (5,508,792)
Purchase of other assets (271,125) (102,384) (313,306)
Proceeds on sale of property and equipment and
other assets 1,862,000 23,436 68,192
Net cash used by investing activities ---------- ---------- ----------
(4,318,666) (7,970,129) (5,713,754)
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions (3,128,596) (3,180,447) (3,236,795)
Repurchase of Units (175,219) (897,631) (238,964)
Proceeds from issuance of debt including revolver
activity 2,900,000 4,500,000 4,500,000
Payments on debt including revolver activity (5,233,245) (4,316,691) (4,812,373)
Net cash used by financing activities ---------- ---------- ----------
(5,637,060) (3,894,769) (3,788,132)
---------- ---------- ----------
NET (DECREASE) INCREASE IN CASH AND
EQUIVALENTS (385,013) (59,839) 312,627
CASH AND EQUIVALENTS - JANUARY 1 679,531 739,370 426,743
---------- ---------- ----------
CASH AND EQUIVALENTS - DECEMBER 31 $ 294,518 $ 679,531 $ 739,370
========== ========== ==========
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest $ 178,119 $ 250,831 $ 223,286
Income taxes 70,000 - -
The accompanying notes are an integral part of these financial statements.
F-8
36
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 offered to exchange (the "Exchange Offer") its
Units of limited partnership interest for the common
shares of EEI and the interests of the Investors in the
Programs (collectively, the "Interests"). 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 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 Exchange Value of
$66,996,249 accepted the offer and tendered their
Interests. Effective on such date, Everflow acquired these
Interests, which include partnership interests and working
interests in the Programs, and all of the outstanding EEI
shares. Of these Interests tendered in the Exchange Offer,
$28,565,244 was represented by the EEI shares and
$38,431,005 by the remaining Interests. Approximately
6,632,000 Units were issued pursuant to the Exchange
Offer.
The tax-free combination of the Programs and EEI with
Everflow was accounted for as a reorganization of
affiliated entities under common control. Accordingly, the
accompanying financial statements reflect the historical
costs of the Programs and EEI.
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. Everflow Management Limited, LLC was
formed in March 1999 as the successor to Everflow's
original general partner, Everflow Management Company.
The members of Everflow Management Limited, LLC are
Everflow Management Corporation ("EMC"), three 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.
F-9
37
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(CONTINUED)
C. Use of Estimates - The preparation of financial statements
in conformity with generally accepted accounting
principles requires management to make estimates and
assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those
estimates.
D. Fair Value of Financial Instruments - The fair values of
cash, accounts receivable, short-term investments (based
on quoted market values), accounts payable and other
short-term obligations approximate their carrying values
because of the short maturity of these financial
instruments. The carrying values of the Company's
long-term obligations approximate their fair value. In
accordance with Statement of Financial Accounting
Standards ("SFAS") No. 107, "Disclosure About Fair Value
of Financial Instruments," rates available at balance
sheet dates to the Company are used to estimate the fair
value of existing debt.
E. Cash Equivalents - For purposes of the statement of cash
flows, the Company considers all highly liquid debt
instruments purchased with a maturity of three months or
less to be cash equivalents. The Company maintains at
various financial institutions cash and cash equivalents
which may exceed federally insured amounts and which may,
at times, significantly exceed balance sheet amounts due
to float.
F. 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 $4,876,838,
$5,254,190 and $5,127,388 for the years ended December 31,
1998, 1997 and 1996, 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.
F-10
38
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 (Continued)
SFAS No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of,"
requires that long-lived assets (including oil and gas
properties) and certain identifiable intangibles be
reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount of an
asset may not be recoverable. Everflow utilizes a field by
field basis for assessing impairment of its oil and gas
properties. The Company wrote down oil and gas properties
by approximately $426,000, $199,000 and $262,000 during
1998, 1997 and 1996, 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
$733,000 - 39 years). Depreciation on pipeline and support
equipment and other corporate property and equipment
amounted to $52,185, $73,601 and $75,047 for the years
ended December 31, 1998, 1997 and 1996, 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.
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 will earn and receive
monthly management and operating fees from certain joint
venture partners after the properties are completed and
placed into production.
F-11
39
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(CONTINUED)
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
Statement of Financial Accounting Standards No. 109 (SFAS
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 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 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 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 6,190,094, 6,293,796 and
6,406,492 in 1998, 1997 and 1996, respectively.
F-12
40
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 1997, SFAS 130,
"Reporting Comprehensive Income," was issued. SFAS 130
established new standards for reporting comprehensive
income and its components and is effective for fiscal
years beginning after December 15, 1997. In June 1997, the
Financial Accounting Standards Board issued SFAS 131,
"Disclosure About Segments of an Enterprise and Related
Information." SFAS 131 changes the standards for reporting
financial results by operating segments, related products
and services, geographical areas and major customers and
is adoptable by December 31, 1998. In February 1998, SFAS
132, "Employers' Disclosures About Pensions and Other
Postretirement Benefits," was issued. SFAS 132
standardizes the disclosure requirements for pension and
other postretirement benefit plans but does not change the
measurement or recognition of those plans. SFAS 132 is
effective for fiscal years beginning after December 15,
1997. In June 1998, SFAS 133, "Accounting for Derivative
Instruments and Hedging Activities," was issued. SFAS 133
establishes accounting and reporting standards for
derivative instruments and hedging activities. SFAS 133 is
effective for fiscal years beginning after June 15, 1999.
The effect of adoption or anticipated adoption of the
above standards had no, or is expected to have no,
material effect on the Company's financial statements.
K. Year 2000 - The Year 2000 problem, software, hardware or
an embedded chip that does not correctly process date
information for years after 1999, results from the
practice of storing date information with only the last
two digits of the year. The Company began to address Year
2000 issues in 1997. The scope of the Year 2000 readiness
effort includes the Company's internal information
technology ("IT") systems, such as hardware and software;
non-IT systems with date- sensitive characteristics; the
status of key third parties, including suppliers, service
providers and customers. The Company's major IT
applications are currently Year 2000 ready. Remediation
and testing of the balance of the IT systems are expected
to be completed by fall 1999. The Company is in the early
stages of analyzing the readiness of non-IT systems and
anticipates that remediation and testing of any
noncompliant systems will be completed by October 1999.
The Company also has taken initial steps to determine the
compliance of key third parties and expects that it will
have received and reviewed responses from the majority of
such parties by October 1999. Although the Company expects
to meet the target dates for completion of remediation and
testing and for determining the status of key third
parties, the Company will attempt to develop contingency
plans should the programs not be completed when
anticipated or should the third parties not be ready on a
timely basis.
Costs of addressing the Year 2000 issue to date
approximate $50,000. It is anticipated that an additional
$100,000 will be incurred. Substantially all of these
outlays are expected to result from remediation of
existing systems as opposed to replacing existing systems.
Costs are being funded from operating cash flows. The
actual costs of the Company's Year 2000 efforts may vary
from current estimates, which are based on information
available at this time.
F-13
41
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(CONTINUED)
K. Year 2000 (Continued)
Although the Company believes that it is taking
appropriate precautions against disruption of its systems
due to the Year 2000 issue, there can be no assurance that
the Company will identify all Year 2000 problems in
advance of their occurrence(s) or that the Company will be
able to successfully remedy all problems that are
discovered. Furthermore, there can be no assurance that
the Company's third party relationships will not be
adversely affected by Year 2000 issues. The Company is in
the process of developing contingency plans to address the
potential effects of problems arising from Year 2000
noncompliance. While the Company does not anticipate that
costs of Year 2000 disruptions will have a material
adverse effect, Year 2000 disruptions, arising either from
within the Company or through third party relationships,
could have a material adverse effect on the Company's
business, operating results and financial condition.
L. Reclassifications - Certain reclassifications were made to
prior period financial statement presentations to conform
with current period presentations.
NOTE 2. SHORT-TERM INVESTMENTS
Short-term investments consist 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 June 1997, the Company entered into an agreement that replaced
its prior credit agreements. The agreement provides for a
revolving line of credit in the amount of $7,000,000, all of
which is available. The revolving line of credit provides for
interest payable quarterly at LIBOR plus 175 basis points with
the principal due at maturity (as renewed), May 31, 1999. The
Company anticipates renewing the facility on a year to year basis
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 $7,000,000; (ii) tangible net
worth of at least $40,000,000; and (iii) a total debt to tangible
net worth ratio of not more than 0.5 to 1.0. In addition, there
are restrictions on mergers, sales and acquisitions, the
incurrence of additional debt and the pledge or mortgage of the
Company's assets.
F-14
42
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 3. CREDIT FACILITIES AND LONG-TERM DEBT (CONTINUED)
Borrowings on revolving credit facilities amounted to $1,800,000
and $4,100,000 at December 31, 1998 and 1997, respectively. The
following schedule reflects activity under the Company's
revolving credit facilities for the years ended December 31,
1998, 1997 and 1996. The average amount outstanding under the
facility was calculated using daily balances and a 365 day
period. The weighted average interest rates were calculated by
dividing the interest expense for the year for such borrowings by
the average amounts outstanding during the period.
Weighted
Maximum Average Average
Amount Amount Interest
Outstanding Outstanding Rate
----------- ----------- ----
Year Ended December 31:
1998 $4,100,000 $1,743,014 7.5%
1997 $4,100,000 $1,796,986 8.0%
1996 $4,800,000 $2,645,479 8.4%
For purposes of the Company's borrowings LIBOR was 5.06% and
5.93% at December 31, 1998 and 1997, respectively, and the prime
rate was 8.25% at December 31, 1996.
The Company purchased a building and funded its cost, including
improvements, in part, through mortgage notes. Two of the notes,
which have an aggregate balance of $363,053 and $388,979 at
December 31, 1998 and 1997, respectively, bear interest at 6.51%
per annum until October 6, 2001 and then a variable rate of .5%
above prime or the three year constant treasury maturity index
plus 2.25% until maturity. A third note, which has a balance of
$92,845 and $100,164 at December 31, 1998 and 1997, respectively,
bears interest at 8.41% per annum until June 25, 2000 and then a
variable rate of .5% above prime or the three year constant
treasury maturity index plus 2.25% until maturity. The notes
require aggregate payments of principal and interest of $5,312
per month. Maturities on the notes are expected to be as follows:
1999 - $30,805; 2000 - $35,200; 2001 - $37,700; 2002 - $40,500;
2003 - $43,500; thereafter - $268,193.
NOTE 4. PARTNERS' EQUITY
Units represent limited partnership interests in Everflow. The
Units are transferable subject only to the approval of any
transfer by Everflow Management Limited, LLC and to the laws
governing the transfer of securities. The Units are not listed
for trading on any securities exchange nor are they quoted in the
automated quotation system of a registered securities
association. However, Unitholders have an opportunity to require
Everflow to repurchase their Units pursuant to the Repurchase
Right.
Under the terms of the limited partnership agreement, initially,
99% of revenues and costs are allocated to the Unitholders (the
limited partners) and 1% of revenues and costs are allocated to
the General Partner. Such allocation has changed and will change
in the future due to Unitholders electing to exercise the
Repurchase Right.
F-15
43
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 4. PARTNERS' EQUITY (CONTINUED)
The partnership agreement provides that Everflow will repurchase
for cash up to 10% of the then outstanding Units, to the extent
Unitholders offer Units to Everflow for repurchase pursuant to
the Repurchase Right. The Repurchase Right entitles any
Unitholder, between May 1 and June 30 of each year, to notify
Everflow that he elects to exercise the Repurchase Right and have
Everflow acquire certain or all of his Units. The price to be
paid for any such Units 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 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 so
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,
1998 calculation, is estimated to be $5.79 per Unit, net of the
distributions ($.375 per Unit in total) expected to be made in
January and April 1999.
Units repurchased pursuant to the Repurchase Right, for each of
the four years in the period ended December 31, 1998, are as
follows:
Per Unit
-------------------------------------------------------------
Calculated Units
Price for Less Outstanding
Repurchase Premium Interim Net # of Units Following
Year Right Offered Distributions Price Paid Repurchased Repurchase
---- ----- ------- ------------- ---------- ----------- ----------
1995 $ 4.72 $ .28 $ .375 $ 4.625 81,522 6,433,044
1996 $ 4.48 $ .27 $ .25 $ 4.50 53,103 6,379,941
1997 $ 5.46 $ - $ .25 $ 5.21 172,290 6,207,651
1998 $ 5.24 $ - $ .25 $ 4.99 35,114 6,172,537
F-16
44
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 5. PROVISION FOR INCOME TAXES
As referred to in Note 1, EEI and its subsidiaries account for
current and deferred income taxes under the provisions of SFAS
No. 109. The deferred taxes are the result of temporary
differences arising from differences in financial reporting and
tax reporting methods for EEI's proved properties.
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,
---------------------------------------------------------------
1998 1997 1996
------------------- ------------------ --------------------
Amount % Amount % Amount %
------ - ------ - ------ -
Provision based on the
statutory rate (for taxable
income up to $10,000,000) $ 2,369,000 34.0 $ 1,886,000 34.0 $ 1,434,000 34.0
Tax effect of:
Non-taxable status of the
Programs and Everflow (2,097,000) (30.1) (1,891,000) (34.1) (1,368,000) (32.4)
Excess statutory depletion (95,000) (1.4) (95,000) (1.7) (90,000) (2.1)
Graduated tax rates, state
income tax and other - net (107,000) (1.5) (50,000) (0.9) 14,000 0.3
---------- ---- --------- ---- ---------- ----
Total $ 70,000 1.0 $ (150,000) (2.7) $ (10,000) (0.2)
========== ==== ========= ==== ========== ====
EEI has percentage depletion deduction carryforwards for tax
purposes of approximately $1,800,000. These carryforwards can be
carried forward indefinitely. For financial reporting purposes,
the deferred tax liability at December 31, 1998 and 1997 has been
reduced by approximately $754,000 and $820,000, respectively, for
the tax effect of carryforwards.
NOTE 6. RETIREMENT PLAN
The Company has a defined contribution plan pursuant to Section
401(k) of the Internal Revenue Code for all employees who had
reached the age of 21 and completed one year of service.
Contributions to the plan are at the discretion of EMC's Board of
Directors. The Company made contributions of $83,295, $88,788 and
$38,595 for the years ended December 31, 1998, 1997 and 1996,
respectively.
NOTE 7. RELATED PARTY TRANSACTIONS
Since 1989, EEI provided certain employees with an opportunity to
receive assignments of certain overriding royalty interests which
were created at the time EEI generated an oil and gas lease for
acquisition by oil and gas drilling programs. Not all leases
generated and acquired by such Programs had an overriding royalty
interest reserved for assignment to employees. Certain employees
of the Company have been given the option of having a portion of
their compensation in the form of an assignment in certain of
such overriding royalty interests. Those employees who elect to
receive a portion of their compensation in this form receive an
assignment of a pro rata portion of each of the overriding
royalty interests selected. During the calendar years ended
December 31, 1998, 1997 and 1996, approximately $180,000,
$175,000 and $121,000, respectively, was distributed to such
employees from such overriding royalty interests.
F-17
45
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 7. RELATED PARTY TRANSACTIONS (CONTINUED)
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 175 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. Additionally, because of the
number of recent transactions involving the purchase and sale of
Appalachian Basin oil and gas companies and properties,
management of the Company and the Company's investment bankers
continue to evaluate the sale of the Company and other
alternatives to maximize Unitholder value. However, management
cannot predict whether any sale transaction will be a viable
alternative for the Company in the immediate future.
F-18
46
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 8. BUSINESS SEGMENTS, RISKS AND MAJOR CUSTOMERS (CONTINUED)
Gas sales accounted for 93%, 86% and 84% of total oil and gas
sales in 1998, 1997 and 1996, respectively. Approximate
percentages of oil and gas sales from significant purchasers for
the years ended December 31, 1998, 1997 and 1996, respectively,
were as follows:
Customer 1998 1997 1996
-------- ---- ---- ----
The East Ohio Gas Company ("East Ohio") 74% 70% 72%
Ergon Oil Purchasing, Inc. (formerly
Quaker State Refining Corporation) 7 10 12
-- -- --
81% 80% 84%
== == ==
The Company expects that East Ohio and Ergon will be the only
major customers in 1999.
The Company has various Intermediate Term Adjustable Price Gas
Purchase Agreements (the "East Ohio Contracts") with East Ohio.
Pursuant to the East Ohio Contracts and subject to certain
restrictions and adjustments, including termination clauses, East
Ohio is obligated to purchase, and the Company is obligated to
sell, all natural gas production from a specified list of wells
(the "Contract Wells"). A summary of Everflow's principal East
Ohio Gas Contracts at December 31, 1998 follows:
Contract Period Number Required Shut-In Limitation
Date Covered of Wells Purchases Provisions Provisions
---- ------- -------- --------- ---------- ----------
9/3/91 11/91-10/01 426 275 days/year Maximum of May-Oct. - 50% of
60 days (Nov.- production from
April) prior 6 month period
3/10/94 4/94-3/00 52 275 days/year Maximum of May-Oct. - 50% of
60 days (Nov.- production from
April) prior 6 month period
8/10/94 11/94-10/00 27 Nov.-March April-Oct. Shut-in provisions
Net Price per MCF
--------------------------------------------------------------------------------------
Adjusted Prices
Contract --------------------------------------------------------------------------------------
Date 11/96-4/97 5/97-10/97 11/97-4/98 5/98-10/98 11/98-4/99 5/99-10/00
---- ---------- ---------- ---------- ---------- ---------- ----------
9/3/91 $ 3.31 $ 2.68 $ 3.90 $ 3.27 $ 3.71 $ 3.08
3/10/94 $ 2.95 $ 2.25 $ 3.54 $ 2.84 $ 3.35 $ 2.65
8/10/94 $ 3.55 N/A $ 4.14 N/A $ 3.95 N/A
F-19
47
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 8. BUSINESS SEGMENTS, RISKS AND MAJOR CUSTOMERS (CONTINUED)
As detailed in the table, the price paid for natural gas
purchased under the East Ohio Contracts varies with the
production period. Pricing under the East Ohio Contracts is
adjusted annually, up or down, by an amount equal to 80% of the
increase or decrease in East Ohio's average Gas Cost Recovery
("GCR") rates. Additionally, the 8/10/94 contract provides for a
price cap equal to the quarterly GCR, which amounted to $3.84,
$4.20 and $4.05 in November 1998, 1997 and 1996, respectively.
Price caps related to this contract are not included in the
table. The net price per MCF includes $.20 per MCF for
transportation less a $.02 per MCF metering charge.
In addition to the East Ohio Contracts, the Company has various
short-term contracts (covering production from 72 gross wells at
December 31, 1998) which have a primary term of one year.
Sixty-seven of the wells are covered by fixed price contracts
that provide for the sale of the Company's gas at $2.65 to $2.82
per MCF. The remaining five wells are covered by a fixed rate
contract that provides for the sale of the Company's gas based on
monthly gas deliveries, with price provisions ranging from $2.66
for gas production in the month of July to $3.32 in January
(including transportation allowances). There are no significant
production restrictions under the Company's short-term contracts
as they relate to the Company's existing wells. Future wells can
be added to certain of the contracts subject to gross production
restrictions under the contracts.
NOTE 9. COMMITMENTS AND CONTINGENCIES
Everflow paid a dividend in January 1999 of $.125 per Unit. The
distribution amounted to approximately $780,000.
The Company is the General Partner in certain oil and gas
partnerships. As General Partner, the Company shares in unlimited
liability to third parties with respect to the operations of the
Partnerships and may be liable to limited partners for losses
attributable to breach of fiduciary obligations.
The Company has, or is subject to, compensation agreements with
certain executive officers and employees that become operative
only upon a change in control of the Company, as defined in those
agreements. Certain of the agreements provide for compensation
continuation for up to three years and bonus payments based on
valuation of the Company at a date of sale. The current change in
control arrangements expire on April 30, 1999.
NOTE 10. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING
ACTIVITIES (UNAUDITED)
The following supplemental unaudited oil and gas information is
required by Statement of Financial Accounting Standards (SFAS)
No. 69, "Disclosures About Oil and Gas Producing Activities."
F-20
48
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 10. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING
ACTIVITIES (UNAUDITED) (CONTINUED)
The tables on the following pages set forth pertinent data with
respect to the Company's oil and gas properties, all of which are
located within the continental United States.
CAPITALIZED COSTS RELATING TO OIL AND GAS
PRODUCING ACTIVITIES
December 31,
-----------------------------------------------
1998 1997 1996
---- ---- ----
Proved oil and gas properties $110,178,841 $105,080,039 $ 98,321,815
Pipeline and support equipment 506,153 466,717 451,971
----------- ----------- -----------
110,684,994 105,546,756 98,773,786
Accumulated depreciation,
depletion, amortization
and write down 61,379,736 56,192,136 51,286,350
----------- ----------- -----------
Net capitalized costs $ 49,305,258 $ 49,354,620 $ 47,487,436
=========== =========== ===========
COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
December 31,
------------------------------------------
1998 1997 1996
---- ---- ----
Property acquisition costs $ 629,603 $ 845,647 $ 972,653
Development costs, including
prepayments 5,105,622 6,814,035 4,109,532
In 1998 and 1997, development costs include the purchase of
approximately $348,000 and $1,065,000, respectively, of producing
oil and gas properties.
F-21
49
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 10. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING
ACTIVITIES (UNAUDITED) (CONTINUED)
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
December 31,
-------------------------------------------
1998 1997 1996
---- ---- ----
Oil and gas sales $16,058,164 $15,418,755 $14,078,491
Production costs (2,550,686) (2,427,124) (2,192,349)
Depreciation, depletion and
amortization (4,904,221) (5,287,066) (5,155,681)
Abandonment and write down of
oil and gas properties (964,226) (523,513) (671,992)
---------- ---------- ----------
7,639,031 7,181,052 6,058,469
Income tax expense 150,000 135,000 360,000
---------- ---------- ----------
Results of operations for oil and
gas producing activities
(excluding corporate overhead
and financing costs) $ 7,489,031 $ 7,046,052 $ 5,698,469
========== ========== ==========
Income tax expense was computed using statutory tax rates and
reflects permanent differences that are reflected in the
Company's consolidated income tax expense for the year.
F-22
50
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 10. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING
ACTIVITIES (UNAUDITED) (CONTINUED)
ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES
Oil Gas
(BBLS) (MCF)
------ -----
Balance, January 1, 1996 832,000 40,058,000
Extensions, discoveries and other
additions 119,000 3,665,000
Production (112,000) (4,264,000)
Revision of previous estimates 73,000 1,556,000
-------- ----------
Balance, December 31, 1996 912,000 41,015,000
Extensions, discoveries and other
additions 78,000 4,093,000
Production (126,000) (4,322,000)
Revision of previous estimates (42,000) (129,000)
-------- ----------
Balance, December 31, 1997 822,000 40,657,000
Extensions, discoveries and other
additions 67,000 4,844,000
Production (94,000) (4,575,000)
Revision of previous estimates 140,000 11,977,000
-------- ----------
Balance, December 31, 1998 935,000 52,903,000
======== ==========
PROVED DEVELOPED RESERVES:
December 31, 1995 832,000 40,058,000
December 31, 1996 912,000 41,015,000
December 31, 1997 822,000 40,657,000
December 31, 1998 935,000 52,903,000
The Company has not determined proved reserves associated with
its proved undeveloped acreage. At December 31, 1998 and 1997,
the Company had 1,600 and 2,200 net proved undeveloped acres,
respectively. The carrying cost of the proved undeveloped acreage
that is included in proved properties amounted to $1,569,741 and
$1,840,542 at December 31, 1998 and 1997, respectively.
F-23
51
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 10. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING
ACTIVITIES (UNAUDITED) (CONTINUED)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS
December 31,
-------------------------------
1998 1997 1996
---- ---- ----
(Thousands of Dollars)
Future cash inflows from sales of oil
and gas $153,538 $124,466 $132,308
Future production and development
costs 57,255 48,085 49,255
Future income tax expense 2,253 1,885 2,171
------- ------- -------
Future net cash flows 94,030 74,496 80,882
Effect of discounting future net cash
flows at 10% per annum 42,551 28,402 30,375
------- ------- -------
Standardized measure of discounted
future net cash flows $ 51,479 $ 46,094 $ 50,507
======= ======= =======
CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED
FUTURE NET CASH FLOWS
Year Ended December 31,
--------------------------------
1998 1997 1996
---- ---- ----
(Thousands of Dollars)
Balance, beginning of year $ 46,094 $ 50,507 $ 41,805
Extensions, discoveries and other
additions 6,004 5,553 6,168
Development costs incurred 801 270 308
Revision of previous estimates 11,926 (424) 2,616
Sales of oil and gas, net of production
costs (13,507) (12,992) (11,886)
Net change in income taxes (60) 149 (20)
Net changes in prices and production
costs (1,193) (2,291) 5,660
Accretion of discount 4,609 5,051 4,181
Other (3,195) 271 1,675
-------- -------- --------
Balance, end of year $ 51,479 $ 46,094 $ 50,507
======== ======== ========
F-24
52
EVERFLOW EASTERN PARTNERS, L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 10. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING
ACTIVITIES (UNAUDITED) (CONTINUED)
The estimated future cash flows are determined based on year-end
prices for crude oil, current allowable prices (reduced for
periods beyond the contract period to year-end market prices)
applicable to expected natural gas production, estimated
production of proved crude oil and natural gas reserves,
estimated future production and development costs of reserves,
based on current economic conditions, and the estimated future
income tax expense, based on year-end statutory tax rates (with
consideration of future tax rates already legislated) to be
incurred on pretax net cash flows less the tax basis of the
properties involved. Such cash flows are then discounted using a
10% rate.
The methodology and assumptions used in calculating the
standardized measure are those required by SFAS No. 69. It is not
intended to be representative of the fair market value of the
Company's proved reserves. The valuation of revenues and costs
does not necessarily reflect the amounts to be received or
expended by the Company. In addition to the valuations used,
numerous other factors are considered in evaluating known and
prospective oil and gas reserves.
F-25
53
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
Everflow Management Limited, LLC as of March 20, 1999 are Everflow Management
Corporation, an Ohio corporation ("EMC"), Thomas L. Korner, William A. Siskovic
and David T. Matak, 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 Everflow Management Limited,
LLC. EMC was formed in September 1990 to act as the Managing General Partner of
Everflow Management Company, the predecessor of Everflow Management Limited,
LLC. EMC is owned by the other members of Everflow Management Limited, LLC and
EMC currently has no employees, but as Managing Member of Everflow Management
Limited, LLC, makes all management and business decisions on behalf of Everflow
Management Limited, LLC 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, 1999 are as follows:
Positions and Positions and
Name Age Offices with EEI Offices with EMC
- -------------------- --- ------------------------ --------------------------
Robert F. Sykes 75 Chairman of the Board Chairman of the Board
and Director
Thomas L. Korner 45 President and Director President and Director
David A. Kidder 60 Treasurer None
David T. Matak 40 Vice President/Land Vice President and
Director
William A. Siskovic 43 Vice President, Secretary, Vice President, Secretary-
Principal Financial and Treasurer, Principal
Accounting Officer and Financial and Accounting
Director Officer and Director
-27-
54
All directors of EEI are elected to serve by the Company, which is EEI's sole
shareholder. All officers of EEI serve at the pleasure of the Board of
Directors. Directors and officers of EEI receive no compensation or fees for
their services to EEI or their services on behalf of the Company.
All directors and officers of EMC hold their positions with
EMC pursuant to a shareholders' agreement among EMC and such directors and
officers. The shareholders agreement controls the operation of EMC, provides for
changes in share ownership of EMC, and determines the identity of the directors
and officers of EMC as well as their replacement.
ROBERT F. SYKES has been a Director of EEI since March 1987 and Chairman of the
Board since May 1988. Mr. Sykes is the Chairman of the Board and a Director of
EMC and has served in such capacities since its formation in September 1990. He
was the Chairman of the Board of Sykes Datatronics, Inc., Rochester, New York,
from its organization in 1986 until his resignation in January 1989. Sykes
Datatronics, Inc. is a manufacturer of telephone switching equipment. Mr. Sykes
also served as President and Chief Executive Officer of Sykes Datatronics, Inc.
from 1968 until October 1983 and from January 1985 until October 1985. Mr. Sykes
also has been a Director of Voplex, Inc., Rochester, New York, a manufacturer of
plastic products, and a Director of ACC Corp., a long distance telephone
company.
THOMAS L. KORNER has been President of EEI and EMC since November 1995 and the
President and Treasurer of Everflow Nominee. Mr. Korner is also a Director of
EMC and has served in such capacity since its formation in September 1990. He
served as Vice President and Secretary of EEI from April 1985 to November 1995
and as Vice President and Secretary of EMC from September 1990 to November 1995.
He served as the Treasurer of EEI from June 1982 to June 1986. Mr. Korner
supervises and oversees all aspects of EEI's business, including oil and gas
property acquisition, development, operation and marketing. Prior to joining EEI
in June 1982, Mr. Korner was a practicing certified public accountant with Hill,
Barth and King, certified public accountants, and prior to that with Arthur
Andersen & Co., certified public accountants. He has a Business Administration
Degree from Mt. Union College.
DAVID A. KIDDER has been the Treasurer of EEI since June 1986 and has been
employed by EEI since April 1985. From 1983 to 1985, he was Treasurer of LGM
Corporation, Columbus, Ohio, an oil and gas service company; from 1982 to 1983,
he was Treasurer of OPEX, Inc., Columbus, Ohio, a producer of oil and gas; and
from 1980 to 1981, he was Treasurer of United Petroleum, Inc., Columbus, Ohio, a
producer of oil and gas. From 1973 to 1980, Mr. Kidder was involved in the oil
and gas industry in various financial and accounting capacities. Prior to that
time, Mr. Kidder practiced as a certified public accountant with Coopers &
Lybrand, certified public accountants. Mr. Kidder has a Bachelor of Arts Degree
in Accounting from the University of Cincinnati.
DAVID T. MATAK has been Vice President of EEI since July 1987. He is primarily
responsible for the exploration and development activities of EEI. Mr. Matak is
a Vice President and a Director of EMC and has served in such capacities since
its formation in September 1990. From September 1982 to June 1984, Mr. Matak
served as a teaching assistant in the Geology
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55
Department of the University of Akron and worked on the Clinton Research Project
at the university. From March 1984 to July 1986, Mr. Matak was a geologist with
Gasearch, Inc., Girard, Ohio, where he logged and evaluated over 200 wells and
evaluated and reviewed all locations to be drilled by Gasearch, Inc. Mr. Matak
has a Bachelor of Science Degree in Biology and Geology from Mt. Union College
and a Masters Degree in Geology from the University of Akron.
WILLIAM A. SISKOVIC has been a Vice President of EEI since January 1989. Mr.
Siskovic is a Vice President, Secretary-Treasurer, Principal Financial and
Accounting Officer and a Director of EMC. He has served as Principal Financial
Officer and Secretary of EMC since November 1995 and in all other capacities
since the formation of EMC in September 1990. He is responsible for the
financial operations of the Company and EEI. From August 1980 to July 1984, Mr.
Siskovic served in various financial and accounting capacities including
Assistant Controller of Towner Petroleum Company, a public independent oil and
gas operator, producer and drilling fund sponsor company. From August 1984 to
September 1985, Mr. Siskovic was a Senior Consultant for Arthur Young & Company,
certified public accountants, where he was primarily responsible for the firm's
oil and gas consulting practice in the Cleveland, Ohio office. From October 1985
until joining EEI in April 1988, Mr. Siskovic served as Controller and Principal
Accounting Officer of Lomak Petroleum, Inc., a public independent oil and gas
operator and producer. He has a Business Administration Degree in Accounting
from Cleveland State University.
SECTION 16 DISCLOSURE. 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 review of the copies of such forms furnished
to the Company, the Company believes that for all of 1998, all Section 16(a)
filing requirements applicable to its officers, directors and greater than 10%
beneficial owners were complied with.
ITEM 11. EXECUTIVE COMPENSATION
- --------------------------------------
As a limited partnership the Company has no executive officers
or directors, but is managed by Everflow Management Limited, LLC, the General
Partner of the Company. 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, 1998, 1997 and 1996, of those persons
who were, at December 31, 1998: (i) the chief executive officer; and (ii) the
other two most highly compensated executive officers of the
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56
Company. The Chief Executive Officer and such other executive officers are
hereinafter referred to collectively as the "Named Executive Officers."
SUMMARY COMPENSATION TABLE
Annual Compensation
----------------------------------------------------------
Other
Annual All Other
Name and Compen- Compen-
Principal Position Year Salary Bonus sation sation(1)
------------------ ---- ------ ----- --------- -----------
Thomas L. Korner 1998 80,000 39,000 2,067 40,302(2)
President 1997 80,000 43,375 1,818 35,965(2)
1996 71,250 75,500 2,190 26,846(2)
David T. Matak 1998 80,000 39,000 1,455 42,353(3)
Vice President 1997 80,000 43,375 1,102 37,941(3)
1996 73,000 95,500 1,241 28,530(3)
William A. Siskovic 1998 80,000 39,000 1,489 31,087(4)
Vice President and 1997 80,000 43,375 1,497 26,609(4)
Principal Financial and 1996 75,625 65,500 2,073 17,996(4)
Accounting Officer
No Named Executive Officer received personal benefits or perquisites during
1998, 1997 and 1996 in excess of the lesser of $50,000 or 10% of his aggregate
salary and bonus.
(1) Includes amounts received from participation in certain overriding
royalty interest arrangements organized by EEI. Also includes amounts
contributed under the Company's 401(K) Retirement Savings Plan. The
Company made a profit sharing contribution and matched employees'
contributions to the 401(K) Retirement Savings Plan to the extent of
50% of the first 6% of a participant's salary reduction. The amounts
attributable to the Company's matching contribution vest immediately.
(2) Includes amounts received by Thomas L. Korner from participation in
certain overriding royalty interest arrangements organized by EEI of
$33,031, $32,264 and $22,602 in 1998, 1997 and 1996, respectively.
(3) Includes amounts received by David T. Matak from participation in
certain overriding royalty interest arrangements organized by EEI of
$35,082, $34,240 and $24,365 in 1998, 1997 and 1996, respectively.
(4) Includes amounts received by William A. Siskovic from participation in
certain overriding royalty interest arrangements organized by EEI of
$23,816, $22,908 and $13,762 in 1998, 1997 and 1996, respectively.
-30-
57
Everflow Management Limited, LLC, 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
Everflow Management Limited, LLC as 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
Everflow Management Limited, LLC, as the General Partner of the Company.
Everflow Management Limited, LLC is entitled to share in the income and expense
of the Company on the basis of its interests as the General Partner of the
Company. Everflow Management Limited, LLC 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.
The Company has or is subject to compensation agreements with
certain Executive Officers and employees that become operative only upon a
change in control of the Company, as defined in these agreements. Certain of the
agreements provide for compensation continuation for up to three years and bonus
payments based on valuation of the Company at a date of sale. The current change
in control arrangements expire on April 30, 1999. The company does not
anticipate that a change in control of the Company will occur before April 30,
1999.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
- ------------------------------------------------------------------------------
Everflow Management Limited, LLC is a limited liability
company of which EMC, an Ohio corporation is the Managing Member. The members of
Everflow Management Limited, LLC are Thomas L. Korner, William A. Siskovic and
David T. Matak, all of whom are directors or officers of EEI, and Sykes
Associates, a limited partnership controlled by Robert F. Sykes, Chairman of the
Board of EEI and EMC. The members and their affiliates currently hold (in
addition to Everflow Management Limited, LLC's interest as a general partner of
the Company) 1,400,457 Units, representing approximately 23% of the outstanding
Units.
Everflow Management Limited, LLC, as General Partner of the
Company, owns a 1.07% general partner's interest in the Company.
The following table sets forth certain information with
respect to the number of Units beneficially owned as of March 20, 1999 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 Everflow Management Limited, LLC, and (ii) the ownership
of EMC.
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58
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) 1,062,854 17.22 57.1429 57.1429
Thomas L. Korner 157.814 2.56 14.2857 14.2857
David T. Matak 103,920 1.68 14.2857 14.2857
William A. Siskovic 75,869 1.23 14.2857 14.2857
All officers and directors as
a group (4 persons in EMC) 1,400,457 22.69 100.0000 100.0000
- -----------------------------
(1) Does not include the interest in the Company owned indirectly by such
individuals as a result of their ownership in (i) Everflow Management
Limited, LLC (based on Everflow Management Limited, LLC's 1.07% general
partner's interest in the Company) or (ii) EMC (based on EMC's 1% managing
member's interest in Everflow Management Limited, LLC).
(2) Includes the interest in Everflow Management Limited, LLC owned indirectly
by such individuals as a result of their share ownership in EMC resulting
from EMC's 1% managing member's interest in Everflow Management Limited,
LLC.
(3) Includes 739,245 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 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 its officers
the funds necessary to participate in the drilling and development of such
wells. Such loans currently accrue interest at the rate of LIBOR plus 175 basis
points per annum. As of December 31, 1998, the aggregate outstanding balance of
such indebtedness was approximately $549,649, with Thomas L. Korner, David T.
Matak and William A. Siskovic owing $140,790, $249,238 and $159,621,
respectively.
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59
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.
PART IV
-------
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
- -------------------------------------------------------------------------------
(a) (1) Financial Statements
--------------------
The following Consolidated Financial Statements of the
Registrant and its subsidiaries are included in Part II, Item 8:
Page(s)
-------
Auditors' Report on Audited Financial Statements F-3
Balance Sheets F-4 - F-5
Statements of Income F-6
Statements of Partners' Equity F-7
Statements of Cash Flows F-8
Notes to Financial Statements F-9 - F25
(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) On November 9, 1998, the Registrant filed a current report on Form 8-K
relating to pricing adjustments under the Company's Agreements with The
East Ohio Gas Company.
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60
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 29 , 1999
-------------------------------------------- ----
Robert F. Sykes
By: /s/Thomas L. Korner President and Director March 29 , 1999
-------------------------------------------- ----
Thomas L. Korner
By: /s/William A. Siskovic Vice President, March 29 , 1999
-------------------------------------------- ----
William A. Siskovic Secretary-Treasurer
and Director (principal
financial and accounting
officer)
By: /s/David T. Matak Vice President and March 29 , 1999
-------------------------------------------- ----
David T. Matak Director
61
Exhibit Index
-------------
Exhibit No. Description
----------- -----------
4.1 Certificate of Limited Partnership of the Registrant (1)
dated September 13, 1990, as filed with the Delaware
Secretary of State on September 14, 1990
4.2 Form of Agreement of Limited Partnership of the (1)
Registrant
4.3 General Partnership Agreement of Everflow (1)
Management Company
4.4 Articles of Incorporation of Everflow Management (1)
Corporation
4.5 Code of Regulations of Everflow Management (1)
Corporation
4.6 Shareholders Agreement for Everflow Management (1)
Corporation
4.7 Third Amended and Restated Loan Agreement, (2)
dated as of May 1, 1991 between Everflow
Eastern, Inc., the Registrant and the banks listed
therein, with National Bank of Detroit as Agent
4.8 First Amendment to Third Amended and Restated (5)
Loan and Security Agreements dated July 1, 1993,
between Everflow Eastern, Inc. and Everflow Eastern
Partners, L.P. and the banks listed therein, with
National Bank of Detroit as Agent
4.9 Revolving Credit Note to First Amendment to Third (5)
Amended and Restated Loan and Security Agreement
dated as of July 1, 1993
4.10 Credit Agreement dated January 19, 1995 between (8)
Everflow Eastern, Inc. and Everflow Eastern Partners, L.P.
and Bank One, Texas, National Association
E-1
62
Exhibit No. Description
- ----------- -----------
4.11 Amendment to Credit Agreement dated February 23, 1996 (13)
between Everflow Eastern, Inc. and Everflow Eastern
Partners, L.P. and Bank One, Texas, National Association
4.12 Second Amendment to Credit Agreement dated December 30, (13)
1996 between Everflow Eastern, Inc. and Everflow Partners,
L.P. and Bank One, Texas, National Association
4.13 Loan Modification Agreement dated June 16, 1997 between (14)
Bank One, N.A., Bank One, Texas, N.A. and Everflow
Eastern, Inc. and Everflow Eastern Partners, L.P.
4.14 Loan Modification Agreement dated May 29, 1998 between (15)
Bank One, N.A., Successor to Bank One, Texas, N.A., and
Everflow Eastern, Inc. and Everflow Eastern Partners L.P.
10.1 Lease Agreement dated June 30, 1984 by and (1)
between Village Green Associates, Inc. and
Everflow Eastern, Inc.
10.2 Gas Purchase Agreement dated September 3, 1991 (3)
by and between the Registrant and The East Ohio
Gas Company
10.3 Intermediate Term Adjustable Price Gas Purchase (4)
Agreement, contract #10342, dated October 9, 1992,
between The East Ohio Gas Company and Everflow
Eastern Partners, L.P.
10.4 Quaker State Full Load Crude Oil Purchase Agreement (4)
Dated January 13, 1993, between Quaker State Oil
Refining corporation and Everflow Eastern Partners, L.P.
10.5 Intermediate Term Adjustable Gas Purchase Agreement, (6)
Contract #10461, dated March 10, 1994, between The
East Ohio Gas Company and Everflow Eastern Partners, L.P.
10.6 Intermediate Term Adjustable Gas Purchase Agreement, (7)
Contract #10515, dated August 10, 1994, between The
East Ohio Gas Company and Everflow Eastern Partners, L.P.
E-2
63
Exhibit No. Description
----------- -----------
10.7 Operating facility lease dated October 3, 1995 between (9)
Everflow Eastern Partners, L.P. and A-1 Storage of
Canfield, Ltd.
10.8 Intermediate Term Adjustable Gas Purchase Agreement, (11)
Contract #11245, dated May 29, 1996, between The
East Ohio Gas Company and Everflow Eastern Partners, L.P.
10.9 Intermediate Term Adjustable Gas Purchase Agreement, (11)
Contract #11285, dated May 29, 1996, between The
East Ohio Gas Company and Everflow Eastern Partners, L.P.
10.10 One Year Term Gas Purchase Agreement dated August 1, (12)
1996, between Everflow Eastern Partners, L.P. and
JDS Energy Corporation
10.11 One Year Term Gas Purchase Agreement dated January 20, (13)
1997, between Everflow Eastern Partners, L.P. and
JDS Energy Corporation
10.12 Gas Purchase Agreement, Contract #11467, dated 64
November 1, 1997, between Everflow Eastern Partners, L.P.
and CNG Energy Services Corporation.
10.13 One Year Term Gas Purchase Agreement dated November 1, 73
1998, between Everflow Eastern Partners, L.P. and JDS
Energy Systems, Inc.
22.1 Subsidiaries of the Registrant (10)
27 Financial Data Schedule
- ------------------
(1) Incorporated herein by reference to the appropriate exhibit to Registrant's
Registration Statement on Form S-1 (Reg. No. 33-36919).
(2) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Quarterly Report on Form 10-Q for the second quarter ended
June 30, 1991.
(3) Incorporated herein by reference to the appropriate exhibit to Registrant's
Annual Report on Form 10-K for the year ended December 31, 1991 (File No.
0-19279).
(4) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Annual Report on Form 10-K for the year ended December 31,
1992 (File No. 0-19279).
(5) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Quarterly Report on Form 10-Q for the second quarter ended
June 30, 1993.
E-3
64
Exhibit Index
-------------
(6) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Quarterly Report on Form 10-Q for the second quarter ended
June 30, 1994.
(7) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Quarterly Report on Form 10-Q for the third quarter ended
September 30, 1994.
(8) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Annual Report on Form 10-K for the year ended December 31,
1994 (File No. 0-19279).
(9) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Quarterly Report on Form 10-Q for the third quarter ended
September 30, 1995.
(10) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Annual Report on Form 10-K for the year ended December 31,
1995 (File No. 0-19279).
(11) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Quarterly Report on Form 10-Q for the second quarter ended
June 30, 1996.
(12) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Quarterly Report on Form 10-Q for the third quarter ended
September 30, 1996.
(13) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Annual Report on Form 10-K for the year ended December 31,
1996 (File No. 0-19279).
(14) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Quarterly Report on Form 10-Q for the second quarter ended
June 30, 1997.
(15) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Quarterly Report on Form 10-Q for the second quarter ended
June 30, 1998.
E-4