SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934 FOR THE FISCAL YEAR ENDED JUNE 30, 2000.
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ________ TO
________.
Commission file number 333-29001-01
ENERGY CORPORATION OF AMERICA
(Exact name of registrant as specified in its charter)
WEST VIRGINIA 84-1235822
(State or other jurisdiction of incorporation or organization)
(IRS Employer Identification Number)
4643 SOUTH ULSTER STREET, SUITE 1100
DENVER, COLORADO 80237
(Address of principal executive offices and zip code)
(303) 694-2667
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
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 [ ]
<PAGE>
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of the 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. [X]
The aggregate market value of common stock held by non-affiliates of the
registrant: Class of Voting Stock and Number of Shares Held by Non-affiliates
at September 1, 2000 was 36,450 Shares. Market Value Held by Non-affiliates:
Unavailable.
The number of shares of the registrant's common stock, par value $1.00 per
share, outstanding at September 1, 2000 was 649,527 shares.
DOCUMENTS INCORPORATED BY REFERENCE:
NONE
2
<PAGE>
ENERGY CORPORATION OF AMERICA
TABLE OF CONTENTS
Page
Part I
Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . . 4
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . . 10
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . 10
Item 4. Submission of Matters to a Vote of Security Holders . . 10
Part II
Item 5. Market for the Registrant's Common Stock and Related
Stockholder Matters . . . . . . . . . . . . . . . . . . 11
Item 6. Selected Financial Data . . . . . . . . . . . . . . . 11
Item 7. Management's Discussion and Analysis of Results of
Operations and Financial Condition. . . . . . . . . . 11
Item 8. Consolidated Financial Statements and Supplementary Data
Independent Auditor's Report . . . . . . . . . . . 20
Balance Sheets . . . . . . . . . . . . . . . . . . 21
Statements of Operations . . . . . . . . . . . . . 23
Statements of Stockholders Equity . . . . . . . . 24
Statements of Cash Flows . . . . . . . . . . . . 25
Notes to Consolidated Financial Statements . . . 26
Supplemental Information on Oil and Gas Producing
Activities (Unaudited) . . . . . . . . . . . . . . . 42
Item 9. Changes In and Disagreements With Accountants on
Accounting and Financial Disclosure. . . . . . . . . . 45
Part III
Item 10. Directors and Officers of Registrant . . . . . . . . 46
Item 11. Executive Compensation. . . . . . . . . . . . . . . . . 49
Item 12. Security Ownership of Certain Beneficial Owners
and Management . . . . . . . . . . . . . . . . . . . . . 49
Item 13. Certain Relationships and Related Transactions . . . 51
Part IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K. . . . . . . . . . . . . . . . . . . 54
Part V
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58
All defined terms under Rule 4-10 (a) of Regulation S-X shall have their
statutorily prescribed meanings when used in this report. Quantities of natural
gas are expressed in this report in terms of thousand cubic feet (Mcf), million
cubic feet (Mmcf) or billion cubic feet (Bcf). Oil is quantified in terms of
barrels (Bbls), thousand barrels (Mbbls) or million barrels (Mmbbls). Oil is
compared to natural gas in terms of cubic feet of gas equivalent (Mcfe), million
of cubic feet equivalent (Mmcfe) or billion cubic feet equivalent (Bcfe). One
barrel of oil is the energy equivalent of six Mcf of natural gas. A dekatherm
(dth) is equal to one million British Thermal Units (Btu). A Btu is the amount
of heat required to raise the temperature of one pound of water one degree
Fahrenheit. With respect to information relating to the Company's working
interest in wells or acreage, "net" oil and gas wells or acreage is determined
by multiplying gross wells or acreage by the Company's working interest therein.
Unless otherwise specified, all references to wells and acres are gross.
3
<PAGE>
PART I
------
ITEM 1. BUSINESS
---------------------
GENERAL
-------
Energy Corporation of America (the "Company") is a privately held,
integrated energy company primarily engaged in the development, production,
transportation and marketing of natural gas and oil, primarily in the
Appalachian Basin. The Company was formed in June 1993 through an exchange of
shares with the common stockholders of Eastern American Energy Corporation
("Eastern American"). For the fiscal year ended June 30, 2000, the Company had
total revenues from continuing operations of $101.9 million and EBITDAX
(earnings before interest, income taxes, impairment and exploratory costs,
depreciation and amortization) from continuing operations of $4.1 million.
The Company conducts business through its principal wholly owned
subsidiaries, Eastern American, Westech Energy Corporation ("Westech") and
Westech Energy New Zealand ("WENZ"). Eastern American is one of the largest oil
and gas operators in the Appalachian Basin, including exploration, development
and production, and is engaged in the transportation and marketing of natural
gas. Westech is involved in oil and gas exploration and development in the Rocky
Mountain and Gulf Coast regions of the United States and Australia. WENZ is
involved in oil and gas exploration and development in New Zealand.
On December 20, 1999, the Company entered into a stock purchase and sale
agreement, a copy of which was filed on the Company's form 8-K filed January 10,
2000, with Allegheny Energy, Inc., wherein the Company agreed to sell all of the
stock of its wholly owned natural gas distribution company, Mountaineer Gas
Company and Subsidiaries ("Mountaineer") for $323 million, which included the
assumption of approximately $100 million of debt, ($223 million net to the
Company). The sale was subject to regulatory approval by the Securities and
Exchange Commission pursuant to the Public Utility Holding Company Act of 1935,
the West Virginia Public Service Commission and the Federal Trade Commission.
Upon receiving all necessary approvals, the sale was finalized August 18, 2000.
The Company expects to realize pre-tax gain of approximately $165 million on
this transaction. The use of these proceeds are restricted by debt covenants.
See Note 3 to the Consolidated Financial Statements for a complete discussion of
the transaction.
The financial statements have been reclassified to exclude the operating
results of Mountaineer from continuing operations, and for accounting purposes
to classify such results as discontinued operations. The following discussion,
unless otherwise noted, relates only to the Company's continuing operations.
The principal offices of the Company are located at 4643 South Ulster
Street, Suite 1100, Denver, Colorado 80237, and the telephone number is (303)
694-2667.
As used herein the "Company" refers to the Company alone or together with
one or more of its subsidiaries, excluding Mountaineer.
SEGMENT INFORMATION
--------------------
The Company's principal businesses constitute two operating segments. For
financial information on these segments, see Note 16 to the Consolidated
Financial Statements.
4
<PAGE>
GAS AND OIL EXPLORATION AND PRODUCTION
-------------------------------------------
The Company's proved net gas and oil reserves are estimated as of June 30,
2000 at 157 Bcf and 983 Mbbls, respectively. For the fiscal year ended June 30,
2000, the Company's net gas production was approximately 7.4 Bcf and net oil
production was approximately 113 Mbbls, for a total of 8.1 net Bcfe.
REGIONAL OPERATIONS
--------------------
APPALACHIAN BASIN. Eastern American holds interests in 4,440 gross (2,756
------------------
net) wells in the Appalachian Basin and serves as operator of substantially all
of such wells in which it has a working interest. The Company's proved gas and
oil reserves attributable to its Appalachian Basin properties are estimated as
of June 30, 2000 at 152 Bcfe, of which approximately 97% was gas reserves and 3%
was oil reserves. For the fiscal year ended June 30, 2000, the Company's gas
production from its Appalachian Basin properties was approximately 7.3 net Bcf.
In the Appalachian Basin, the Company has interests in approximately 573,196
gross acres (448,663 net) of producing properties and an additional 79,060 gross
acres (49,367 net) of undeveloped properties located primarily in West Virginia,
Pennsylvania and Ohio. During fiscal 2000, the Company drilled 16 successful
gross wells (13.1 net) and recompleted 27 gross wells (26 net), which added 2.6
net Bcfe in reserves. The Company also acquired several existing partnership
interests during fiscal 2000. The acquired producing properties added
approximately 9 net Bcfe in reserves. The Company's drilling program for fiscal
year 2001, within this Basin, contemplates drilling 8 gross exploratory wells,
71 gross development wells and 27 gross recompletion wells.
WESTERN BASINS AND GULF COAST. Westech owns developed and undeveloped
---------------------------------
leasehold interests in approximately 573,000 gross acres (342,000 net) located
in the Rocky Mountain and Gulf Coast areas. This year, the Company drilled 14
exploratory wells in the Powder River and Williston Basins, with one commercial
success in the Powder River Basin. The fiscal year 2001 drilling program
includes two development wells in the Powder River Basin and four exploratory
wells on newly acquired acreage holdings in the Gulf Coast.
INTERNATIONAL. WENZ currently operates three offshore permits and six
-------------
onshore permits on the North Island of New Zealand, totaling 6,114,000 gross
acres (3,061,000 net). The Tuhara 1 well was re-entered on the East Coast and
is currently suspended until further drilling is undertaken with the Tuhara 2
well. A total of 600 square km of 3-D seismic was acquired and evaluated on the
East Coast of New Zealand. 3-D seismic totaling 43.2 square km was acquired and
evaluated on the West Coast permits. Technical evaluation also included
reprocessing of 750 km of offshore and 71 km of onshore 2-D data. During fiscal
year 2001, WENZ plans to drill four onshore exploratory wells, one onshore
appraisal well and three offshore wells. The Company's plans regarding the
funding for drilling the three offshore wells are incomplete at this time.
Drilling costs, net to the Company, are estimated at $10-$15 million. The
Company's options include funding the entire costs through internal or external
(borrowed) funds, farming out a portion or all of its interests, or terminating
the applicable government license.
The Company participated in two exploratory wells in the Cooper Basin,
Queensland, Australia, which were non-commercial. The contractual agreement
lead to a small working interest in another well that will generate short-term
revenue at the current higher oil prices.
OIL AND GAS RESERVES
-----------------------
The following information relating to estimated reserve quantities, reserve
values and discounted future net revenues is derived from, and qualified in its
entirety by reference to, the more complete reserve and revenue information and
assumptions included in the Company's Supplemental Oil and Gas Disclosures at
Item 8. The Company's estimates of proved reserve quantities of its properties
have been subject to review by Ryder Scott Company, independent petroleum
engineers. There are numerous uncertainties inherent in estimating quantities
of proved reserves and projecting future rates of production and timing of
development expenditures. The following reserve information represents
5
<PAGE>
estimates only and should not be construed as being exact. Future reserve
values are based on year-end prices except in those instances where the sale of
gas and oil is covered by contract terms providing for determinable escalation.
Operating costs, production and ad valorem taxes and future development costs
are based on current costs with no escalations.
The following table sets forth the Company's estimated proved and proved
developed reserves and the related estimated future value, as of June 30:
<TABLE>
<CAPTION>
2000 1999 1998
-------- -------- --------
<S> <C> <C> <C>
Net proved:
Gas (Mmcf) 157,490 148,587 152,780
Oil (Mbbls) 983 959 1,332
Total (Mmcfe) 163,388 154,341 160,772
Net proved developed:
Gas (Mmcf) 141,067 126,962 122,255
Oil (Mbbls) 738 714 735
Total (Mmcfe) 145,495 131,246 126,665
Estimated future net cash flows
before income taxes (in thousands) $427,414 $252,192 $261,798
Present Value of estimated future net cash
flows after income taxes (in thousands) (1) $124,871 $ 84,883 $ 74,913
<FN>
_______________
(1) Discounted using an annual discount rate of 10%.
</TABLE>
The following table sets forth the Company's estimated proved reserves and
the related estimated future value by region, as of June 30, 2000:
<TABLE>
<CAPTION>
Present Value
======================== Natural Gas
Amount Oil & NGLs Natural Gas Equivalent
Region (thousands) % (Mbbls) (Mmcf) (Mmcfe)
------------------ ------------ ----------- ------------ ----------- --------
<S> <C> <C> <C> <C> <C>
Appalachian Basin $ 117,264 93.9% 788 147,661 152,389
Rocky Mountains 1,937 1.6% 195 193 1,363
New Zealand 5,670 4.5% - 9,636 9,636
------------ ----------- ------------ ----------- --------
Total $ 124,871 100.0% 983 157,490 163,388
============ =========== ============ =========== ========
</TABLE>
PRODUCING WELLS
----------------
The following table sets forth certain information relating to productive
wells at June 30, 2000. Wells are classified as oil or gas according to their
predominant production stream.
6
<PAGE>
<TABLE>
<CAPTION>
Gross Wells Net Wells
========================= ===========================
Oil Gas Total Oil Gas Total
------- ------- ------- ------- ------- ---------
<S> <C> <C> <C> <C> <C> <C>
Appalachian Basin 17 4,423 4,440 5.4 2,750.6 2,756.0
Rocky Mountains 11 - 11 4.2 - 4.2
------- ------- ------- ------- ------- ---------
Total 28 4,423 4,451 9.6 2,750.6 2,760.2
======= ======= ======= ======= ======= =========
</TABLE>
ACREAGE
-------
The following table sets forth the developed and undeveloped gross and net
acreage held at June 30, 2000 (in thousands).
<TABLE>
<CAPTION>
Developed Undeveloped
Acreage Acreage
============ ================
Gross Net Gross Net
----- ----- ------- -------
<S> <C> <C> <C> <C>
Appalachian Basin 573.2 448.7 79.1 49.4
Rocky Mountains and Gulf Coast 0.1 0.1 572.8 341.6
New Zealand - - 6,114.0 3,061.0
----- ----- ------- -------
Total 573.3 448.8 6,765.9 3,452.0
===== ===== ======= =======
</TABLE>
The following table sets forth certain production data and average sales
prices attributable to the Company's properties for the years ended June 30:
<TABLE>
<CAPTION>
2000 1999 1998
------ ------ ------
<S> <C> <C> <C>
Production Data:
Oil (Mbbls) 113 133 125
Natural gas (Mmcf) 7,399 7,184 7,266
Natural gas equivalent (Mmcfe) 8,079 7,979 8,018
Average Sales Price:
Oil per Bbl $21.64 $10.95 $15.30
Natural gas per Mcf $ 2.81 $ 2.20 $ 2.42
</TABLE>
DRILLING ACTIVITIES
--------------------
The Company's gas and oil exploratory and developmental drilling activities
are as follows for the years ended June 30. The number of wells drilled refers
to the number of wells commenced at any time during the respective fiscal year.
A well is considered productive if it justifies the installation of permanent
equipment for the production of gas or oil.
7
<PAGE>
<TABLE>
<CAPTION>
2000 1999 1998
=========== =========== ===========
Gross Net Gross Net Gross Net
----- ---- ----- ---- ----- ----
<S> <C> <C> <C> <C> <C> <C>
Development:
Productive
Appalachian 15.0 12.6 19.0 15.0 24.0 17.4
Other - - 3.0 0.7 5.0 0.5
----- ---- ----- ---- ----- ----
Total 15.0 12.6 22.0 15.7 29.0 17.9
===== ==== ===== ==== ===== ====
Nonproductive
Appalachian - - 2.0 1.6 3.0 1.8
Other - - 3.0 1.3 1.0 0.2
----- ---- ----- ---- ----- ----
Total - - 5.0 2.9 4.0 2.0
===== ==== ===== ==== ===== ====
Exploratory:
Productive
Appalachian 1.0 0.5 8.0 3.8 6.0 2.6
Other 3.0 1.5 2.0 0.7 4.0 0.9
----- ---- ----- ---- ----- ----
Total 4.0 2.0 10.0 4.5 10.0 3.5
===== ==== ===== ==== ===== ====
Nonproductive
Appalachian - - 3.0 1.7 5.0 2.6
Other 15.0 8.3 7.0 3.2 12.0 4.2
----- ---- ----- ---- ----- ----
Total 15.0 8.3 10.0 4.9 17.0 6.8
===== ==== ===== ==== ===== ====
</TABLE>
COMPETITION
-----------
The Company encounters substantial competition in acquiring properties,
marketing oil and gas, securing equipment and personnel and operating its
properties. The competitors in acquisitions, development, exploration and
production include major oil companies, numerous independent oil and gas
companies, gas marketers, individual proprietors and others. Many of these
competitors have financial and other resources, which substantially exceed those
of the Company and have been engaged in the energy business for a much longer
time than the Company. Therefore, competitors may be able to pay more for
desirable leases and to evaluate, bid for and purchase a greater number of
properties or prospects than the financial or personnel resources of the Company
will permit.
Natural gas competes with other forms of energy available to customers,
primarily based on price. These alternate forms of energy include electricity,
coal and fuel oils. Changes in the availability or price of natural gas or
other forms of energy, as well as business conditions, conservation,
legislation, regulations and the ability to convert to alternate fuels and other
forms of energy may affect the demand for natural gas.
REGULATIONS AFFECTING OPERATIONS
----------------------------------
The Company's operations are affected by extensive regulation pursuant to
various federal, state and local laws and regulations relating to the
exploration for and development, production, gathering, marketing,
transportation and storage of oil and gas. These regulations, among other
things, can affect the rate of oil and gas production. The Company's operations
are subject to numerous laws and regulations governing plugging and abandonment,
the discharge of materials into the environment or otherwise relating to
environmental protection.
8
<PAGE>
These laws and regulations require the acquisition of a permit before drilling
commences, restricts the types, quantities and concentration of various
substances that can be released into the environment in connection with drilling
activities on certain lands lying within wilderness, wetlands and other
protected areas, and impose substantial liabilities for pollution which might
result from the Company's operations.
GAS AGGREGATION AND MARKETING
---------------------------------
The Company, primarily through the wholly owned subsidiary of Eastern
American, Eastern Marketing Corporation ("Eastern Marketing"), aggregates
natural gas through the purchase of production from properties in the
Appalachian Basin in which the Company has an interest, the purchase of gas
delivered through the Company's gathering pipelines located in the Appalachian
Basin, the purchase of gas from smaller Appalachian Producers that are not large
enough to have marketing departments, the purchase of gas produced in the
Southwestern areas of the United States pursuant to contractual arrangements and
the purchase of gas in the spot market. The Company sells gas to local gas
distribution companies, industrial end users located in the Northeast, other gas
marketing entities and into the spot market for gas delivered into interstate
pipelines. The Company has historically attempted to balance its gas sales mix
with approximately one-third of its total gas sales being made under long term
contracts (contracts with terms of five years or more), one-third being sold
under intermediate term contracts (contracts with terms of one to five years),
and one-third being sold under short term contracts (contracts with terms of
less than one year) or on a spot market basis. The demand for long term
contracts has decreased substantially and no new long term contracts were
entered into in fiscal year 2000. Volumes that became available from expired
long term contracts were sold under intermediate and short term contracts.
The Company owns and operates approximately 2,100 miles of gathering lines
and intrastate pipelines that are used in connection with its gas aggregation
and marketing activities. In addition, the Company has entered into contracts
with interstate and intrastate pipeline companies that provide it with rights to
transport specified volumes of natural gas. During the fiscal year ended June
30, 2000, the Company aggregated and sold an average of 95.7 Mmcf of gas per
day, of which 39.7 Mmcf per day represented sales of gas produced from wells
operated by the Company. This represents a decrease compared to fiscal year
1999, during which the Company aggregated and sold an average of 129.5 Mmcf of
gas per day.
GAS SALES AND PURCHASE CONTRACTS
-------------------------------------
The Company satisfied its obligations under all gas sales contracts (23.0
Bcf in fiscal year 2000) through gas production attributable to its own
interests in oil and gas properties and through production attributable to third
party interests in oil and gas properties (14.1 Bcf in fiscal 2000), and from
natural gas aggregated by the Company pursuant to its aggregation and marketing
activities from third parties (8.9 Bcf in fiscal 2000).
Eastern American has a gas sales contract with Hope Gas, Inc. ("Hope"), a
subsidiary of Dominion Energy, which requires Eastern American to sell up to
4,000 but not less than 1,500 Mmbtu per day during the winter months of November
through March to Hope through December 31, 2001. Pricing under the contract
requires Hope to pay Eastern American a ten cent premium above the posted
Appalachian Index.
9
<PAGE>
In March 1993, Eastern Marketing entered into a gas purchase contract with
the Eastern American Natural Gas Trust (the "Royalty Trust") to purchase all gas
production attributable to the Royalty Trust until its termination in May 2013.
The purchase price under this gas purchase contract through December 1999 was
based in part on an escalating fixed price component of $3.39 per Mcf in
calendar year 1999 and $3.56 per Mcf in calendar year 2000 and in part on a
Henry Hub based variable price component, which fluctuated with certain spot
market prices, provided that the purchase price during such period was not less
than a specified floor price of $2.84 per Mcf in calendar year 1999 and $3.09
per Mcf in calendar year 2000. Beginning in January 2000, the purchase price
under this gas purchase contract is determined solely by reference to the
variable price component without regard to any minimum purchase price. See Note
13, for further discussion.
REGULATIONS AFFECTING MARKETING AND TRANSPORTATION
------------------------------------------------------
As a marketer of natural gas, the Company depends on the transportation
and storage services offered by various interstate and intrastate pipeline
companies for the delivery and sale of its own gas supplies as well as those it
processes and/or markets for others. Both the performance of transportation and
storage services by interstate pipelines and the rates charged for such services
are subject to the jurisdiction of the FERC. In addition, the performance of
transportation and storage services by intrastate pipelines and the rates
charged for such services are subject to the jurisdiction of state regulatory
agencies.
EMPLOYEES
---------
As of June 30, 2000, the Company had approximately 215 full-time employees.
None of the employees were covered by a collective bargaining agreement.
Management believes that its relationship with its employees is good.
ITEM 2. PROPERTIES
----------------------
See Item 1. Business, for information concerning the general location and
characteristics of the important physical properties and assets of the Company
and information regarding production, reserves, development and interests in oil
and gas producing properties of the Company.
ITEM 3. LEGAL PROCEEDINGS
-----------------------------
The Company is involved in various legal actions and claims arising in the
ordinary course of business. While the outcome of these lawsuits against the
Company cannot be predicted with certainty, management does not expect these
matters to have a material adverse effect on the Company's operations or
financial position.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
---------------------------------------------------------------
One matter was submitted to a vote of security holders during the fourth
quarter of fiscal year 2000 by Eastern Systems Corporation, a subsidiary of the
Company, concerning the sale of all the outstanding stock of Mountaineer Gas
Company to Allegheny Energy, Inc., dated June 13, 2000.
10
<PAGE>
PART II
-------
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK
----------------------------------------------------
AND RELATED STOCKHOLDER MATTERS
-------------------------------
The Company's common stock is not traded in a public market. As of
September 1, 2000, the Company had 31 holders of record of its common stock.
The Company declared dividends in fiscal years 2000, 1999 and 1998 of $0,
$644,505 and $1,131,000, respectively.
ITEM 6. SELECTED FINANCIAL DATA
-----------------------------------
<TABLE>
<CAPTION>
(Dollars in thousands, except per share items)
Year Ended June 30,
-----------------------------------------------------
2000 1999 1998 1997 1996
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
Operating revenue $101,919 $113,500 $193,459 $189,070 $180,828
Loss from continuing operations (26,508) (27,099) (3,773) (4,086) (3,324)
Loss from continuing operations
Per common share, basic and diluted (40.11) (40.27) (5.67) (5.94) (4.75)
Total assets 265,691 286,077 290,541 302,446 273,627
Long term debt 212,575 219,886 201,507 200,089 159,647
Dividends declared per common share $ - $ 0.95 $ 1.70 $ 1.50 $ 2.10
</TABLE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF
--------------------------------------------------------------
OPERATIONS AND FINANCIAL CONDITION
----------------------------------
The following should be read in conjunction with the Company's Financial
Statements and notes (including the segment information) at Item 8 and the
Selected Financial Data at Item 6.
This discussion and analysis of financial condition and results of
operations, and other sections of this Form 10-K, contain forward-looking
statements that are based on management's beliefs, assumptions, current
expectations, estimates and projections about the oil and gas industry, the
economy and about the Company itself. Words such as "anticipates," believes,"
"estimates," "expects," "forecasts," "intends," "is likely," "plans,"
"predicts," "projects," variations of such words and similar expressions are
intended to identify such forward-looking statements. These statements are not
guarantees of future performance and involve certain risks, uncertainties and
assumptions that are difficult to predict with regard to timing, extent,
likelihood and degree of occurrence. Therefore, actual results and outcomes may
materially differ from what may be expressed or forecasted in such
forward-looking statements. Furthermore, the Company undertakes no obligation
to update, amend or clarify forward-looking statements, whether as a result of
new information, future events or otherwise.
Important factors that could cause actual results to differ materially from
the forward-looking statements include, but are not limited to, weather
conditions, changes in production volumes, worldwide demand and commodity prices
for petroleum natural resources, the timing and extent of the Company's success
in discovering, acquiring, developing and producing oil and natural gas
reserves, risks incident to the drilling and operation of oil and natural gas
wells, future production and development costs, the effect of existing and
future laws, governmental regulations and the political and economic climate of
the United States and New Zealand, the effect of hedging activities, and
conditions in the capital markets.
11
<PAGE>
COMPARISON OF RESULTS OF OPERATIONS FOR THE YEARS ENDED JUNE 30, 2000 AND 1999
--------------------------------------------------------------------------------
The Company recorded a net loss from continuing operations of $26.5 million
for the year ended June 30, 2000 compared to a net loss of $27.1 million for the
same period in 1999. The increase in income of $0.6 million is attributed to an
$11.6 million decrease in revenue, a $5.3 million decrease in operating
expenses, a $10.9 million decrease in impairment and exploratory costs, a $2.2
million increase to interest expense, a $0.5 million decrease in other income
and a $1.3 million decrease in income tax benefits.
OPERATING MARGINS. Operating Margins (defined as revenue less operating
------------------
costs, taxes other than income taxes and direct general and administrative
expense) for the Company's operating subsidiaries totaled $7.8 million for the
current year compared to $13.4 million for the prior period. The Company's Oil
and Gas Operating Margin (defined as oil and gas sales and well operations and
service revenues less field operating expenses, taxes other than income and
direct general and administrative) totaled $10.7 million versus $9.2 million for
the prior year. The Company's Marketing and Pipeline Operating Margin (defined
as gas marketing and pipeline sales less gas marketing and pipeline cost of
sales) totaled a loss of $2.9 million for the current period versus income of
$4.1 million for the prior period.
REVENUES. Total revenues decreased $11.6 million or 10.2% during the
--------
periods. The decrease was due to an 18.4% decrease in gas marketing and
pipeline sales and a 9.9% decrease in well and service operations, which was
partially offset by a 30.5% increase in oil and gas sales.
Revenues from gas marketing decreased $18.6 million and pipeline sales
increased $2.3 million, for a net decrease of $16.3 million from $88.5 million,
during the period ended June 30, 1999, to $72.2 million in the period ended June
30, 2000. The decrease in revenue is primarily attributable to a 35.3% decline
in marketed volumes from 37.2 Mmbtu at June 30, 1999 to 24.1 Mmbtu at June 30,
2000, which was partially offset by a 26.1% increase in the average sales price
per Mmbtu from $2.32 to $2.92 for the years ended June 30, 1999 and 2000,
respectively. The decrease in volumes is primarily a result of the termination
and non-renewal of marketing contracts as they expire.
Revenues from well and service operations decreased $0.6 million from $6.5
million during the period ended June 30, 1999 to $5.9 million in the period
ended June 30, 2000. The decrease in revenue is primarily attributable to the
acquisition of outside owner interests in Company wells through the acquisition
of partnership interests.
Revenues from oil and gas sales increased $5.6 million from $18.3 million
for the period ended June 30, 1999 to $23.9 million for the period ended June
30, 2000. The increase in revenue is primarily attributable to a 97.5% increase
in the average oil sales price from $10.95 to $21.64 per Bbl and a 28.0%
increase in the average gas sales price from $2.20 to $2.81 per Mcf between June
30, 1999 and June 30, 2000. Lessening the effect of the higher prices on oil
and gas sales is a loss on related hedges of $0.8 million for the year ended
June 30, 2000 compared to a loss of $0.1 for the year ended June 30, 1999.
Production volumes were comparable for the two periods.
COSTS AND EXPENSES. The Company's costs and expenses decreased $5.3
--------------------
million or 4.6% during this period primarily as a result of an 11.1% decrease in
gas marketing and pipeline costs, which was partially offset by a 32.5% increase
in general and administrative expenses. Field and lease operating expenses,
taxes other than income and depreciation, depletion and amortization expenses
remained relatively constant between the periods.
12
<PAGE>
The $9.4 million decrease to gas marketing costs from $84.4 million during
the period ended June 30, 1999 to $75.0 million in the period ended June 30,
2000, is comprised of a $15.6 million decrease to gas marketing costs, a $1.3
million increase to pipeline costs and a $4.9 million gas purchase commitment
charge (See Note 13). The overall decrease to gas marketing costs is primarily
the result of a 31.9% decline in purchased gas volumes from 39.8 Mmbtu to 27.1
Mmbtu from June 30, 1999 and June 30, 2000, which was partially mitigated by a
25.2% increase in the average price paid for gas purchased, from $2.26 per Mmbtu
to $2.83 per Mmbtu between the respective periods.
General and administrative expense increased $3.3 million, primarily as a
result of impairing certain notes receivable issued by a subsidiary of Eastern
American, relating to a state tax incentive program, which had been deemed
uncollectible. In addition, there were increased profit sharing expenses and
increased overhead at the corporate level.
Impairment and exploratory expenses decreased $10.9 million primarily due
to the leasehold and well costs that were written off in fiscal 1999. The
increase in fiscal year 1999 was due to programmed seismic costs and New Zealand
dry holes.
INTEREST EXPENSE. Interest expense increased $2.2 million, primarily due
-----------------
to higher interest rates throughout fiscal 2000.
OTHER (INCOME) EXPENSE. Other income decreased $0.5 million primarily due
-----------------------
to the recognition of gains on the sale of property during fiscal 1999.
PROVISION FOR INCOME TAXES. The benefit for income taxes decreased $1.3
-----------------------------
million primarily because of the increased income in the current year.
DISPOSAL OF UTILITY OPERATIONS. Net income for the year ended June 30,
---------------------------------
2000 was $8.1 million compared to $12.2 million the previous year, a decrease of
approximately $4.1 million. Revenues for the current year increased $6.8
million compared to the prior year. Utility revenues increased $10.7 million,
primarily resulting from additional revenues provided as a result of the
acquisition of the West Virginia assets of Shenandoah Gas Company in July 1999.
One other significant change in revenue resulted from one customer changing from
sales to transportation service, which resulted in a decrease of $4.9 million,
which had no significant impact on operating income because it was offset by
reduced gas marketing and pipeline costs. Operating expenses increased
approximately $12.5 million during the current period compared to the prior
year. This increase resulted from increased gas costs of $10.0 million,
partially offset by decreased gas marketing and pipeline costs of $4.2 million
(see above), and increases in operations and maintenance and general and
administrative costs of $5.1 million. The increase in gas costs resulted
primarily from the additional costs associated with Shenandoah customers
amounting to $6.8 million and the impact of the gas supply management agreement
amounting to approximately $4.4 million. Operations and maintenance and general
and administrative costs increased primarily due to increased profit sharing
expenses and increased labor associated costs. Depreciation expense increased
approximately $1.0 million, resulting primarily from the addition of the assets
of Shenandoah acquired on July 1, 1999. Interest expense increased
approximately $1.7 million, principally the result of an additional $40 million
in long term debt, which was issued in November 1999. Income taxes decreased
$4.2 million, due to lower income before taxes of $20.1 million in 1999 to $11.8
million in the current year.
13
<PAGE>
COMPARISON OF RESULTS OF OPERATIONS FOR THE YEARS ENDED JUNE 30, 1999 AND 1998
--------------------------------------------------------------------------------
The Company recorded a net loss from continuing operations of $27.1 million
for the year ended June 30, 1999 compared to a net loss of $3.8 million for the
same period in 1998. The decrease in income of $23.3 million is attributed to
an $80.0 million decrease in revenue, a $30.4 million decrease in operating
expenses, an $11.0 million increase in impairment and exploratory costs, a $3.8
million increase in other income and an $11.1 million increase in income tax
benefits.
OPERATING MARGINS. Operating Margins (defined as revenue less operating
------------------
costs, taxes other than income taxes and direct general and administrative
expense) for the Company's operating subsidiaries totaled $13.3 million for the
current year compared to $9.0 million for the prior period. The Company's Oil
and Gas Operating Margin (defined as oil and gas sales and well operations and
service revenues less field operating expenses, taxes other than income and
direct general and administrative) totaled $9.2 million versus $11.9 million for
the prior year. The Company's Marketing and Pipeline Operating Margin (defined
as gas marketing and pipeline sales less gas marketing and pipeline cost of
sales) totaled $4.1 million for the current period versus a loss of $2.9 million
for the prior period.
REVENUES. Total revenues decreased $80.0 million or 41.3% during the
--------
periods. The decrease was due to a 34.6% decrease in gas marketing and pipeline
sales, an 11.7% decrease in oil and gas sales and a 99.4% decrease in other
operating revenue. Well and service operating revenue remained relatively
constant between the periods.
Revenues from gas marketing and pipeline sales decreased $46.9 million from
$135.3 million during the period ended June 30, 1998 to $88.5 million in the
period ended June 30, 1999. The decrease in revenue is primarily attributable
to a 12% decrease in the average unit price from $2.63 to $2.32 and a 27%
decline in marketed volumes from 50.7 million Mmbtu at June 30, 1998 to 37.2
million Mmbtu at June 30, 1999. The decrease in volumes is primarily a result
of the termination of two contracts that accounted for 9.5 Mmbtu and reduced
volumes associated with trading activities. See other operating revenue,
discussed below.
Revenues from oil and gas sales decreased $2.4 million from $20.7 million
for the period ended June 30, 1998 to $18.3 million for the period ended June
30, 1999. The decrease in revenue is primarily attributable to a 29.7% decrease
in the average oil sales price from $15.30 to $10.95 per Bbl and a 9.1% decrease
in the average gas sales price from $2.42 to $2.20 per Mcf between June 30, 1998
and June 30, 1999. The price decline was partially offset by production
increasing 6.2% for oil and 1.2% for gas.
Other operating revenues decreased $30.4 million from $30.6 million to $0.2
million between the periods. This was primarily because 1998 included revenue
from the termination of a long-term gas delivery contract. See Note 15 to the
Consolidated Financial Statements for discussion.
COSTS AND EXPENSES. The Company's costs and expenses decreased $52.4
--------------------
million or 31.3% during this period primarily as the result of a 38.9% decrease
in gas marketing and pipeline costs, which was partially offset by a 12.0%
increase in general and administrative expenses. Field and lease operating
expenses, taxes other than income and depreciation, depletion and amortization
costs remained relatively constant between the periods.
The $53.8 million decrease in gas marketing and pipeline costs is primarily
the result of a 27% decline in purchased gas volumes from 51.1 Mmbtu to 37.6
Mmbtu from June 30, 1998 and June 30, 1999. Contributing to the decline in
costs was a 15% decrease in the average price paid for gas purchased, from $2.67
per Mmbtu to $2.26 per Mmbtu between the respective periods. Additionally,
approximately $2.4 million of purchased gas costs were charged against a reserve
for losses on future gas purchases, which was primarily related to the contract
settlement. See Note 15 to the Consolidated Financial Statements for
discussion.
14
<PAGE>
General and administrative expense increased $1.1 million as a result of
increased overhead at the corporate level.
Impairment and exploratory expenses increased $11.0 million primarily due
to the current year cost of drilling exploratory dry holes of $5.9 million in
New Zealand and $1.5 million domestically. In addition, approximately $2.2
million of leasehold and well in progress costs were written off late in fiscal
1999.
INTEREST EXPENSE. Interest expense remained relatively constant between
-----------------
the periods.
OTHER (INCOME) EXPENSE. Other income increased $3.8 million primarily due
-----------------------
to the recognition of gains on the sale of property during fiscal 1999, compared
to losses in the prior year. In addition, during fiscal 1998 a reserve of $1.1
million was established against a note receivable.
PROVISION FOR INCOME TAXES. The provision for income taxes changed $11.1
----------------------------
million primarily because of the increased current year losses.
DISPOSAL OF UTILITY OPERATIONS. Net income for the year ended June 30,
---------------------------------
1999 was $12.2 million compared to $6.8 million the previous year, an increase
of approximately $5.4 million. Operating revenues increased approximately $1.2
million during the current year, primarily due to increased sales rates in
accordance with Mountaineer's new rate agreement, which became effective
November 1, 1998. Operating expenses decreased $8.1 million during the current
year, primarily driven by decreased gas purchase costs as a result of the
initial effect of the implementation of Mountaineer's gas supply management
agreement, which went into effect on November 1, 1998. Slightly offsetting this
decrease were increased labor associated costs and other miscellaneous costs of
$1.0 million. Depreciation expense increased primarily due to additions to gas
plant in service and the elimination of a negative acquisition adjustment, which
reduced expense by approximately $0.5 million in the prior year period. Income
tax expense increased $3.9 million, due to higher income before taxes of $20.1
million during the current year compared to $10.8 million the previous year.
LIQUIDITY AND CAPITAL RESOURCES
----------------------------------
The Company's financial condition declined during the twelve month period
ended June 30, 2000 ("current period"). The ratio of current assets to current
liabilities, excluding "net utility assets held for sale" of $56.8 million for
the current period and $70.1 million for the period ended June 30, 1999 ("prior
period"), decreased from 1.04:1 at June 30, 1999 to 0.75:1 at June 30, 2000.
Cash and cash equivalents decreased from $12.2 million to $3.3 million.
The Company's net cash used by operating activities from continuing
operations decreased from $24.1 million for the prior period to $5.0 million for
the current period. The primary net uses of cash from continuing operations for
the current period versus the prior period were the net losses from continuing
operations of $(26.5) million and $(27.1) million. Non-cash charge adjustments
were inclusive of depreciation, depletion and amortization of $12.5 million and
$12.0 million; exploration and impairment of $6.0 million and $16.8 million;
provision for losses on notes receivable of $1.5 million and $0.4 million.
These non-cash additions were offset by reduction of deferred revenue of $(2.2)
million versus $(2.3) million and deferred taxes of $(11.1) million versus
$(12.5) million. Net cash used by operating activities from continuing
activities was also impacted by net collections in accounts receivable of $0.4
million for the current period; decreases in gas in storage and prepaids of
$(0.2) million versus $1.7 million for the prior period; an increase in accounts
payable $(6.3) million for the prior period; increases of $0.9 million and
$(0.3) million in funds held for distribution; and increases in other accrued
expenses (mainly income taxes) of $8.8 million and $(11.6) million for the
periods, respectively.
15
<PAGE>
The Company incurred a net cash outflow of $19.2 million from investing
activities from continuing activities for the current period versus a cash
outflow of $21.7 million in the prior period. The reduction in capital
expenditure activities of $5.9 million was related primarily to reduced oil and
gas drilling activities. An acquisition of miscellaneous oil and gas limited
partnership interests for $3.0 million dollars occurred during the current
period. The use of cash for investing activities was offset by cash received
from sales of non-core assets by $0.4 million in the current period and $3.4
million in the prior period.
The Company's financing activities from continuing activities in the
current period resulted in the Company's long term debt balance being reduced by
the net payment of $12.8 million. The Company's revolving credit facility was
paid in full on August 18, 2000 and the credit agreement was terminated (see
Note 5). During the current period, $2.0 million of short-term debt was
incurred for the acquisition of an 85% interest in 68.5 net wells with reserves
of 5.1 Bcf at a cost of $3.0 million. In addition, during the current period
the Company purchased $0.4 million of treasury stock in discretionary
transactions. The financing activity net cash outflow of $1.1 million for the
current period was reduced primarily from the receipt of $10 million in the form
of a cash prepayment under a gas sale agreement (see Note 3). Under this
agreement, the Company will be obligated to begin delivery of certain volumes of
gas on July 1, 2001 or repay the monies advanced. The primary sources of cash
from financing activities in the prior period were long-term borrowings of $27.5
million offset by principal repayments on long-term debt of $3.1 million,
treasury stock purchases of $2.2 million and dividend payments of $1.0 million.
At June 30, 2000, the Company's principal sources of liquidity consisted of
$3.3 million of cash, with no amounts available under short-term credit
facilities currently in place. On August 18, 2000, the Company paid in full the
$19.8 million then outstanding under its revolving line of credit facility. The
Company also gave notice of termination of the revolving credit facility,
effective August 18, 2000. Presently, the Company has not formally commenced
efforts to seek a replacement for this credit facility. At June 30, 2000 the
Company had $2 million drawn, the maximum permitted, under an additional line of
credit facility.
On August 18, 2000, the Company consummated the sale of Mountaineer and
Subsidiary and received pre-tax proceeds of approximately $222.7 million (see
Note 3). Pursuant to the terms of the Company's $200 million Senior
Subordinated Notes (the "Notes"), attached as Exhibit 4.3, the Company has the
option within 360 days of receipt of the net proceeds from the sale of the stock
of Mountaineer to apply such proceeds to (a) reduce debt senior to or pari passu
with the Notes (provided that in connection with the reduction of pari passu
debt, a pro rata portion of the Notes is redeemed); (b) acquire a controlling
interest in another business engaged in either natural gas distribution or the
exploration, development or operation of oil, gas or other hydrocarbon
properties (an "Energy Business"); (c) make capital expenditures in respect to
the Company's or its restricted subsidiaries' Energy Business; (d) purchase
long term assets that are used or useful in the Energy Business; or (e)
repurchase the Notes. If the Company elects not to apply all of the net
proceeds in accordance with one of the above options within 360 days of receipt
of such proceeds, then with respect to those net proceeds which were not applied
to one of the above options, the Company must make an offer to the holders of
the Notes, (and holders of the pari passu debt, to the extent required by the
terms of the pari passu debt) to repurchase the maximum principal amount of the
Notes and any pari passu debt at an offer price in cash equal to 100% of the
principal amount thereof, plus accrued and unpaid interest thereon to the date
of the purchase.
16
<PAGE>
It is the intention of the Company to comply with reinvestment requirements
of the Notes and seek to reinvest such proceeds into Energy Business assets. A
component of the Company's reinvestment strategy will be to expand its
exploration and development activities, both domestically and internationally.
For fiscal year 2001, the Company plans to invest approximately $42.4 million in
capital projects. The fiscal year 2001 capital expenditure program contemplates
spending approximately $11.7 million on 27 gross (25 net) recompletions and 73
gross (60.3 net) development wells as well as approximately $2.0 million on
acquisitions of producing properties primarily in the Appalachian Basin. In
addition, the Company's fiscal year 2001 capital spending program contemplates
spending approximately $15.9 million (including estimated completion costs) on
exploratory drilling projects. These projects include funding $12.1 million on
domestic exploration drilling opportunities and $3.8 million on international
exploration drilling opportunities. This funding program assumes drilling 14
gross (5.9 net) domestic exploration wells and 8 gross (4.6 net) international
exploration wells. Other capital projects include $5.1 million for seismic
studies and for leasehold acquisitions plus $7.7 million for infrastructure
projects.
In addition to the Company's exploration and development drilling
activities associated with this reinvestment program, the Company will seek to
satisfy the reinvestment requirement by engaging in acquisitions of utility
assets or oil and natural gas reserves and properties. There can be no
assurance that the Company will be able to acquire exploration or development
drilling opportunities or to identify acquisition candidates in the required 360
day time period. Further, there can be no assurance that the drilling
activities associated with the reinvestment program will achieve commercial
success or that any future acquisitions made by the Company will achieve desired
profitability objectives.
Other than the reinvestment program described above, the timing of the
Company's capital expenditures is mostly discretionary with no material capital
expenditure commitments. However, the Company has designated certain projects
as non-deferrable commitments incurred in the normal course of business. These
include certain drilling obligations, primarily in New Zealand and Texas, that
range from $5.9 million to $8.1 million at June 30, 2000; the annual paydown
requirement, under the Company's line of credit, which has $2.0 million
outstanding at June 30, 2000; and the satisfaction of the obligations resulting
from the draw down of $10.0 million under the gas purchase and sale agreement
(see Note 3). Consequently, the Company has a significant degree of flexibility
to adjust its level of its capital expenditures as circumstances warrant.
The Company's cash requirements will fluctuate based on timing and the
extent of the interplay of the factors discussed above. Moreover, management
anticipates that although projected earnings from continuing operations before
interest charges, taxes, depreciation, depletion and amortization, and
impairment and exploratory costs ("EBITDAX") for fiscal year 2001 will increase
to $25.4 million from $4.2 million for the current period, such results will not
be sufficient to fully fund fiscal year 2001 projected interest charges of $20.1
million and fund the Company's fiscal year 2001 capital expenditures program of
$42.4 million. Based on such estimates, the Company may utilize a certain
portion of the proceeds from the sale of Mountaineer to make capital
expenditures, subject to limitations on such usage under the Notes, if any, and
may seek to raise additional capital or incur permitted indebtedness. The
availability and attractiveness of such sources of financing will depend upon a
number of factors, some of which will relate to the financial condition and
performance of the Company, and some of which will be beyond the Company's
control, such as prevailing interest rates, oil and gas prices, weather
patterns, credit agency rating reports and other market conditions. The
Company's liquidity is directly affected by such factors and the Company's cash
requirements will fluctuate based on the timing and the extent of the interplay
of these factors. However, management believes that cash generated from
continuing oil and gas operations, the use of net proceeds from the sale of
Mountaineer (as permitted under provisions of the related debt agreements),
together with the liquidity provided by existing cash balances, permitted
borrowings and by investments in new "Energy Business" assets, if any, will be
sufficient to satisfy commitments for capital expenditures, debt service
obligations, working capital needs and other cash requirements for the next
year.
17
<PAGE>
The Company believes that its existing capital resources, its mitigating
management efforts, and its expected fiscal year 2001 results of operations and
cash flows from operating activities will be sufficient for the Company to
remain in compliance with the requirements of its Notes. However, since future
results of operations, cash flow from operating activities, debt service
capability, and levels and availability of capital resources and continuing
liquidity are dependent on future weather patterns, maintaining current levels
of oil and gas commodity sales prices and production volume levels, future
exploration and development drilling success and successful acquisition
transactions, no assurance can be given that the Company will not continue to
report substantial net losses from continuing operations or that debt service or
debt covenant violations will not occur. In such instances, the Company may
elect to increase permitted borrowing levels (see discussion above), restructure
debt agreements (including debt agreements with additional lenders), sell core
and non-core assets, defer discretionary capital expenditures, curtail certain
domestic and international oil and gas programs or take other actions necessary
to mitigate liquidity short-falls and debt agreement violations or acquire new
or additional capital resources, although no assurances can be given that such
actions will be successful.
RECENT ACCOUNTING PRONOUNCEMENTS
----------------------------------
As of July 1, 2000, the Company adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities" as amended by SFAS No. 137 and
No. 138. SFAS No. 133 establishes accounting and reporting standards for
derivative instruments, including certain derivative instruments embedded in
other contracts, and hedging activities. It requires the recognition of all
derivative instruments as assets or liabilities in the Company's balance sheet
and measurement of those instruments at fair value. The accounting treatment of
changes in fair value is dependent upon whether or not a derivative instrument
is designated as a hedge and if so, the type of hedge. For derivatives
designated as cash flow hedges, changes in fair value are recognized in other
comprehensive income until the hedged item is recognized in earnings.
The Company periodically hedges a portion of its oil and gas production
through futures and swap agreements. The purpose of the hedges is to provide a
measure of stability in the volatile environment of oil and gas prices and to
manage its exposure to commodity price risk under existing sales commitments.
All of the Company's price swap agreements in place at June 30, 2000 will be
designated as cash flow hedges. Adoption of SFAS No. 133 on July 1, 2000,
resulted in recording $3.4 million of decline in fair value to accumulated other
comprehensive income, consisting of $3.8 million to short term derivative
liabilities, $0.4 million to long term derivative liabilities and $0.8 million
to short term derivative assets.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES
-----------------------------------------------------
ABOUT MARKET RISK
-----------------
INTEREST RATE RISK
---------------------
Interest rate risk is attributable to the Company's debt. The Company
utilizes United States dollar denominated borrowings to fund working capital and
investment needs. There is inherent rollover risk for borrowings as they mature
and are renewed at current market rates. The extent of this risk is not
predictable because of the variability of future interest rates and the
Company's future financing needs. The Company has not attempted to hedge the
interest rate risk associated with its floating rate debt of which $13.7 million
was outstanding at year end. If interest rates changed by 1%, it would have an
impact of approximately $0.14 million. The Company has fixed interest rate debt
of $200.0 million, representing 93.1% of the total debt.
18
<PAGE>
COMMODITY RISK
----------------
The Company's operations, as described in detail at Item 1 Business,
consists primarily of exploring for, producing, aggregating and selling natural
gas and oil. The Company attempts to mitigate its commodity price risk by
entering into a mix of short, medium and long-term supply contracts. Contracts
to deliver gas at pre-established prices mitigate the risk to the Company of
falling prices but at the same time limit the Company's ability to benefit from
the effects of rising prices. The Company occasionally uses derivative
instruments to hedge its commodity price risk. Notwithstanding the above, the
Company's future cash flows from gas and oil production are exposed to
significant volatility as commodity prices change.
The Company periodically enters into hedging activities on a portion of its
projected natural gas production through a variety of financial and physical
arrangements intended to support natural gas prices at targeted levels and to
manage its exposure to price fluctuations. The Company may use futures
contracts, swaps, options and fixed price physical contracts to hedge its
commodity prices. Realized gains and losses from the Company's price risk
management activities are recognized in oil and gas sales when the associated
production occurs. The Company does not hold or issue derivative instruments for
trading purposes. The Company has elected to enter into swap transactions,
covering approximately half of its Appalachian natural gas.
* * * * *
19
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
-------------------------------------------------------
INDEPENDENT AUDITORS' REPORT
------------------------------
To the Stockholders and Board of Directors of Energy Corporation of America:
We have audited the accompanying consolidated balance sheets of Energy
Corporation of America and Subsidiaries as of June 30, 2000 and 1999, and the
related consolidated statements of operations, stockholders' equity (deficit),
and cash flows for each of the three years in the period ended June 30, 2000.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Energy Corporation of America and
Subsidiaries as of June 30, 2000 and 1999, and the results of their operations
and their cash flows for each of the three years in the period ended June 30,
2000 in conformity with accounting principles generally accepted in the United
States of America.
DELOITTE & TOUCHE LLP
Denver, Colorado
September 27, 2000
20
<PAGE>
<TABLE>
<CAPTION>
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF JUNE 30
(AMOUNTS IN THOUSANDS)
===================================================================================
ASSETS 2000 1999
------------ ---------
<S> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents $ 3,310 $ 12,163
------------ ---------
Accounts receivable:
Gas marketing and pipeline 9,249 9,271
Oil and gas sales 1,081 870
Other 4,600 5,209
------------ ---------
14,930 15,350
Less allowance for doubtful accounts (463) (429)
------------ ---------
14,467 14,921
Gas in storage, at average cost 765 357
Income taxes receivable 2,502 3,580
Deferred income tax asset 191
Net utility assets held for sale 56,795 70,139
Prepaid and other current assets 1,921 2,084
------------ ---------
Total current assets 79,760 103,435
NET PROPERTY, PLANT AND EQUIPMENT (Note 2) 160,162 158,442
------------ ---------
OTHER ASSETS:
Deferred financing costs, less accumulated
amortization of $2,446 and $1,647 5,210 6,009
Notes receivable, less allowance for doubtful accounts
of $0 and $440 1,531
Notes receivable - related party 1,519 1,853
Deferred income tax asset 4,405 292
Other 14,635 14,515
------------ ---------
Total other assets 25,769 24,200
------------ ---------
TOTAL $ 265,691 $286,077
============ =========
See notes to consolidated financial statements. (Continued)
</TABLE>
21
<PAGE>
<TABLE>
<CAPTION>
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF JUNE 30
(AMOUNTS IN THOUSANDS)
===================================================================================
LIABILITIES AND STOCKHOLDERSEQUITY (DEFICIT) 2000 1999
--------- ---------
<S> <C> <C>
CURRENT LIABILITIES:
Accounts payable and accrued expenses $ 14,877 $ 15,471
Current portion of long-term debt 1,086 6,618
Short-term debt 2,000
Funds held for future distribution 6,280 5,378
Accrued taxes, other than income 5,079 4,500
Deferred income tax liability 329
Other current liabilities 1,131
--------- ---------
Total current liabilities 30,782 31,967
LONG-TERM OBLIGATIONS
Long-term debt 212,575 219,886
Gas delivery obligation and deferred trust revenue 15,443 13,839
Deferred income tax liability 4,877
Other long-term obligations 11,014 1,031
--------- ---------
Total liabilities 269,814 271,600
--------- ---------
COMMITMENTS AND CONTINGENCIES (Note 13)
STOCKHOLDERS' EQUITY (DEFICIT):
Common stock, par value $1.00; 2,000,000 shares authorized;
718,000 and 721,000 shares issued 718 721
Class A non-voting common stock, no par value; 100,000
shares authorized; 26,000 shares issued 2,940 2,940
Additional paid-in capital 4,615 4,656
Retained earnings (deficit) (4,833) 13,598
Treasury stock and notes receivable arising from
issuance of common stock (7,429) (7,261)
Accumulated other comprehensive loss (134) (177)
--------- ---------
Total stockholders' equity (deficit) (4,123) 14,477
--------- ---------
TOTAL $265,691 $286,077
========= =========
See notes to consolidated financial statements.
</TABLE>
22
<PAGE>
<TABLE>
<CAPTION>
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED JUNE 30
(AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
===========================================================================================================
2000 1999 1998
--------- --------- ---------
<S> <C> <C> <C>
REVENUES:
Gas marketing and pipeline sales $ 72,156 $ 88,474 $135,348
Oil and gas sales 23,869 18,295 20,730
Well operations and service revenues 5,894 6,540 6,751
Contract settlement and other 191 30,630
--------- --------- ---------
101,919 113,500 193,459
--------- --------- ---------
COSTS AND EXPENSES:
Gas marketing and pipeline cost of sales 70,101 84,417 138,211
Purchase commitment costs 4,945
Field operating expenses 8,143 8,198 8,545
General and administrative 13,647 10,299 9,192
Taxes, other than income 1,492 1,247 1,313
Depletion and depreciation of oil and gas properties 8,847 7,915 7,599
Depreciation of pipelines, other property and equipment 2,892 3,252 2,911
Exploration and impairment 8,347 19,261 8,262
--------- --------- ---------
118,414 134,589 176,033
--------- --------- ---------
Income (loss) from operations (16,495) (21,089) 17,426
--------- --------- ---------
OTHER (INCOME) AND EXPENSE:
Interest 22,302 20,122 20,123
Loss (gain) on sale of assets (101) (91) 1,208
Other (377) (895) 1,638
--------- --------- ---------
21,824 19,136 22,969
--------- --------- ---------
Loss from continuing operations before income taxes and minority interest (38,319) (40,225) (5,543)
Provision (benefit) for income taxes (11,811) (13,133) (2,013)
--------- --------- ---------
Loss from continuing operations before minority interest (26,508) (27,092) (3,530)
Minority interest - 7 243
--------- --------- ---------
Loss from continuing operations (26,508) (27,099) (3,773)
Disposal of utility operations:
Income from utility operations, net of income tax provision of
$3,691, $7,901 and $4,030 8,077 12,212 6,787
--------- --------- ---------
NET INCOME (LOSS) $(18,431) $(14,887) $ 3,014
========= ========= =========
Earnings per common share
Loss from continuing operations $ (40.11) $ (40.27) $ (5.67)
Discontiued operations 12.22 18.15 10.20
--------- --------- ---------
Basic earnings (loss) per common share $ (27.89) $ (22.12) $ 4.53
========= ========= =========
See notes to consolidated financial statements.
</TABLE>
23
<PAGE>
<TABLE>
<CAPTION>
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERSEQUITY (DEFICIT)
FOR THE YEARS ENDED JUNE 30
(AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
=================================================================================================================================
Notes Accum.
Received/ Other
Class A Additional Retained Issuance Compre- Stock-
Common Common Paid-In Earnings Treasury of hensive holders'
Stock Stock Capital (Deficit) Stock Stock Income (Loss) Equity
--------- --------- --------- ---------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Balance, June 30, 1997 $ 714 $ - $ 4,221 $ 27,249 $(3,175) $ (260) $ (151) $28,598
--------
Components of comprehensive income:
Foreign currency translation adjustment (159) (159)
Net income 3,014 3,014
--------
Comprehensive income 2,855
Dividends ($1.70 per share) (1,131) (1,131)
Issuance of common stock 3 164 167
Exercise of employee stock options
for notes receivable 3 125 (128) -
Purchase of treasury stock (523) (523)
Reduction of notes receivable 4 4
--------- --------- --------- ---------- -------- -------- -------- --------
Balance, June 30, 1998 720 - 4,510 29,132 (3,698) (384) (310) 29,970
--------
Components of comprehensive loss:
Foreign currency translation adjustment 133 133
Net loss (14,887) (14,887)
--------
Comprehensive loss (14,754)
Dividends ($0.95 per share) (647) (647)
Common stock issued for services 1 146 147
Conversion of minority interest 2,040 (150) 1,890
Employee stock purchases 900 (856) 44
Purchase of treasury stock - common (1,761) (1,761)
Purchase of treasury stock - Class A (437) (437)
Reduction of notes receivable 25 25
--------- --------- --------- ---------- -------- -------- -------- --------
Balance, June 30, 1999 721 2,940 4,656 13,598 (5,896) (1,365) (177) 14,477
--------
Components of comprehensive loss:
Foreign currency translation adjustment 43 43
Net loss (18,431) (18,431)
---------
Comprehensive loss (18,388)
Common stock issued for services 2 146 148
Redemption of common stock and related
note receivable (5) (187) 192 -
Purchase of treasury stock - common (223) (223)
Purchase of treasury stock - Class A (165) (165)
Reduction of notes receivable 28 28
--------- --------- --------- ---------- -------- -------- -------- --------
Balance, June 30, 2000 $ 718 $ 2,940 $ 4,615 $ (4,833) $(6,284) $(1,145) $ (134) $(4,123)
========= ========= ========= ========== ======== ======== ======== ========
See notes to consolidated financial statements.
</TABLE>
24
<PAGE>
<TABLE>
<CAPTION>
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED JUNE 30
(AMOUNTS IN THOUSANDS)
===================================================================================================================
2000 1999 1998
--------- --------- ---------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss from continuing operations $(26,508) $(27,099) $ (3,773)
Adjustments to reconcile net loss to net cash provided (used) by
operating activities:
Minority interest 7 243
Depletion, depreciation and amortization 12,538 11,966 11,297
Loss (gain) on sale of assets (101) (91) 1,208
Deferred income taxes (11,099) (12,491) (2,300)
Exploration and impairment 5,979 16,778 8,012
Other, net 4,413 3,426 (589)
--------- --------- ---------
(14,778) (7,504) 14,098
Changes in assets and liabilities:
Accounts receivable 420 (38) (655)
Gas in storage (408) 92 (138)
Income taxes receivable 1,079 (4,344) 6,879
Prepaid and other assets 163 1,625 (3,375)
Accounts payable (42) (6,348) 4,846
Funds held for future distributions 902 (337) (301)
Other 7,670 (7,252) (10,583)
--------- --------- ---------
Net cash provided (used) by operating activities from continuing operations (4,994) (24,106) 10,771
Net cash provided by operating activities from disposed operations 7,286 30,009 25,338
--------- --------- ---------
Net cash provided by operating activities 2,292 5,903 36,109
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment (19,299) (25,245) (22,901)
Proceeds from sale of assets 428 3,444 568
Notes receivable and other (300) 70 (238)
--------- --------- ---------
Net cash used by investing activities from continuing operations (19,171) (21,731) (22,571)
Net cash used by investing activities from disposed operations (23,842) (11,414) (15,793)
--------- --------- ---------
Net cash used by investing activities (43,013) (33,145) (38,364)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt 16,250 27,500 1,298
Principal payment on long-term debt (29,094) (3,084) (296)
Proceeds from short-term borrowing 2,000
Purchase of treasury stock and other financing activities (214) (2,154) 161
Prepayment of future gas delivery 10,000 -
Dividends paid - (967) (834)
--------- --------- ---------
Net cash provided (used) by financing activities from continuing operations (1,058) 21,295 329
Net cash provided (used) by financing activities from disposed operations 32,926 (2,375) 2,050
--------- --------- ---------
Net cash provided by financing activities 31,868 18,920 2,379
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents (8,853) (8,322) 124
Cash and cash equivalents, beginning of period 12,163 20,485 20,361
--------- --------- ---------
Cash and cash equivalents, end of period $ 3,310 $ 12,163 $ 20,485
========= ========= =========
The accompanying notes are an integral part of these condensed consolidated financial statements.
</TABLE>
25
<PAGE>
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED JUNE 30, 2000, 1999 AND 1998
--------------------------------------------------------------------------------
1. NATURE OF ORGANIZATION
Energy Corporation of America (the "Company") was formed in June 1993
through an exchange of shares with the common stockholders of Eastern
American Energy Corporation ("Eastern American"). The Company is an
independent energy company. All references to the "Company" include Energy
Corporation of America and its consolidated subsidiaries. The Company's
industry segments are discussed at Note 16.
The Company, primarily through Eastern American, is engaged in exploration,
development and production, transportation and marketing of natural gas
primarily within the Appalachian Basin of West Virginia, Pennsylvania and
Ohio.
The Company, through its wholly owned subsidiaries Westech Energy
Corporation ("Westech") and Westech Energy New Zealand ("WENZ"), is also
engaged in the exploration for and production of oil and natural gas
primarily in the Rocky Mountains, New Zealand and Australia.
In August 2000, the Company sold its wholly owned regulated gas
distribution utility, Mountaineer Gas Company and Subsidiaries
("Mountaineer"). See Note 3.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The following is a summary of the significant accounting policies followed
by the Company.
The following is a summary of the significant accounting policies followed
by the Company.
Principles of Consolidation - The consolidated financial statements include
---------------------------
the accounts of the Company; Eastern American and its subsidiaries; Westech
and WENZ and its investment in certain New Zealand oil and gas exploration
joint ventures. The Company has investments in oil and gas limited
partnerships and joint ventures and has recognized its proportionate share
of these entities' revenues, expenses, assets and liabilities. All
significant intercompany transactions have been eliminated in
consolidation.
Fourth Quarter Results - During the fourth quarter of fiscal 2000, the
------------------------
Company had the normal weather related decline in earnings. In addition,
the Company reported a $4.9 million gas purchase commitment charge. See
Note 13.
Cash and Cash Equivalents - Cash and cash equivalents include short-term
----------------------------
investments maturing in three months or less from the date acquired.
Property, Plant and Equipment - Oil and gas properties are accounted for
--------------------------------
using the successful efforts method of accounting. Under this method,
certain expenditures such as exploratory geological and geophysical costs,
exploratory dry hole costs, delay rentals and other costs related to
exploration are recognized currently as expenses. All direct and certain
indirect costs relating to property acquisition, successful exploratory
wells, development costs, and support equipment and facilities are
capitalized. The Company computes depletion, depreciation and amortization
of capitalized oil and gas property costs on the units-of-production method
using proved developed reserves. Direct production costs, production
overhead and other costs are charged against income as incurred. Gains and
losses on the sale of oil and gas property interests are generally
recognized as income.
26
<PAGE>
Other property, equipment, pipelines and buildings are stated at cost and
are depreciated using straight-line and accelerated methods over estimated
useful lives ranging from three to 30 years.
Repairs and maintenance costs are charged against income as incurred;
significant renewals and betterments are capitalized. Gains and losses on
dispositions of property, equipment, pipelines and buildings are recognized
as income.
At June 30 property, plant and equipment consisted of the following (in
thousands):
Other property, equipment, pipelines and buildings are stated at cost and
are depreciated using straight-line and accelerated methods over estimated
useful lives ranging from three to 30 years.
Repairs and maintenance costs are charged against income as incurred;
significant renewals and betterments are capitalized. Gains and losses on
dispositions of property, equipment, pipelines and buildings are recognized
as income.
At June 30 property, plant and equipment consisted of the following (in
thousands):
<TABLE>
<CAPTION>
2000 1999
--------- ---------
<S> <C> <C>
Oil and gas properties $219,259 $207,904
Other property and equipment 14,167 13,675
Pipelines 18,842 19,021
--------- ---------
252,268 240,600
Less accumulated depletion, depreciation and amortization (92,106) (82,158)
--------- ---------
Net property, plant and equipment $160,162 $158,442
========= =========
</TABLE>
Long-Lived Assets - Statement of Financial Accounting Standards ("SFAS")
------------------
No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of", requires all companies to assess
long-lived assets and assets to be disposed of for impairment. For the
three years ended June 30, 2000, the Company determined that no impairment
needed to be recognized for applicable assets.
Gas in Storage - Gas in storage is stated at the lower of average cost or
----------------
market value.
Deferred Financing Costs - Certain legal, underwriting fees and other
--------------------------
direct expenses associated with the issuance of credit agreements, lines of
credit and other financing transactions have been capitalized. These
financing costs are being amortized over the term of the related credit
agreement.
Foreign Currency Translation - The translation of applicable foreign
------------------------------
currencies into U.S. dollars is performed for balance sheet accounts using
current exchange rates in effect at the balance sheet date and for revenue
and expense accounts using an average exchange rate during the period. The
cumulative translation adjustment is included in stockholders' equity.
Income Taxes - Deferred income taxes reflect the impact of "temporary
-------------
differences" between assets and liabilities recognized for financial
reporting purposes and such amounts as measured by tax laws. These
temporary differences are determined in accordance with SFAS No. 109,
"Accounting For Income Taxes".
Gas Delivery Obligation - Gas delivery obligation represents deferred
-------------------------
revenues on gas sales where the Company has received an advance payment.
The Company recognizes the actual gas sales revenue in the period the gas
delivery takes place.
Revenues and Gas Costs - Oil and gas sales are recognized as income when
-------------------------
the oil or gas is produced and sold. Gas costs are expensed as incurred.
Stock Compensation - As permitted under SFAS No. 123, "Accounting for
-------------------
Stock-Based Compensation", the Company has elected to continue to measure
compensation costs for stock-based employee compensation plans using the
intrinsic value method as prescribed by Accounting Principles Board Opinion
No. 25, "Accounting for Stock Issued to Employees".
27
<PAGE>
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.
The Company's financial statements are based on a number of significant
estimates including oil and gas reserve quantities, which are the basis for
the calculation of depletion, depreciation, amortization and impairment of
oil and gas properties. Management emphasizes that reserve estimates are
inherently imprecise. In addition, utilization of tax credit carryforwards
is based largely on estimates of future taxable income.
Prior Year Reclassifications - Certain amounts in the financial statements
-----------------------------
of prior years have been reclassified to conform to the current year
presentation.
Concentration of Credit Risk - The Company maintains its cash accounts
-------------------------------
primarily with a single bank and invests cash in money market accounts,
which the Company believes to have minimal risk. As operator of jointly
owned oil and gas properties, the Company sells oil and gas production to
numerous U.S. oil and gas purchasers, and pays vendors on behalf of joint
owners for oil and gas services. Both purchasers and joint owners are
located primarily in the northeastern United States. The risk of nonpayment
by the purchasers or joint owners is considered minimal and has been
considered in the Company's allowance for doubtful accounts.
Environmental Concerns - The Company is continually taking actions it
-----------------------
believes necessary in its operations to ensure conformity with applicable
federal, state and local environmental regulations. As of June 30, 2000,
the Company has not been fined or cited for any environmental violations,
which would have a material adverse effect upon capital expenditures,
earnings or the competitive position of the Company.
Recent Accounting Pronouncements - As of July 1, 2000, the Company adopted
---------------------------------
SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities" as amended by SFAS No. 137 and No. 138. SFAS No. 133
establishes accounting and reporting standards for derivative instruments,
including certain derivative instruments embedded in other contracts, and
hedging activities. It requires the recognition of all derivative
instruments as assets or liabilities in the Company's balance sheet and
measurement of those instruments at fair value. The accounting treatment of
changes in fair value is dependent upon whether or not a derivative
instrument is designated as a hedge and if so, the type of hedge. For
derivatives designated as cash flow hedges, changes in fair value are
recognized in other comprehensive income until the hedged item is
recognized in earnings.
The Company periodically hedges a portion of its oil and gas production
through futures and swap agreements. The purpose of the hedges is to
provide a measure of stability in the volatile environment of oil and gas
prices and to manage its exposure to commodity price risk under existing
sales commitments. All of the Company's price swap agreements in place at
June 30, 2000 will be designated as cash flow hedges. Adoption of SFAS No.
133 on July 1, 2000, resulted in recording $3.4 million of decline in fair
value to accumulated other comprehensive income, consisting of $3.8 million
to short term derivative liabilities, $0.4 million to long term derivative
liabilities and $0.8 million to short term derivative assets.
28
<PAGE>
Supplemental Disclosures of Cash Flow Information - Supplemental cash flow
--------------------------------------------------
information for the years ended June 30 is as follows (in thousands):
<TABLE>
<CAPTION>
2000 1999 1998
------- ------- -------
<S> <C> <C> <C>
Cash paid for:
Interest $21,360 $19,192 $18,829
Income taxes, net 242 1,376 1,234
Noncash investing and financing activities:
Dividends declared and unpaid at year end 316
Seller financed acquisition 150 943
Acquisition of property for cancellation of notes 1,900
</TABLE>
3. DISPOSITIONS
On December 20, 1999, the Company agreed to sell its wholly-owned regulated
gas distribution utility, Mountaineer, to Allegheny Energy, Inc.
("Allegheny") pursuant to a stock purchase agreement for $323 million,
which includes the assumption of approximately $100 million of long term
debt and was subject to certain adjustments. The transaction closed on
August 18, 2000 and will be recorded in the first quarter of fiscal year
2001. The transaction will result in a pre-tax gain for the Company
estimated at approximately $165 million.
The Company also entered into a gas sale and purchase agreement with
Allegheny whereby it will begin the delivery of natural gas beginning on or
after July 1, 2001. The Company has received a $10 million prepayment
pursuant to the agreement, which is recorded as long term deferred revenue
on the balance sheet. Potentially, the Company has the ability to receive
additional prepayments up to $20 million, pending the ability to present a
letter of credit equal to the prepayment.
The utility operations have historically been reported as a separate
segment. As a result of the sale, its disposition is considered, for
accounting purposes, to be a discontinued business. Accordingly, amounts in
the financial statements and related notes thereto for all periods
presented therein have been restated to reflect discontinued operations
accounting. Summarized financial statements for the disposed business, as
of and for the year ended June 30 are as follows, in thousands:
29
<PAGE>
<TABLE>
<CAPTION>
2000 1999
-------- --------
<S> <C> <C>
ASSETS
Cash and cash equivalents $ 1,089 $ 457
Accounts receivable 19,780 22,117
Prepaid and other current assets 30,369 24,682
-------- --------
Total current assets 51,238 47,256
Property, plant and equipment, net 167,121 156,873
Deferred utility charges 15,983 18,785
Other 2,605 2,674
-------- --------
TOTAL $236,947 $225,588
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Accounts payable $ 13,111 $ 24,575
Short term borrowings 9,944 16,799
Other current liabilities 17,829 18,596
-------- --------
Total current liabilities 40,884 59,970
Long-term debt 100,116 60,135
Deferred income tax liability 22,472 22,991
Other long-term obligation 10,096 10,819
-------- --------
Total liabilities 173,568 153,915
Total stockholders' equity 63,379 71,673
-------- --------
TOTAL $236,947 $225,588
======== ========
</TABLE>
<TABLE>
<CAPTION>
2000 1999 1998
-------- --------- ---------
<S> <C> <C> <C>
REVENUES:
Utility gas sales and transportation $169,173 $158,439 $156,579
Other revenue 9,709 13,664 14,298
-------- --------- ---------
178,882 172,103 170,877
-------- --------- ---------
COST AND EXPENSES:
Utility gas purchased 83,840 73,842 85,166
Utility operations and maintenance 23,166 22,496 22,084
General and administrative (1) 19,876 15,533 14,858
Depreciation and depletion 11,764 10,871 9,527
Taxes, other than income 14,734 14,013 13,568
Other 5,575 9,706 9,400
-------- --------- ---------
158,955 146,461 154,603
-------- --------- ---------
Income from operations 19,927 25,642 16,274
-------- --------- ---------
OTHER (INCOME) EXPENSE
Interest 8,146 6,432 6,264
Other 733 (183) (87)
-------- --------- ---------
Income before income taxes 11,048 19,393 10,097
Provision for income taxes 3,691 7,901 4,030
-------- --------- ---------
NET INCOME $ 7,357 $ 11,492 $ 6,067
======== ========= =========
<FN>
(1) Includes $720 in management fees paid to the Company, which is
subsequently eliminated in consolidation.
</TABLE>
30
<PAGE>
<TABLE>
<CAPTION>
2000 1999 1998
--------- --------- ---------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 7,357 $ 11,492 $ 6,067
Adjustment to reconcile earnings to net cash
provided by operating activities
Depletion, depreciation and amortization 11,764 10,871 9,528
Other, net 745 1,540 4,173
Changes in assets and liabilities:
Current assets (3,027) (3,041) 3,715
Current liabilities (9,641) 7,822 341
--------- --------- ---------
Net cash provided by operating activities 7,198 28,684 23,824
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment (23,842) (11,414) (15,793)
--------- --------- ---------
Net cash used by investing activities (23,842) (11,414) (15,793)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt 40,000
Short term borrowings, net (6,855) (2,375) 3,450
Debt issuance costs and other (219)
Dividends to parent company (15,650) (15,500) (10,875)
--------- --------- ---------
Net cash provided (used) by financing activities 17,276 (17,875) (7,425)
--------- --------- ---------
Net increase in cash and cash equivalents 632 (605) 606
Cash and cash equivalents, beginning of period 457 1,062 456
--------- --------- ---------
Cash and cash equivalents, end of period $ 1,089 $ 457 $ 1,062
========= ========= =========
</TABLE>
The income from operations of utility totaling $8.1 million, net of a tax
provision of $3.6 million, includes net earnings from discontinued
operations for the six month period ended December 31, 1999 (the
pre-measurement period) of $4.5 million, net of tax provision of $2.3
million and net earnings from discontinued operations for the six month
period January 1, 2000 to June 30, 2000 (post-measurement period) of $3.6
million, net of tax provision of $1.4 million. Net earnings during the
post-measurement period are included herein and not deferred and included
within the gain on disposal computation since such earnings are considered
to have been realized. Estimated net losses from discontinued operations
for the period of July 1, 2000 to August 18, 2000 (disposal date) of $1.9
million, net of tax benefit of $1.2 million, will be recorded in the first
quarter of fiscal year 2001 and included, as a reduction, in the
computation of the gain on disposal of utility segment. When aggregated,
net earnings from discontinued operations for the period of December 20,
1999 (measurement date) to August 18, 2000 (disposal date) totals $6.2
million, net of tax provision $2.5 million.
4. RISK MANAGEMENT
Options, Future Contracts, and Swap Agreements -The Company is a party to
------------------------------------------------
natural gas options, future contracts and swap agreements in the normal
course of business. These instruments involve, to varying degrees, elements
of market and credit risk in excess of the amount recognized in the
consolidated balance sheets.
At June 30, 2000, the Company had swap agreements maturing from July 2000
through October 2001 covering 5,176,600 Mmbtu of gas. The Company receives
a fixed price in exchange for a variable price on 4,760,000 Mmbtu and
receives a variable price in exchange for a fixed price on 416,600 Mmbtu.
The Company's net unrealized loss related to these agreements was
approximately $3.4 million at June 30, 2000.
At June 30, 1999, the Company had over-the-counter natural gas futures and
options contracts related to gas sale commitments covering 3,553,000 Mmbtu
of gas maturing through June 2000. As these contracts were designated as
hedges, any gains or losses resulting from market price changes were
included in oil and gas sales for the month to which the contract is
applicable. The Company's net unrealized loss related to these contracts
was approximately $88,000 at June 30, 1999.
31
<PAGE>
In addition to futures and options contracts, the Company enters into
over-the-counter price swap agreements to manage its exposure to commodity
price risk under existing sales commitments. At June 30, 1999, the Company
had swap agreements maturing from November 1999 through June 2000 covering
772,000 Mmbtu under which the Company receives a fixed price in exchange
for a variable price. The Company's net unrealized gain related to these
agreements was approximately $28,000 at June 30, 1999.
In addition, at June 30, 1999, the Company had natural gas fixed price
purchase option contracts for the purchase and physical delivery of 615,000
Mmbtu of gas expiring through October 1999. The cost of these options,
which totaled approximately $190,000 for the year ended June 30, 1999, is
included in Cost of Gas Sales for the month to which the options were
applicable. At June 30, 1999, the remaining options, for the months of July
1999 through October 1999, are carried at cost that totaled $189,875 and
approximates fair value.
For the years ended June 30, 2000, 1999 and 1998, the Company recognized a
net loss on its natural gas hedging activities of $805,400, $32,200 and
$47,000, respectively.
5. DEBT
Long-Term Debt - At June 30 long-term debt consisted of the following (in
---------------
thousands):
<TABLE>
<CAPTION>
2000 1999
--------- ---------
<S> <C> <C>
ECA senior subordinated notes, interest at 9.5% payable
semi-annually, due May 15, 2007 $200,000 $200,000
ECA revolving credit, interest floating at Prime, plus 1.5% or
LIBOR plus 3%, due 2002 12,000 25,000
Installment notes payable, at interest rates ranging from
6.2% to 8% 1,661 1,504
--------- ---------
213,661 226,504
Less current portion (1,086) (6,618)
--------- ---------
$212,575 $219,886
========= =========
</TABLE>
The Company's various debt agreements contain certain restrictions and
conditions among which are limitations on indebtedness, funding of certain
subsidiaries, dividends and investments, and certain tangible net worth and
debt and interest coverage ratio requirements. The agreements require the
Company to maintain certain financial conditions, including a minimum net
worth, restriction on funded debt and restrictions on the amount of
dividends that can be declared.
32
<PAGE>
Scheduled maturities of the Company's long-term debt at June 30, 2000 for
each of the next five years and thereafter are as follows (in thousands):
2001 $ 1,086
2002 12,113
2003 113
2004 113
2005 113
Thereafter 200,123
-----------------
$ 213,661
================
Revolving Credit - The Company had a $22 million revolving credit facility
-----------------
secured by certain properties, interest and contracts. The interest rate is
variable based on Eurodollars or other defined basis. The annual commitment
fee ranges between 0.3% and 0.625% depending on usage. As of June 30, 2000,
$12.8 million was outstanding under this facility. On August 18, 2000, the
balance, $19.8 million, was paid in full and the credit agreement was
terminated.
Other Credit Facilities - As of June 30, 1999, Eastern American had a $3
-------------------------
million letter of credit, issued by a bank in support of Eastern American's
obligations under a gas purchase contract with the royalty trust (see Note
13). The letter of credit reduced by $3 million on June 30 of each year
until its expiration on June 30, 2000. As of June 30, 2000 and 1999, no
amounts had been drawn under the letter of credit. Eastern American also
has an unsecured revolving line of credit totaling $2 million, which
expires November 30, 2000 and charges an interest rate of prime plus 0.5%.
As of June 30, 2000 and 1999, $2 million and $0 were outstanding under the
line of credit.
Seller Financed Note - In 1998, the Company purchased a natural gas
----------------------
gathering system in West Virginia for $1.2 million. The Company paid $0.3
million in cash and issued a note for the balance payable to the seller in
100 consecutive equal monthly payments. As of June 30, 2000 and 1999, the
balance of the note was approximately $0.7 million and $0.8 million.
6. INCOME TAXES
The following table summarizes components of the Company's provision
(benefit) for income taxes for the years ended June 30 (in thousands):
<TABLE>
<CAPTION>
2000 1999 1998
--------- --------- --------
<S> <C> <C> <C>
Current:
Federal $ (666) $ (340) $ 337
State (46) (302) (50)
--------- --------- --------
Total current (712) (642) 287
--------- --------- --------
Deferred:
Federal (11,477) (9,386) (3,733)
State 378 (3,105) 1,433
--------- --------- --------
Total deferred (11,099) (12,491) (2,300)
--------- --------- --------
Total provision (benefit) for income taxes $(11,811) $(13,133) $(2,013)
========= ========= ========
</TABLE>
33
<PAGE>
A reconciliation of the provision for income taxes computed at the
statutory rate to the provision for income taxes as shown in the
consolidated statements of operations for the years ended June 30 is
summarized below (in thousands):
<TABLE>
<CAPTION>
2000 1999 1998
--------- --------- --------
<S> <C> <C> <C>
Tax expense (benefit) at the federal statutory rate $(13,028) $(13,676) $(1,885)
State taxes, net of federal tax effects (1,781) (2,664) (260)
Foreign losses 838
Section 29 tax credits 216 921 (1,783)
Change in valuation allowance on federal, foreign
and state deferred tax assets, net of federal effect 2,000 (592) 571
Investment tax credit expiration 532 530
IRS adjustment 519
Other, net 250 1,829 506
--------- --------- --------
Provision (benefit) for income taxes $(11,811) $(13,133) $(2,013)
========= ========= ========
</TABLE>
During fiscal 1999, the Company finalized an IRS examination resulting in
payments for prior taxes of $0.5 million. In addition, Section 29 credits
for 1998 were not utilized because of reductions to regular taxable income
and have been added to the current year's tax provision.
Components of the Company's federal and state deferred tax assets and
liabilities, as of June 30, are as follows (in thousands):
<TABLE>
<CAPTION>
2000 1999
============================= ==============================
Federal State Total Federal State Total
--------- -------- --------- --------- -------- ---------
<S> <C> <C> <C> <C> <C> <C>
Deferred tax assets:
Bad debt allowance $ 168 $ 45 $ 213 $ 161 $ 43 $ 204
Deferred compensation and profit sharing 162 43 205 162 43 205
Tax credits and carryforwards 19,678 10,904 30,582 13,058 8,774 21,832
Other long-term obligations 1,272 337 1,609 1,272 337 1,609
Other 10,392 2,683 13,075 7,746 2,016 9,762
--------- -------- --------- --------- -------- ---------
Total deferred tax assets 31,672 14,012 45,684 22,399 11,213 33,612
--------- -------- --------- --------- -------- ---------
Deferred tax liabilities:
Property, plant and equipment (15,887) (4,206) (20,093) (16,181) (4,283) (20,464)
Federal income tax on state tax credits (2,999) (2,999) (2,983) (2,983)
Other liabilities (8,397) (2,168) (10,565) (7,648) (1,991) (9,639)
--------- -------- --------- --------- -------- ---------
Total deferred tax liabilities (27,283) (6,374) (33,657) (26,812) (6,274) (33,086)
--------- -------- --------- --------- -------- ---------
Valuation allowance (7,951) (7,951) (4,920) (4,920)
--------- -------- --------- --------- -------- ---------
Net deferred income tax asset (liability) 4,389 (313) 4,076 (4,413) 19 (4,394)
Current deferred tax asset (liability) (259) (70) (329) 152 39 191
--------- -------- --------- --------- -------- ---------
Net long-term deferred tax asset (liability) $ 4,648 $ (243) $ 4,405 $ (4,565) $ (20) $ (4,585)
========= ======== ========= ========= ======== =========
</TABLE>
34
<PAGE>
At June 30, 2000, the Company has the following federal and state tax
credits and carryforwards (in thousands):
<TABLE>
<CAPTION>
Year of
Amount Expiration
-------- ----------
<S> <C> <C>
AMT and Section 29 tax credits $ 11,723 None
Investment tax credits 80 2000-2001
Net operating loss carryover 7,875 2020
--------
Total federal credits $ 19,678
========
West Virginia tax credits $ 8,820 2002
Net operating loss carryover 2,084 2015
--------
Total state credits $ 10,904
========
</TABLE>
The Company is eligible for relocation incentives taken in the form of tax
credits from West Virginia. The incentive amounts are based upon
investments made and jobs created in that state. Tax credits generated by
the Company are used primarily to offset the payment of severance, property
and state income taxes. Based on existing future taxable temporary
differences and projections of future West Virginia severance, property and
state income taxes, management has provided a valuation allowance for that
portion of the credits not expected to be utilized.
7. EMPLOYEE BENEFIT PLANS
The Company and certain subsidiaries, have a Profit Sharing/Incentive Stock
Plan (the "Plan") for the stated purpose of expanding and improving profits
and prosperity and to assist the Company in attracting and retaining key
personnel. The Plan is noncontributory, and its continuance from year to
year is at the discretion of the Board of Directors. The annual profit
sharing pool is based on calculations set forth in the Plan. One-half of
the pool is generally paid to eligible employees within 120 days of the end
of the fiscal year and one-half is deferred to the following year.
Generally, to be eligible to participate, an employee must have been
continuously employed for two or more years; however, employees with less
than two years of employment may participate under certain circumstances.
The Company recognized $0.9 million, $0 and $1.7 million of profit sharing
expense during the years ended June 30, 2000, 1999, and 1998, respectively.
For certain subsidiaries, the Company sponsors a Section 401(k) plan
covering all full-time employees who wish to participate. The Company's
contributions, which are principally based on a percentage of the employee
contributions, and charged against income as incurred, totaled $232,800,
$182,600 and $153,600 for the years ended June 30, 2000, 1999, and 1998,
respectively.
8. CAPITAL STOCK
Voting Common Stock- In May 1995, the Company was reincorporated in the
---------------------
State of West Virginia. As part of this reincorporation, each outstanding
share of then existing no-par value common stock was converted to one share
of $1 par value common stock.
The Company has an agreement with a stockholder covering the sale or
disposition of 59,600 shares of common stock, at June 30, 2000, that
provides the stockholder cannot sell stock without first offering such
shares to the Company. Under certain circumstances, the Company would be
required to purchase the related stock if not previously tendered to the
Company or otherwise sold or disposed of in accordance with the provisions
of the agreement.
35
<PAGE>
Class A Non-Voting Common Stock - In August 1998, the Company amended its
---------------------------------
articles of incorporation authorizing the issuance of up to 100,000 shares
of Class A non-voting common stock. The Company then offered and exchanged
13,517 shares of its new Class A stock for the outstanding Class A stock of
its subsidiaries, owned by certain employees, officers and directors. The
minority interest carrying value prior to exchange, which reflected the
subsidiaries' Class A shares, was the basis used to record the issuance of
the Company's new Class A stock.
Treasury Stock - At June 30, 2000, the Company had 78,012 shares of voting
---------------
common stock in treasury, carried at cost. The Company purchased 2,660 and
20,704 shares of voting common stock during the years ended June 30, 2000
and 1999, respectively. At June 30, 2000, the Company also had 6,227 shares
of non-voting Class A stock in treasury, carried at cost. The Company
purchased 1,711 and 4,516 shares of non-voting Class A stock during the
years ended June 30, 2000 and 1999, respectively.
Stock Plans - During fiscal 1999, the Company created an incentive stock
------------
purchase agreement, primarily for outside Directors. Under the agreement,
options to purchase voting common stock were granted at $75, based on the
fair market value as determined by the Board of Directors, per share and
are exercisable based on the following schedule:
<TABLE>
<CAPTION>
Number of
Exercise Period Shares
------------------------------------- ---------
<S> <C>
January 1, 1999 to December 31, 2003 10,002
January 1, 2000 to December 31, 2004 10,002
January 1, 2001 to December 31, 2005 9,996
---------
30,000
=========
</TABLE>
No options were exercised for either of the years ended June 30, 2000 or
1999. Therefore, as of June 30, 2000, a total of 20,004 options were
exercisable. Fair value of the options at the grant dates, as estimated by
management, was nominal.
During fiscal 1999, the Company created an employee stock purchase plan.
Under the plan, 12,003 Class A shares were issued to employees at $75 per
share in exchange for cash and promissory notes bearing interest of 6.5% or
8%, depending on the initial cash payment and recourse nature of the notes.
The Company has agreed to forgive the notes over a seven year period
assuming continued employment; therefore, the notes are being amortized
over the term of employment. The Company has a right-of-first refusal to
repurchase any shares employees wish to sell and in the event of death,
disability or termination, the Company has an option to repurchase the
shares.
36
<PAGE>
9. EARNINGS PER SHARE
A reconciliation of the components of basic and diluted net loss from
continuing operations per common share as of June 30, for the years
indicated, is as follows:
<TABLE>
<CAPTION>
Per-Share
Income Shares Amount
------------- ------- --------
<S> <C> <C> <C>
2000
----
Basic and Diluted Earnings per Share
Loss available to common shareholders $(26,508,000) 660,928 $(40.11)
1999
----
Basic and Diluted Earnings per Share
Loss available to common shareholders $(27,099,000) 672,973 $(40.27)
1998
----
Basic and Diluted Earnings per Share
Income available to common shareholders $ (3,773,000) 665,074 $ (5.67)
</TABLE>
The effect of stock options was not included in the computation of diluted
net loss per share during fiscal years 2000 and 1999 because to do so would
have been antidilutive. There were no stock options outstanding during
fiscal 1998.
10. UNCONSOLIDATED AFFILIATE
The Company owns a 25.4% interest in the successor limited liability
corporation, Breitburn Energy Corporation ("BEC"). The Company's investment
in BEC is accounted for under the equity method. As the Company's share of
net losses in BEC has exceeded the carrying amount of the investment, the
investment has been reduced to zero until the Company's share of net income
equals its share of unrecognized net losses. Summarized financial
information for BEC as of and for the years ended June 30, is as follows
(in thousands):
<TABLE>
<CAPTION>
2000 1999 1998
------- -------- --------
<S> <C> <C> <C>
Current assets $ 8,644 $ 5,914
Oil and gas properties 79,480 50,415
Other assets 3,157 1,742
------- --------
Total assets $91,281 $58,071
======= ========
Current liabilities $10,100 $ 5,340
Long-term debt 52,900 26,200
Other liabilities 1,131 190
Equity 27,150 26,341
------- --------
Total liabilities and equity $91,281 $58,071
======= ========
Net sales $17,658 $11,655 $ 8,969
======= ======== ========
Gross profit $ 3,179 $(1,218) $ 2,379
======= ======== ========
Net income (loss) $ 1,155 $(2,557) $(1,772)
======= ======== ========
</TABLE>
37
<PAGE>
11. OPERATING LEASES
The Company has noncancelable operating lease agreements for the rental of
office space, computer and other equipment. Certain of these leases contain
purchase options or renewal clauses. Rental expense for operating leases
was approximately $1.2, $1.2 and $1.0 million for the years ended June 30,
2000, 1999 and 1998, respectively.
At June 30, 2000 future minimum lease payments for each of the next five
years and thereafter are as follows (in thousands):
2001 $ 1,243
2002 1,090
2003 957
2004 792
2005 680
Thereafter -
------------
$ 4,762
============
12. RELATED PARTY TRANSACTIONS
The Company has entered into a rental arrangement for office space from a
partnership in which certain officers are partners. Rent payments totaled
$415,700, $374,200 and $339,470 for the years ended June 30, 2000, 1999 and
1998, respectively.
The Company advanced funds to certain officers, generally at 8% interest.
Balances totaled $0.1 million and $0.5 million, respectively, at June 30,
2000 and 1999.
In 1998, the Company issued promissory notes to certain employees as part
of a Class A incentive stock purchase agreement, whereby 13,669 shares were
issued at $75 per share. The carry value of these notes was $1.0 million at
June 30, 2000 and 1999. The notes have interest rates of 6.5% and 8%. A
provision in the agreement cancels the principal balance if the employee
remains in the continuous employment of the Company through December 31,
2005. In addition, between 1995 and 1997, the Company issued 19,200 shares
of common stock as part of an incentive stock option agreement with two
officers. Promissory notes were issued for $0.2 million, which was also the
carrying value at June 30, 2000 and 1999. Interest rates are calculated at
LIBOR plus 1.5%. No cancellation provision was included with this stock
incentive program.
The Company advanced funds in 1988 to certain officers and directors at 8%
interest, secured by interests in oil and gas properties and were payable
out of net proceeds from the oil and gas production on these properties.
During fiscal 1999, Eastern American purchased the related working interest
from the officers and directors, canceling the related notes.
During fiscal 1999, the Company purchased from certain officers and
directors, for $2.4 million, volumetric production from wells in New
Zealand. Future production, totaling 3.3 million Mcf, otherwise allocable
to the officers and directors will be allocated to the Company. The Company
has recorded the payment as an investment in oil and gas properties.
13. COMMITMENTS AND CONTINGENCIES
In 1993, the Company sold working interests in certain Appalachian gas
properties in connection with the formation of a royalty trust.
38
<PAGE>
A portion of the proceeds from the sale of these interests, representing a
term net profits interest, was accounted for as a production payment and
was classified as deferred trust revenue. Certain gas production
attributable to the royalty trust is purchased by a wholly owned subsidiary
of the Company pursuant to a gas purchase contract, which expires in 2013.
The purchase price under the contract is based on escalating fixed price
and spot market components. The fixed price component expired on January 1,
2000. As of June 30, 2000, the Company determined that due to the rising
cost of transporting gas and diminishing margins, losses are expected on
the Company's purchase commitment. A purchase commitment loss of $4.9
million was accrued and $6.2 million was reclassified from deferred trust
revenue to other long term obligations. Unamortized deferred trust revenue
is $4.3 million and $12.0 million at June 30, 2000 and 1999, respectively.
In connection with an existing gas delivery obligation agreement, whereby
Eastern American received an advance payment, a subsidiary of Eastern
American entered into a credit line deed of trust, which has an available
balance of $5.0 million as of June 30, 2000 to collateralize its
performance under the gas delivery obligation. This credit line deed of
trust declines at a rate of 7.5% per year.
The Company is involved in various legal actions and claims arising in the
ordinary course of business. Management does not expect these matters to
have a material adverse effect on the Company's financial position or
results of operations.
14. FINANCIAL INSTRUMENTS
The estimated fair values of the Company's financial instruments, as of
June 30, have been determined using appropriate market information and
valuation methodologies. Considerable judgment is required to develop the
estimates of fair value; thus, the estimates provided below are not
necessarily indicative of the amount that the Company could realize upon
the sale or refinancing of such financial instruments (in thousands):
<TABLE>
<CAPTION>
2000 1999
==================== ===================
Carrying Fair Carrying Fair
Value Value Value Value
--------- --------- --------- --------
<S> <C> <C> <C> <C>
Notes receivable $ 2,657 $ 2,657 $ 4,749 $ 4,695
Long-term debt 212,575 140,000 226,504 206,505
Futures, swaps, options - (3,400) 490 430
</TABLE>
The Company in estimating the fair value of its financial instruments used
the following methods and assumptions:
Notes Receivable - The notes receivable accrue interest at a fixed rate.
-----------------
Fair value was estimated using discounted cash flows based on current
interest rates for notes with similar credit characteristics and
maturities.
Long-Term Debt - A portion of long-term debt was borrowed under a senior
---------------
revolving credit facility, which accrues interest at variable rates; as a
result, carrying value approximates fair value. The Company's subordinated
debt is traded publicly. The market value at the end of the year was used
for valuation purposes. The remaining portion of the Company's long-term
debt is comprised of fixed rate facilities; for this portion, fair value
was estimated using discounted cash flows based upon the Company's
estimated current borrowing rates for debt with similar maturities.
Futures, swaps and options - The fair value of these instruments are based
---------------------------
on quoted market prices.
39
<PAGE>
15. CONTRACT SETTLEMENT
In March 1998, the Company entered into a Termination Agreement (the
"Agreement") with Seneca Power Partners, L.P. ("Seneca"), which provided
for the termination of a long-term gas sale and purchase contract between
the Company and Seneca. Prior to such termination, the Company was
obligated to deliver up to 12,000 Mcf of natural gas per day to Seneca's
cogeneration facility. The Agreement was a direct result of an amendment to
the existing Power Purchase Agreement by and between Seneca and Niagara
Mohawk Power Corporation ("Niagara"). Niagara negotiated amendments to all
of its existing Power Purchase Agreements as part of a Master Restructuring
Agreement. Pursuant to the Agreement, the Company received cash
consideration of approximately $22 million on June 30, 1998. As a result of
this termination, the Company estimated it would incur future losses of
approximately $2 million on its gas purchase commitments. Accordingly, the
provision for anticipated losses was recorded as an offset to the contract
settlement income in fiscal 1998 and amortized against the cost of gas
purchased during fiscal 1999.
Although the Company terminated all rights and obligations under the
contract, the Company retained its 10% limited partnership interest in
Seneca. For the fiscal year ended June 30, 1998, the Company recorded
partnership distributions of $10.0 million, comprised of $7.2 million in
cash and $2.8 million of Niagara common stock. The Niagara stock was sold
in November 1998 for $2.9 million. No partnership distributions were
received in fiscal years 2000 or 1999.
40
<PAGE>
16. INDUSTRY SEGMENTS
The Company's reportable business segments have been identified based on
the differences in products and service provided. Revenues for the
exploration and production segment are derived from the production and sale
of natural gas and crude oil. Revenues for the marketing and pipeline
segment arise from the marketing of both Company and third party produced
natural gas volumes and the related transportation. Management utilizes
earnings before interest, taxes, depreciation, depletion, amortization and
exploratory costs ("EBITDAX") to evaluate each segment's operations.
Summarized financial information for the Company's reportable segments is
shown in the following table. The "other" column includes items related to
corporate items (in thousands):
<TABLE>
<CAPTION>
Exploration Marketing
and and
Production Pipeline Other Consolidated
------------- ----------- -------- --------------
<S> <C> <C> <C> <C>
2000
Sales to unaffiliated customers $ 29,763 $ 72,156 $ 101,919
Intersegment revenues -
Depreciation, depletion, amortization 10,349 1,031 359 11,739
Exploratory costs 8,347 8,347
Operating profit (loss) (5,048) (6,871) (4,576) (16,495)
Interest expense 110 2 22,190 22,302
EBITDAX 9,270 (1,287) (3,914) 4,069
Total assets 122,033 67,522 19,341 208,896
Capital expenditures 19,074 148 77 19,299
--------------------------------------- ------------- ----------- -------- --------------
1999
Sales to unaffiliated customers $ 24,836 $ 81,279 $ 191 $ 106,306
Intersegment revenues 7,194 7,194
Depreciation, depletion, amortization 9,713 1,104 350 11,167
Exploratory costs 19,261 19,261
Operating profit (loss) (17,794) 929 (4,224) (21,089)
Interest expense 113 20,009 20,122
EBITDAX 11,638 2,033 (3,353) 10,318
Total assets 121,852 58,420 35,666 215,938
Capital expenditures 22,139 506 2,600 25,245
--------------------------------------- ------------- ----------- -------- --------------
1998
Sales to unaffiliated customers $ 26,523 $ 136,279 $10,030 $ 172,832
Intersegment revenues 958 19,669 20,627
Depreciation, depletion, amortization 9,285 1,066 159 10,510
Exploratory costs 8,262 8,262
Operating profit (loss) (3,471) 14,925 5,971 17,425
Interest expense 248 19,875 20,123
EBITDAX 10,736 15,991 6,382 33,109
Total assets 129,621 64,955 24,467 219,043
Capital expenditures 19,952 590 2,359 22,901
--------------------------------------- ------------- ----------- -------- --------------
</TABLE>
Operating profit represents revenues less costs which are directly
associated with such operations. Revenues are priced and accounted for
consistently for both unaffiliated and intersegment sales. The 'Other'
column includes items related to non-reportable segments, corporate and
elimination items. Included in the exploration and production segment are
net long-lived assets located in New Zealand and Australia of $3.9, $1.8
and $1.4 million, as of June 30, 2000, 1999, and 1998.
41
<PAGE>
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
Costs - The following tables set forth capitalized costs as of June 30 and costs
-----
incurred, including capitalized overhead, for oil and gas producing activities
for the years ended June 30 (in thousands):
<TABLE>
<CAPTION>
2000 1999 1998
--------- --------- ---------
<S> <C> <C> <C>
Capitalized costs:
Proved properties $208,271 $196,554 $187,689
Unproved properties 10,988 11,351 14,428
--------- --------- ---------
Total 219,259 207,905 202,117
Less accumulated depletion and depreciation (76,458) (68,804) (61,521)
--------- --------- ---------
Net capitalized costs $142,801 $139,101 $140,596
========= ========= =========
Companyshare of equity method investeenet
capitalized costs $ 18,693 $ 11,607 $ 9,474
========= ========= =========
Costs incurred:
Acquisition of proved properties $ 4,160 $ 2,088 $ 694
Development costs 5,869 7,527 9,336
Exploration costs 8,693 13,589 9,154
--------- --------- ---------
Total costs incurred $ 18,722 $ 23,204 $ 19,184
========= ========= =========
Companyshare of equity method investeetotal
costs incurred $ 7,759 $ 3,966 $ 944
========= ========= =========
</TABLE>
Results of Operations - The results of operations for oil and gas producing
-----------------------
activities, excluding corporate overhead and interest costs for the years ended
June 30 are as follows (in thousands):
<TABLE>
<CAPTION>
2000 1999 1998
-------- --------- --------
<S> <C> <C> <C>
Revenues from sale of oil and gas $23,869 $ 18,295 $20,730
Less:
Production costs 8,849 9,005 8,545
Production taxes 1,198 964 1,073
Exploration and impairment 8,347 19,261 8,262
Depletion, depreciation and amortization 8,847 7,915 7,599
Income tax expense (benefit) (1,181) (6,597) (1,662)
-------- --------- --------
Income (loss) from oil and gas operations $(2,191) $(12,253) $(3,087)
======== ========= ========
Companyshare of equity method investee
income from oil and gas operations $ 1,857 $ 183 $ 714
======== ========= ========
</TABLE>
Production costs include those costs incurred to operate and maintain productive
wells and related equipment and include costs such as labor, repairs and
maintenance, materials, supplies, fuel consumed and insurance. Production costs
are net of well tending fees, which are included in well operations revenues in
the accompanying consolidated statements of operations.
Exploration and impairment expenses include the costs of geological and
geophysical activity, unsuccessful exploratory wells and leasehold impairment
allowances.
42
<PAGE>
Depletion, depreciation and amortization include costs associated with
capitalized acquisition, exploration, and development costs.
The provision for income taxes is computed at the statutory federal income tax
rate and is reduced to the extent of permanent differences which have been
recognized in the Company's tax provision, such as investment tax credits, and
the utilization of Federal tax credits permitted for fuel produced from a
non-conventional source.
Reserve Quantity Information - Reserve estimates are subject to numerous
------------------------------
uncertainties inherent in the estimation of quantities of proved reserves and in
the projection of future rates of production and timing of development
expenditures. The accuracy of such estimates is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Results of subsequent drilling, testing and production may cause either upward
or downward revisions of previous estimates. Further, the volumes considered
commercially recoverable fluctuate with changes in prices and operating costs.
Reserve estimates, by their nature, are generally less precise than other
financial statement disclosures.
The following table sets forth information for the years indicated with respect
to changes in the Company's proved reserves, substantially all of which are in
the United States.
<TABLE>
<CAPTION>
Natural Gas Crude Oil
(Mmcf) (Mbbls)
------------ ----------
<S> <C> <C>
Proved reserves:
June 30, 1997 145,780 1,233
Revisions of previous estimates (945) (49)
Extensions and discoveries 14,209 205
Purchases of reserves in place 1,002 79
Sales of reserves in place (11)
Production (7,266) (125)
------------ ----------
June 30, 1998 152,780 1,332
Revisions of previous estimates (1,384) (229)
Extensions and discoveries 5,049 74
Sales of reserves in place (674) (85)
Production (7,184) (133)
------------ ----------
June 30, 1999 148,587 959
Revisions of previous estimates 4,656 71
Extensions and discoveries 2,185 66
Purchases of reserves in place 9,461
Production (7,399) (113)
------------ ----------
June 30, 2000 157,490 983
============ ==========
Proved developed reserves:
June 30, 1998 122,255 735
June 30, 1999 126,962 714
June 30, 2000 141,067 738
Companyshare of equity method investeeproved reserve at:
June 30, 1998 2,077 3,113
June 30, 1999 5,529 9,907
June 30, 2000 7,402 13,681
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows - Estimated discounted
---------------------------------------------------------
future net cash flows and changes therein were determined in accordance with
SFAS No. 69, "Disclosures About Oil and Gas Producing Activities." Certain
information concerning the assumptions used in computing the valuation of proved
reserves and their inherent limitations are discussed below. The Company
believes such information is essential for a proper understanding and assessment
of the data presented.
43
<PAGE>
Future cash inflows are computed by applying period-end prices of oil and gas
relating to the Company's proved reserves to the period-end quantities of those
reserves. Future price changes are considered only to the extent provided by
contractual arrangements in existence at period-end.
The assumptions used to compute estimated future net revenues do not necessarily
reflect the Company's expectations of actual revenues or costs, or their present
worth. In addition, variations from the expected production rates also could
result directly or indirectly from factors outside of the Company's control,
such as unintentional delays in development, changes in prices or regulatory
controls. The reserve valuation further assumes that all reserves will be
disposed of by production. However, if reserves are sold in place, this could
affect the amount of cash eventually realized.
Future development and production costs are computed by estimating the
expenditures to be incurred in developing and producing the proved oil and gas
reserves at the end of the year, based on period-end costs and assuming
continuation of existing economic conditions.
Future income tax expenses are computed by applying the appropriate year-end
statutory tax rates and existing tax credits, with consideration of future tax
rates already legislated, to the future pretax net cash flows relating to the
Company's proved oil and gas reserves.
An annual discount rate of 10% was used to reflect the timing of the future net
cash flows relating to proved oil and gas reserves.
Information with respect to the Company's estimated discounted future net cash
flows related to its proved oil and gas reserves as of June 30 is as follows (in
thousands):
<TABLE>
<CAPTION>
2000 1999 1998
---------- ---------- ----------
<S> <C> <C> <C>
Future cash in flows $ 606,382 $ 396,466 $ 412,866
Future production and development costs (178,968) (144,274) (151,068)
Future income tax expense (121,000) (47,000) (48,241)
---------- ---------- ----------
Future net cash flows before discount 306,414 205,192 213,557
10% discount to present value (181,543) (120,309) (138,644)
---------- ---------- ----------
Standardized measure of discounted future net cash
flows related to proved oil and gas reserves $ 124,871 $ 84,883 $ 74,913
========== ========== ==========
Companyshare of equity method investee
standardized measure of discounted future net
cash flows $ 54,362 $ 28,129 $ 19,975
========== ========== ==========
</TABLE>
44
<PAGE>
Principal changes in the standardized measure of discounted future net cash
flows for the years ended June 30 are as follows (in thousands):
<TABLE>
<CAPTION>
2000 1999 1998
--------- -------- ---------
<S> <C> <C> <C>
Standardized measure of discounted future
net cash flows at beginning of period $ 84,883 $74,913 $100,353
Sales of oil and gas produced, net of
production costs (13,446) (8,059) (11,111)
Net changes in prices and production costs 57,741 (1,107) (8,192)
Changes in production rates and other (10.418) 5,421 (33,132)
Extensions, discoveries and other additions, net
of future production and development costs 2,886 3,977 5,657
Changes in estimated future development costs 2,099 2,701 (1,495)
Development costs incurred 5,869 7,527 9,336
Revisions of previous quantity estimates 5,731 (2,234) (809)
Purchase of reserves in place 10,572 1,126
Sales of reserves in place (918) (55)
Accretion of discount 8,488 7,491 10,035
Net change in income taxes (29,534) (4,829) 3,200
--------- -------- ---------
Standardized measure of discounted
future net cash flows at end of period $124,871 $84,883 $ 74,913
========= ======== =========
</TABLE>
* * * * *
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
------- ----------------------------------------------
ON ACCOUNTING AND FINANCIAL DISCLOSURE
--------------------------------------
There have been no changes in or disagreements with accountants on accounting
and financial disclosure.
45
<PAGE>
PART III
--------
ITEM 10. DIRECTORS AND OFFICERS OF REGISTRANT
-------- ------------------------------------
The executive officers and Directors of the Company and the executive
officers of its subsidiaries on June 30, 2000 are listed below, together with a
description of their experience and certain other information. All of the
Directors were re-elected for a one year term at the Company's December 1999
annual meeting of stockholders. Executive officers are appointed by the Board
of Directors.
<TABLE>
<CAPTION>
Name Age Position with Company or Subsidiary
----------------------- --- --------------------------------------------------------------
<S> <C> <C>
John Mork 52 President and Chief Executive Officer of the Company; Director
Joseph E. Casabona 57 Executive Vice President of the Company; Director
Michael S. Fletcher 51 Chief Financial Officer and Treasurer of the Company;
President of Mountaineer
J. Michael Forbes 40 Vice President of the Company
Donald C. Supcoe 44 Secretary of the Company; Senior Vice President of Mountaineer
Pamela T. Gates 53 Assistant Secretary of the Company
Edward J. Davies 58 President of Westech
W. Gaston Caperton, III 60 Director
Peter H. Coors 53 Director
L. B. Curtis 76 Director
John J. Dorgan 76 Director
Arthur C. Nielsen, Jr. 81 Director
F. H. McCullough, III 53 Director
Julie Mork 50 Director
</TABLE>
W. Gaston Caperton, III, has been a Director of the Company since 1997. He
served as the Governor of the State of West Virginia for two terms, from 1989 to
1997. Governor Caperton is President and Chief Executive Officer of The College
Board and President of the Caperton Group. Governor Caperton presently serves
on the Boards of Directors of Owens Corning and United Bankshares.
Joseph E. Casabona is Executive Vice President of the Company and has been
a Director since its formation. Mr. Casabona joined Eastern American in 1985
and was Executive Vice President of Eastern American and a Director from 1987
until 1993. Mr. Casabona was employed in various audit staff capacities from
1967 to 1979 in the Pittsburgh, Pennsylvania office of KPMG Main Hurdman ("KPMG,
Peat Marwick"), became a partner in the Firm in 1980 and was named Director of
Accounting and Auditing of the Pittsburgh office in 1983. Mr. Casabona
graduated from the University of Pittsburgh with a Bachelor of Science Degree in
Business Administration and from the Colorado School of Mines with a Master of
Science Degree in Mineral Economics. Mr. Casabona has been a Certified Public
Accountant since 1969. Mr. Casabona has been a member of the Boards of
Directors of the West Virginia and Pennsylvania Independent Oil and Gas
Associations.
Peter H. Coors has been a Director of the Company since 1996. Mr. Coors is
Chairman of the Board and Chief Executive Officer of Coors Brewing Company and
Chief Executive Officer of Adolph Coors Company. He received his Bachelor
Degree in Industrial Engineering from Cornell University in 1969 and he earned
his Master Degree in Business Administration from the University of Denver in
1970. Mr. Coors also serves on the Board of Directors of USBank Corp.
46
<PAGE>
L.B. Curtis has been a Director of the Company since 1993. Mr. Curtis was
a Director of Eastern American from 1988 until 1993. Mr. Curtis is retired from
a career at Conoco, Inc. where he held the position of Vice President of
Production Engineering with Conoco Worldwide. Mr. Curtis was highly recognized
across the Petroleum Industry in the upstream (exploration and production)
segment of the industry. Mr. Curtis graduated from The Colorado School of Mines
with an Engineer of Petroleum Professional degree.
Edward J. Davies has been President of Westech and Managing Director of
Westech Energy New Zealand since 1994. Previously, Mr. Davies was with Conoco
Inc., where his most recent positions were General Manager Exploration and
Managing Director Nigeria. Mr. Davies holds a Bachelor of Science in Geology
from the University of Wales, a Doctor of Philosophy in Geology from the
University of Alberta, and a Master of Science from the Massachusetts Institute
of Technology Sloan School of Management.
John J. Dorgan has been a Director of the Company since 1993. He served as
a Director for Eastern American in 1992. He is a former Executive Vice
President and consultant to Occidental Petroleum Corporation where he had worked
in various capacities since 1972.
Michael S. Fletcher has been Chief Financial Officer and Treasurer of the
Company since December 1999. In addition, Mr. Fletcher has been President of
Mountaineer since August 1998. Prior to that time, he also held the positions
of Senior Vice President and Chief Financial Officer of Mountaineer. Before
joining Mountaineer in 1987, Mr. Fletcher was a partner of Arthur Andersen and
Company and was employed by that firm for fifteen years. Mr. Fletcher is a
Certified Public Accountant and a board member for the Board of Risk and
Insurance Management for the State of West Virginia. Mr. Fletcher graduated
from Utah State University with a Bachelor Degree in Accounting.
J. Michael Forbes has been Vice President of the Company since 1995. Prior
to that, Mr. Forbes was an officer with Eastern American, which he joined in
1982. Mr. Forbes graduated with a Bachelor of Arts in Accounting and Finance
from Glenville State College and is a Certified Public Accountant. He also
holds a Master of Business Administration from Marshall University and is a
graduate of Stanford University's Program for Chief Financial Officers.
Pamela T. Gates has been Assistant Secretary of the Company since 1999. Ms.
Gates joined the Company in 1984 and is employed as an Executive Assistant.
F. H. McCullough, III, has been a Director of the Company since 1993. Mr.
McCullough was a Director of Eastern American from 1978 until 1993. Mr.
McCullough joined Eastern American in 1977 and served in various capacities
until 1999. He is currently President of Neumedia, Inc. of Charleston, West
Virginia, a fiber optic carrier. Mr. McCullough is a graduate of the University
of Southern California with a Bachelor of Arts Degree in International Economics
and two Masters Degrees in Business Administration and Financial Systems
Management. He is a graduate of the Northwestern University Kellogg Graduate
School of Management Executive Marketing Program.
John Mork has been President and Chief Executive Officer of the Company and a
Director of the Company since its formation. Mr. Mork served in various
capacities at Union Oil Company until 1972 when he joined Pacific States Gas and
Oil, Inc. and subsequently founded Eastern American. Mr. Mork was President and
a Director of Eastern American from 1973 until 1993. Mr. Mork is a past
47
<PAGE>
Director of the Independent Petroleum Association of America, and the
Independent Oil and Gas Association of West Virginia. He was chapter chairman
of the Young Presidents' Organization, Inc., Rocky Mountain Chapter in
1994-1995. Mr. Mork also founded the Mountain State Chapter of the Young
Presidents' Organization located in Charleston, West Virginia. Mr. Mork holds a
Bachelor of Science Degree in Petroleum Engineering from the University of
Southern California and he is a graduate of the Stanford Business School Program
for Chief Executive Officers. He is the husband of Julie Mork.
Julie M. Mork has been a Director of the Company since 1993. She was a
Director of Eastern American from 1974 until 1993. Mrs. Mork served as a
founder and Secretary/Treasurer of Pacific States Gas and Oil, Inc. and Eastern
American. Mrs. Mork received a Bachelor of Arts Degree in History from the
University of California in Los Angeles. She is the wife of John Mork.
Arthur C. Nielsen, Jr. has been a Director of the Company since 1993. He
was a Director of Eastern American from 1985 until 1993. He serves on the Board
of Directors of General Binding Corporation.
Donald C. Supcoe has been the Senior Vice President of Mountaineer since
August 1998 and has served as the Corporate Secretary of the Company since
December 1998. Prior to joining Mountaineer in August of 1998, he was the Vice
President, General Counsel and Secretary of Eastern American with whom he had
been employed since 1981. Mr. Supcoe is a past President of the Independent Oil
and Gas Association of West Virginia and a past Vice President of the
Independent Petroleum Association of America. Mr. Supcoe graduated from West
Virginia University with a Bachelor of Science Degree in Business
Administration. Mr. Supcoe received a Doctor of Jurisprudence Degree from West
Virginia University College of Law.
48
<PAGE>
ITEM 11. EXECUTIVE COMPENSATION
-------- ----------------------
The following table sets forth for fiscal year 2000 the total value of
compensation of (i) the Company's Chief Executive Officer and (ii) each other
executive officer of the Company.
<TABLE>
<CAPTION>
Salary Bonus Other Total
-------- -------- ------- --------
<S> <C> <C> <C> <C> <C>
John Mork $253,141 $116,350 $40,051 (1) $409,542
President and Chief Executive Officer
Joseph E. Casabona 223,762 55,853 11,363 (2) 290,978
Executive Vice President
Michael S. Fletcher 228,298 168,702 30,053 (3) 427,053
Chief Financial Officer and Treasurer
President of Mountaineer Gas Company
Edward J. Davies 184,885 31,000 5,587 (4) 221,472
President of Westech Energy Corporation
Donald C. Supcoe 180,833 41,599 28,203 (5) 250,635
Senior Vice President of Mountaineer Gas Company
_______________
<FN>
(1) Includes $7,141 in compensation related to insurance policies provided for the benefit of
John Mork, $29,041 for personal use of company owned assets and $3,869 in 401K
matching contributions.
(2) lncludes $5,377 in compensation related to insurance policies provided for the benefit of
Joseph E. Casabona, $2,603 for personal use of company owned assets and $3,383
in 401K matching contributions.
(3) Includes $552 in compensation related to an insurance policy provided for the benefit of
Michael S. Fletcher, $19,496 for personal use of company owned assets and $10,005
for employee dependent tuition assistance.
(4) Includes $681 in compensation related to an insurance policy provided for the benefit of
Edward J. Davies, $1,507 for personal use of company owned assets and $3,399 in
401K matching contributions.
(5) Includes $216 in compensation related to an insurance policy provided for the benefit of
Donald C. Supcoe, and $27,987 for personal use of company owned assets.
</TABLE>
ITEM 12. SECURITY OWNERSHIP OF CERTAIN
-------- -----------------------------
BENEFICIAL OWNERS AND MANAGEMENT
--------------------------------
The following table sets forth certain information regarding (i) the share
ownership of the Company by each person known to the Company to be the
beneficial owner of more than 5% of the outstanding shares of Common Stock, (ii)
the share ownership of the Company by each Director, (iii) the share ownership
of the Company by certain executive officers and (iv) the share ownership of the
Company by all directors and executive officers as a group, in each case as of
September 1, 2000. The business address of each officer and director listed
below is: c/o Energy Corporation of America, 4643 S. Ulster, Suite 1100,
Denver, Colorado 80237.
49
<PAGE>
<TABLE>
<CAPTION>
Beneficial Ownership
Common Stock
-------------------
Number
of Shares Percent
--------- --------
<S> <C> <C>
Kenneth W. Brill (1) 63,610 9.79%
W. Gaston Caperton, III 480 *
Joseph E. Casabona 30,376 4.68%
Peter H. Coors 946 *
L. B. Curtis 10,660 1.64%
John J. Dorgan 1,130 *
F. H. McCullough, III (3) 90,485 13.93%
John Mork (2) 369,943 56.95%
Julie Mork (2) 369,943 56.95%
Arthur C. Nielsen, Jr. 36,480 5.62%
Donald C. Supcoe 3,200 *
All officers and Directors as a group (11 persons) 607,310 93.49%
_______________
<FN>
* Less than one percent.
(1) Pursuant to agreements dated June 30, 1993 and July 8, 1996, Kenneth W.
Brill granted the Company options to purchase 15,400 and 75,850 shares,
respectively, of the Company Common Stock owned by him, of which 31,650
have been purchased by the Company.
(2) Includes 361,380 shares held by John and Julie Mork as joint tenants,
2,663 shares held by Julie Mork individually, and 2,950 shares held by
each of the Alison Mork Trust and the Kyle Mork Trust.
(3) Includes 88,405 shares held by F.H. McCullough, III and Kathy McCullough
as joint tenants, 880 shares held by the Katherine F. McCullough Trust,
and 400 shares held by each of the Lesley McCullough Trust, the Meredith
McCullough Trust and the Kristin McCullough Trust.
</TABLE>
The following table sets forth certain information regarding (i) the share
ownership of the Company by each person known to the Company to be the
beneficial owner of more than 5% of the outstanding shares of Class A Stock,
(ii) the share ownership of the Company's Class A Stock by each Director, (iii)
the share ownership of the Company's Class A Stock by certain executive officers
and (iv) the share ownership of the Company's Class A Stock by all directors and
executive officers as a group, in each case as of September 1, 2000. The
business address of each officer an director listed below is: c/o Energy
Corporation of American, 4643 South Ulster Street, Suite 1100, Denver, Colorado
80237.
50
<PAGE>
<TABLE>
<CAPTION>
Beneficial Ownership
Class A Stock
-------------------
Number
of Shares Percent
--------- --------
<S> <C> <C>
Joseph E. Casabona 5,791 30.02%
Edward J. Davies 4,542 23.54%
Michael S. Fletcher 2,250 11.60%
John Mork (1) 796 4.13%
Julie Mork (1) 796 4.13%
Arthur C. Nielsen, Jr. 1,160 6.01%
Donald C. Supcoe 1,667 8.64%
All officers and Directors as a group (7 persons) 16,206 83.94%
_______________
<FN>
* Less than one percent
(1) Includes 796 shares held by John and Julie Mork as joint tenants.
</TABLE>
ITEM 13. CERTAIN RELATIONSHIPS AND
-------- -------------------------
RELATED TRANSACTIONS
--------------------
Certain officers and Directors of the Company and members of their families
regularly participate in the wells drilled by the Company on an actual costs
basis and share in the costs and revenues on the same basis as the Company. The
Company has the right to select the wells drilled and each participant is
involved in all wells included within a Company drilling program (the "Drilling
Program") and cannot selectively choose the wells in which to participate. The
Company typically has a development drilling component and an
exploration-drilling component within each year's Drilling Program. The
officers and Directors and their family members may participate in either or
both of the components. The following table identifies the participants'
aggregate investment in the calendar years shown (in thousands):
51
<PAGE>
<TABLE>
<CAPTION>
(4) (5)
2000 1999 1998
------- ------ ------
<S> <C> <C> <C>
Dale P. Andrews $ 12 $ 11 $ 13
K.W. Brill 60 174
Gaston Caperton 100 392
Joseph E. Casabona 50 37 52
Peter Coors 50 28 52
L.B. Curtis 129 70 109
E.J. Davies 129 113 101
John J. Dorgan 25 43 52
Michael S. Fletcher 50
J. Michael Forbes 8
Richard L. Grant 28
F.H. McCullough, III 85 160
Lesley McCullough Trust (2) 8
Kristen McCullough Trust (2) 8
Meredith McCullough Trust (2) 8
Katherine McCullough Trust (2) 8
John Mork (1) 771 351 799
Alison Mork Trust (3) 25 28 41
Kyle Mork Trust (3) 25 28 41
Arthur C. Nielsen, Jr. 50 43 139
Kent Schamp 26
Donald C. Supcoe 8
ECA Foundation 78
------- ------ ------
Total $1,442 $ 897 $2,279
======= ====== ======
<FN>
_______________
(1) Interest of John Mork and Julie Mork held as joint tenants.
(2) Trusts for minor children of F. H. McCullough, III and Kathy L. McCullough.
(3) Trusts for minor children of John Mork and Julie Mork.
(4) These amounts represent only the amounts committed to the 2000 Drilling
Program, the actual investment may vary.
</TABLE>
Certain officers, Directors and key employees of the Company have notes
payable to the Company related to employee incentive stock options that were
granted and exercised. The notes bear various interest rates, ranging from
LIBOR to 8% per annum. As of June 30, 2000, in excess of $60,000, the following
were indebted to the Company (in thousands):
<TABLE>
<CAPTION>
<S> <C>
Dale P. Andrews $ 63
Joseph E. Casabona 187
Edward J. Davies 319
J. Michael Forbes 96
Michael S. Fletcher 187
Donald C. Supcoe 209
------
Total $1,061
======
</TABLE>
52
<PAGE>
Certain officers and Directors of the Company have borrowed money from the
Company and have executed promissory notes. The notes bear interest at 8% per
annum. As of June 30, 2000, the following were indebted to the Company (in
thousands):
<TABLE>
<CAPTION>
<S> <C>
Michael S. Fletcher * $115
<FN>
_______________
* Promissory note is being forgiven over three years, assuming
continuing employment.
</TABLE>
During fiscal 1999, the Company purchased from certain officers and
directors volumetric production from wells in New Zealand. Future production,
otherwise allocable to the officers and directors will be allocated to the
Company. The following table identifies the participants' interest:
<TABLE>
<CAPTION>
Payment Volumes
(in thousands) Mmcf
--------------- -------
<S> <C> <C>
Dale P. Andrews $ 20 26.7
K.W. Brill 200 266.7
Gaston Caperton 600 800.0
Joseph E. Casabona 50 66.7
Peter Coors 50 66.7
L.B. Curtis 150 200.0
E.J. Davies 150 200.0
John J. Dorgan 50 66.7
Thomas R. Goodwin 50 66.7
Richard L. Grant 50 66.7
F.H. McCullough, III 150 200.0
John Mork 750 1,000.0
Alison Mork Trust 50 66.7
Kyle Mork Trust 50 66.7
Arthur C. Nielsen, Jr. 94 125.3
--------------- -------
Total $ 2,464 3,285.6
=============== =======
</TABLE>
The Company rents office space in Charleston, West Virginia from Energy
Centre, Inc. a corporation owned 42.86% by John Mork, 21.42% by each of F. H.
McCullough, III and Joseph E. Casabona and 7.15% by each of Donald C. Supcoe and
J. Michael Forbes. The aggregate amount paid by the Company for rent to Energy
Centre, Inc. was $415,700 for fiscal year 2000. The Company believes that such
rental terms are no less favorable than could have been obtained from an
unaffiliated party.
53
<PAGE>
PART IV
-------
ITEM 14. EXHIBITS, FINANCIAL STATEMENT
-------- -----------------------------
SCHEDULES AND REPORTS ON FORM 8-K
---------------------------------
(a)1. Financial Statements
The Financial Statements are filed as a part of this annual report
at Item 8.
2. Financial Statement Schedules
The Financial Statements are filed as a part of this annual report
at Item 8.
3. Exhibits
The following is a complete list of Exhibits filed as part of, or
incorporated by reference to this Registration Statement:
* 3.1 Articles of Incorporation of Energy Corporation of America.
* 3.2 Amended Articles of Incorporation of Energy Corporation of
America.
* 3.3 Amended Bylaws of Energy Corporation of America.
* 4.1 Credit Agreement among Energy Corporation of America, General
Electric Capital Corporation as Agent, and the lenders
named therein, dated as of May 20, 1997.
* 4.2 Note Purchase Agreement between Mountaineer Gas Company and
The John Hancock Mutual Life Insurance Company dated as of
October 12, 1995.
* 4.3 Indenture, dated as of May 23, 1997, between Energy
Corporation of America and The Bank of New York, as Trustee,
with respect to the 9 1/2% Senior Subordinated Notes Due 2007
(including form of 9 1/2% Senior Subordinated Note Due 2007.
* 4.4 Form of 9 1/2% Senior Subordinated Note due 2007, Series A.
4.5 Registration Rights Agreement, dated as of May 20, 1997,
among Energy Corporation of America, as issuer, and Chase
Securities Inc. and Prudential Securities Inc.
* 10.1 Eastern American Energy Corporation Profit/Incentive Stock
Plan dated as of June 4, 1997.
* 10.2 Buy-Sell Stock Option Agreement dated as of May 19, 1997
among Energy Corporation of America, F.H. McCullough, III
and Kathy L. McCullough.
* 10.3 Buy-Sell Stock Option Agreement dated as of July 8, 1996
between Energy Corporation of America and Kenneth W. Brill.
* 10.4 Gas Purchase Contract dated as of January 1, 1993 between
Eastern American Energy Corporation and Eastern Marketing
Corporation.
* 10.5 FTSI Service Agreement No. 37994 dated as of November 1,1993
between Mountaineer Gas Company and Columbia Gulf
Transmission Company.
54
<PAGE>
* 10.6 Service Agreement No. 42794 dated as of November 1,1994
between Mountaineer Gas Company and Columbia Gulf
Transmission Company.
* 10.7 SST Service Agreement No. 38087 dated as of November 1,1993
between Mountaineer Gas Company and Columbia Gas
Transmission Corporation.
* 10.8 FTS Service Agreement No. 38137 dated as of November 1,1993
between Mountaineer Gas Company and Columbia Gas
Transmission Corporation. (Previously misidentified as FTS
Service Agreement No. 38037)
* 10.9 Supplement No. 1 to Transportation Service Agreement No.
38137 dated as of May 6, 1994 between Mountaineer Gas
Company and Columbia Gas Transmission Corporation.
* 10.10 FSS Service Agreement No. 38077 dated as of November 1,1993
between Mountaineer Gas Company and Columbia Gas
Transmission Corporation.
* 10.11 NTS Service Agreement No. 39272 dated as of November 1,1993
between Mountaineer Gas Company and Columbia Gas
Transmission Corporation.
* 10.12 FTS Service Agreement No. 38113 dated as of November 1,1993
between Mountaineer Gas Company and Columbia Gas
Transmission Corporation.
* 10.13 Supplement No. 1 to Transportation Service Agreement No.
38113 dated as of May 6, 1994 between Mountaineer Gas
Company and Columbia Gas Transmission Corporation.
* 10.14 Gas Transportation Agreement dated as of October 1, 1994
between Mountaineer Gas Company and Tennessee Gas
Pipeline Company.
* 10.15 Amendment No. 1 to Gas Transportation Agreement dated as of
May 5, 1995 between Mountaineer Gas Company and
Tennessee Gas Pipeline Company.
* 10.16 FTS Service Agreement No. 60266 dated May 20, 1998 between
Mountaineer Gas Company and Columbia Gas Transmission
Corporation.
* 10.17 Incentive Stock Purchase Agreement dated February 12, 1999
by and between Energy Corporation of America and Michael
S. Fletcher.
* 10.18 Incentive Stock Purchase Agreement dated December 16, 1998
by and between Energy Corporation of America and Joseph
E. Casabona.
* 10.19 Incentive Stock Purchase Agreement dated December 16, 1998
by and between Energy Corporation of America and Edward
J. Davies.
* 10.20 Incentive Stock Purchase Agreement dated December 16, 1998
by and between Energy Corporation of America and Donald
C. Supcoe.
* 10.21 Incentive Stock Purchase Agreement dated March 19, 1999 by
and between Energy Corporation of America and W. Gaston
Caperton III.
* 10.22 Incentive Stock Purchase Agreement dated March 19, 1999 by
and between Energy Corporation of America and Peter
H. Coors.
* 10.23 Incentive Stock Purchase Agreement dated March 19, 1999 by
and between Energy Corporation of America and L.B.
Curtis.
* 10.24 Incentive Stock Purchase Agreement dated March 19, 1999 by
and between Energy Corporation of America and J. J.
Dorgan.
55
<PAGE>
* 10.25 Incentive Stock Purchase Agreement dated March 19, 1999 by
and between Energy Corporation of America and A. C.
Nielsen, Jr.
* 10.26 Stock Purchase Agreement dated February 17, 1999 by and
among Westech Energy Corporation, Westech Energy New Zealand
Limited and Edward J. Davies.
* 10.27 First Amendment to Credit Agreement and Assignment and
Waiver dated September 26, 1997 by and among Energy
Corporation of America, General Electric Capital
Corporation, The Bank of Nova Scotia, and Union Bank of
California, N.A.
* 10.28 Second Amendment to Credit Agreement dated April 2, 1999
by and among Energy Corporation of America, General Electric
Capital Corporation, The Bank of Nova Scotia, and Union Bank
of California, N.A.
* 10.29 Third Amendment to Credit Agreement dated September 27,
1999 by and among Energy Corporation of America, General
Electric Capital Corporation, The Bank of Nova Scotia,
and Union Bank of California, N.A.
* 10.30 Natural Gas Supply management Agreement dated September 20,
1998 by and between Coral Energy Resources, L.P., Coral
Energy, L.P. and Mountaineer.
10.31 Gas Sale and Purchase Agreement dated December 20, 1999
between Energy Corporation of America and Allegheny Energy
Service Corporation.
10.32 Participation Agreement dated December. 20, 1999 between
Energy Corporation of America and Allegheny Energy, Inc.
10.33 Management Agreement dated December 20, 1999 between Energy
Corporation of America and Allegheny Energy , Inc.
10.34 Oil and Gas Lease and Development Agreement dated August 16,
2000 between Allegheny Energy, Inc., Monongahela Power
Company, West Virginia Power and Transmission Company, and
Energy Corporation of America.
10.35 Employment Agreement effective as of August 18, 2000 by and
between Energy Corporation of America and Michael S.
Fletcher.
10.36 Employment Agreement effective as of August 18, 2000 by and
between Energy Corporation of America and Donald C. Supcoe.
21.1 Subsidiaries of Energy Corporation of America.
25.1 Power of Attorney set forth on the signature page contained
in Part V.
27.1 Financial Data Schedule.
previously filed
56
<PAGE>
(b) Reports on Form 8-K
The Company filed a report on Form 8-K, Item 5, dated January 10, 2000,
reporting the arrangement to enter into a stock purchase agreement to sell
its utility operations, Mountaineer Gas Company, to Allegheny Energy, Inc.
The Company filed a report on Form 8-K, Item 2, dated August 18, 2000
reporting the sale of its utility operations, Mountaineer Gas Company,
to Allegheny Energy, Inc.
The Company filed a report on Form 8-K, Item 5, dated August 18, 2000
reporting the decision to terminate its revolving credit facility with
General Electric Capital Corporation.
* * * * *
57
<PAGE>
PART V
------
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto, duly authorized, on the 27th day of
September 2000.
ENERGY CORPORATION OF AMERICA
By: /s/ John Mork
-----------------------------------------
John Mork
President and Chief Executive Officer
58
<PAGE>
POWER OF ATTORNEY
-----------------
Each of the undersigned officers and directors of Energy Corporation of
America (the "Company") hereby constitutes and appoints John Mork, Joseph E.
Casabona and Michael S. Fletcher and each of them (with full power to each of
them to act alone), his true and lawful attorney-in-fact and agent, with full
power of substitution, for him and on his behalf and in his name, place and
stead, in any and all capacities, to sign, execute and file this Form 10-K under
the Securities Act of 1934, as amended, and any or all amendments (including,
without limitation, post-effective amendments), with all exhibits and any and
all documents required to be filed with respect thereto, with the Securities and
Exchange Commission or any regulatory authority, granting unto such
attorneys-in-fact and agents, and each of them acting alone, full power and
authority to do and perform each of every act and thing requisite and necessary
to be done in and about the premises in order to effectuate the same, as full to
all intents and purposes as he himself might or could do if personally present,
hereby ratifying and confirming all the such attorneys-in-fact and agents, or
any of them, or their substitute or substitutes, may lawfully do or cause to be
done.
Pursuant to the requirements of the Securities Act of 1934, this Form 10-K has
been signed on the ___ day of September 2000, by the following persons in the
capacities indicated.
59
<PAGE>
<TABLE>
<CAPTION>
Signature Title
-------------------------- ------------------------------------------------
<S> <C>
/s/ John Mork
--------------------------
John Mork President, Chief Executive Officer and Director
(Principal executive officer)
/s/ Joseph E. Casabona
--------------------------
Joseph E. Casabona Executive Vice President and Director
/s/ Michael S. Fletcher
--------------------------
Michael S. Fletcher Chief Financial Officer and Treasurer
(Principal accounting and financial officer)
/s/ F. H. McCullough III
--------------------------
F. H. McCullough III Director
/s/ Gaston Caperton
--------------------------
Gaston Caperton Director
/s/ Peter H. Coors
--------------------------
Peter H. Coors Director
/s/ L. B. Curtis
--------------------------
L. B. Curtis Director
/s/ John J. Dorgan
--------------------------
John J. Dorgan Director
/s/ Julie Mork
--------------------------
Julie Mork Director
/s/ Arthur C. Nielsen, Jr.
--------------------------
Arthur C. Nielsen, Jr. Director
</TABLE>
60
<PAGE>
