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, 2002.
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 [ ]
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 number of shares and market value of common stock held by
non-affiliates of the registrant at August 31, 2002 was 40,200 shares. The
market value held by non-affiliates is unavailable.
The number of shares of the registrant's common stock, par value $1.00 per
share, outstanding at August 31, 2002 was 624,467 shares.
DOCUMENTS INCORPORATED BY REFERENCE:
NONE
2
ENERGY CORPORATION OF AMERICA
TABLE OF CONTENTS
Page
Part I
Item 1. Business. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Item 2. Properties. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Item 4. Submission of Matters to a Vote of Security Holders . . . . . . . . . . . 11
Part II
Item 5. Market for the Registrant's Common Stock and Related Stockholder Matters. 11
Item 6. Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . 12
Item 7. Management's Discussion and Analysis of Results of Operations
and Financial Condition . . . . . . . . . . . . . . . . . . . . . . . . . 12
Item 7A. Quantitative and Qualitative Disclosures About Market Risk. . . . . . . . 24
Item 8. Consolidated Financial Statements and Supplementary Data
Independent Auditors' Report. . . . . . . . . . . . . . . . . . . . . . 25
Balance Sheets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Statements of Operations. . . . . . . . . . . . . . . . . . . . . . . . 28
Statements of Stockholders Equity (Deficit) . . . . . . . . . . . . . . 29
Statements of Cash Flows. . . . . . . . . . . . . . . . . . . . . . . . 30
Statements of Comprehensive Income. . . . . . . . . . . . . . . . . . . 31
Notes to Consolidated Financial Statements. . . . . . . . . . . . . . . 32
Supplemental Information on Oil and Gas Producing Activities (Unaudited) 46
Item 9. Changes In and Disagreements With Accountants on Accounting
and Financial Disclosure. . . . . . . . . . . . . . . . . . . . . . . . . 50
Part III
Item 10. Directors and Officers of Registrant. . . . . . . . . . . . . . . . . . . 50
Item 11. Executive Compensation. . . . . . . . . . . . . . . . . . . . . . . . . . 53
Item 12. Security Ownership of Certain Beneficial Owners and Management. . . . . . 53
Item 13. Certain Relationships and Related Transactions. . . . . . . . . . . . . . 55
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K . . . . . 58
Part V
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61
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 thousand cubic feet equivalent (Mcfe),
million 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
PART I
------
ITEM 1. BUSINESS
----------------
GENERAL
- -------
Energy Corporation of America (the "Company") is a privately held energy
company engaged in the exploration, 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, 2002 ("fiscal year 2002"), the Company had total
revenues from continuing operations of $86.1 million and EBITDAX (earnings
before interest, income taxes, impairment and exploratory costs, depreciation,
depletion and amortization) from operations of $19.7 million. As used herein
the "Company" refers to the Company alone or together with one or more of its
subsidiaries.
The Company conducts business primarily 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
California and Gulf Coast regions of the United States. WENZ is involved in oil
and gas exploration and development in New Zealand.
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.
BUSINESS ACTIVITY
- -----------------
SEGMENT INFORMATION
- -------------------
The Company's businesses constitute two operating segments (1) gas and oil
exploration and development and (2) gas aggregation and marketing. For
financial information on these segments, see Note 16 to the Consolidated
Financial Statements.
GAS AND OIL EXPLORATION AND DEVELOPMENT
- --------------------------------------------
OPERATIONS AND SIGNIFICANT DEVELOPMENTS
The Company's proved net gas and oil reserves are estimated as of June 30,
2002 at 183,345 Mmcf and 2,951 Mbbls, respectively. For the fiscal year 2002,
the Company's net gas production was 9,941 Mmcf and net oil production was 124
Mbbls, for a total of 10,685 net Mmcfe.
DEVELOPMENT ACTIVITY
The Company has drilled 54 gross wells (48.15 net), with one dry hole,
adding 3,000 gross Mcf of gas production per day. Also, a deposit of $1.2
million was paid for the purchase of certain oil and gas properties located in
southern West Virginia. The total acquisition will be $6.0 million. The
purchase includes proved developed producing gas reserves, estimated at 4 Bcf,
90 producing wells and over 30,000 acres. This acquisition is subject to the
approval of the Public Service Commission of West Virginia.
4
EXPLORATORY ACTIVITY
Exploration wells and activity are summarized under their respective
project areas.
1. Trenton/Rose Run -- New York, West Virginia, Ohio, Kentucky. The
Company drilled three successful Rose Run wells and one dry hole during the
fiscal year. Two of the successful wells are located in northern Ohio where the
Company is a 50% partner. Current production from the two wells is in excess of
1,500 Mcf per day. Additional 2-D and 3-D seismic is being planned for this area
during the next fiscal year. The third Rose Run success is located in central
Ohio, where the Company has a 50% interest. The Company also drilled four
Trenton wells during the fiscal year. The first Trenton well drilled in the
northern Ohio area was unsuccessful in the Trenton, but resulted in a successful
Clinton completion. The first Trenton well drilled in the central West Virginia
is a discovery. Completion options are currently being evaluated. One Trenton
well in New York and one Trenton well in Kentucky were dry holes.
2. Texas. The Company drilled two successful wells, one completed in the
Frio formation and the other completed in the Yegua. The Company's net interest
in the wells is 40%. The wells are producing approximately 2,000 Mcf per day.
The Company drilled two deeper wells to the Wilcox / Meek formation which were
completed but were not economically successful.
3. New Zealand. The Company drilled from onshore a stratigraphic test
of the offshore license. This well was unsuccessful, but satisfied the offshore
permit drilling requirement. The Company is continuing its efforts to farmout
the East Coast offshore prospects.
4. California. The Company participated in the drilling of two field
extension wells in the Sawtelle Field. One well currently is producing
approximately 75 Bbl per day and the second well was a dry hole. The Company's
interest is 33%.
COMPETITION
The Company encounters substantial competition in acquiring properties,
marketing oil and gas, securing drilling 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,
5
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. 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. The Company
believes it is within substantial compliance with regulations affecting the
Company.
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 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 owns and operates approximately 2,000 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, 2002, Eastern Marketing aggregated and sold an average of 44.2 Mmcf of gas
per day, of which 41.3 gross Mmcf per day represented sales of gas produced from
wells operated by the Company. This represents a slight decrease in the overall
volumes compared to fiscal year 2001, during which the Eastern Marketing
aggregated and sold an average of 44.7 Mmcf of gas per day. The increase in
sales from Company operated wells from 38.6 in 2001 to 41.3 Mmcf in 2002 is due
to the integration of production from the Penn Virginia acquisition into
marketing sales.
GAS SALES AND PURCHASE CONTRACTS
The Company has satisfied its obligations under all gas sales contracts
(16.1 Bcf in fiscal year 2002) 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 (15.1 Bcf in fiscal 2002), and from
natural gas aggregated by the Company pursuant to its aggregation and marketing
activities from third parties (1.0 Bcf in fiscal 2002).
The Company entered into a gas sale and purchase agreement with Allegheny
Energy Services Corporation ("Allegheny"), whereby it began the delivery of
natural gas on November 1, 2001. The Company received a $10 million prepayment
pursuant to the agreement. 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 Company's deliveries of natural
gas average 3,100 Mmbtu per day. As of June 30, 2002, 752,940 Mmbtu had been
delivered at a value of $2.3 million.
On November 30, 2001, the Company entered into a natural gas sales contract
with Mountaineer Gas Company, doing business as Allegheny Power, to deliver
5,500 Dth per day. Under the pricing terms, the Company will never receive less
6
than $2.75 per Dth plus the Columbia Gas Transmission ("TCO") Appalachia Basis
or more than $4.85 per Dth plus the TCO Appalachia Basis. The contract began on
December 1, 2001 and continues through October 31, 2004.
The Company has a gas sales contract with Dominion Hope ("Hope"), a
subsidiary of Dominion Energy, which requires the Company to sell up to 4,800
but not less than 3,200 Mmbtu per day to Hope beginning January 1, 2002 through
December 31, 2003. Pricing under the contract requires Hope to pay the Company a
10.5 cent to 15.5 cent premium above the posted Appalachian Index.
In March 1993, the Company 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.
Beginning 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 14 to the Consolidated Financial
Statements 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 Federal Energy Regulatory Commission. 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, 2002, the Company had approximately 213 full-time and 28
part-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
------------------
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
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. 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:
7
2002 2001 2000
-------- -------- --------
Net proved:
Gas (Mmcf) 183,345 206,456 157,490
Oil (Mbbls) 2,951 2,633 983
Total (Mmcfe) 201,051 222,254 163,388
Net proved developed:
Gas (Mmcf) 160,224 175,784 141,067
Oil (Mbbls) 1,135 987 738
Total (Mmcfe) 167,034 181,706 145,495
Estimated future net cash flows
before income taxes (in thousands) $471,927 $557,352 $427,414
Present Value of estimated future net cash
flows after income taxes (in thousands) (1) $150,913 $172,281 $124,871
- ---------------
(1) Discounted using an annual discount rate of 10%.
The following table sets forth the Company's estimated proved reserves and
the related estimated present value by region, as of June 30, 2002:
Present Value
-------------------- Natural Gas
Amount Oil & NGLs Natural Gas Equivalent
Region (thousands) % (Mbbls) (Mmcf) (Mmcfe)
------------------ ------------ ------ ----------- ------------ -----------
Appalachian Basin $ 430,590 91.2% 1,051 171,718 178,024
Western Basins 27,738 5.9% 1,455 4,829 13,559
Gulf Coast 12,903 2.7% 445 6,187 8,857
New Zealand 696 0.2% - 611 611
------------ ------ ----------- ------------ -----------
Total $ 471,927 100.0% 2,951 183,345 201,051
============ ====== =========== ============ ===========
PRODUCING WELLS
- ----------------
The following table sets forth certain information relating to productive
wells at June 30, 2002. Wells are classified as oil or gas according to their
predominant production stream.
Gross Wells Net Wells
----------------- ---------------------
Oil Gas Total Oil Gas Total
--- ----- ----- --- ------- -------
Appalachian Basin 2 5,136 5,138 1.0 3,276.2 3,277.2
Western Basins 11 2 13 3.3 2.0 5.3
Gulf Coast 1 4 5 0.7 2.2 2.9
New Zealand - 3 3 - 3.0 3.0
--- ----- ----- --- ------- -------
Total 14 5,145 5,159 5.0 3,283.4 3,288.4
=== ===== ===== === ======= =======
8
ACREAGE
- -------
The following table sets forth the developed and undeveloped gross and net
acreage held at June 30, 2002:
Developed Acreage Undeveloped Acreage
-------------------- ------------------------
Gross Net Gross Net
--------- --------- ----------- -----------
Appalachian Basin 399,945.0 308,158.0 140,028.0 99,175.0
Western Basins 1,840.0 1,441.9 208,024.3 111,578.3
Gulf Coast 1,086.1 474.9 35,851.1 27,333.5
New Zealand 700.0 700.0 2,969,076.1 2,969,076.1
--------- --------- ----------- -----------
Total 403,571.1 310,774.8 3,352,979.5 3,207,162.9
========= ========= =========== ===========
PRODUCTION
- ----------
The following table sets forth certain production data and average sales
prices attributable to the Company's properties for the years ended June 30:
2002 2001 2000
------- ------- ------
Production Data:
Oil (Mbbls) 124 116 113
Natural gas (Mmcf) 9,941 9,371 7,399
Natural gas equivalent (Mmcfe) 10,685 10,067 8,079
Average Sales Price (before the effect of hedging):
Oil per Bbl $ 21.11 $ 25.94 $21.64
Natural gas per Mcf $ 2.86 $ 5.43 $ 2.81
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.
9
2002 2001 2000
----------- ----------- -----------
Gross Net Gross Net Gross Net
----- ---- ----- ---- ----- ----
Development:
Productive
Appalachian 53.0 47.8 47.0 41.5 15.0 12.6
Other 1.0 0.3 - - - -
----- ---- ----- ---- ----- ----
Total 54.0 48.1 47.0 41.5 15.0 12.6
===== ==== ===== ==== ===== ====
Nonproductive
Appalachian 1.0 0.9 1.0 0.5 - -
Other - - - - - -
----- ---- ----- ---- ----- ----
Total 1.0 0.9 1.0 0.5 - -
===== ==== ===== ==== ===== ====
Exploratory:
Productive
Appalachian 4.0 1.6 1.0 0.5
Other 4.0 2.3 3.0 2.6 3.0 1.5
----- ---- ----- ---- ----- ----
Total 8.0 3.9 3.0 2.6 4.0 2.0
===== ==== ===== ==== ===== ====
Nonproductive
Appalachian 5.0 2.1 2.0 0.3 - -
Other 4.0 3.2 8.0 3.8 15.0 8.3
----- ---- ----- ---- ----- ----
Total 9.0 5.3 10.0 4.1 15.0 8.3
===== ==== ===== ==== ===== ====
ITEM 3. LEGAL PROCEEDINGS
-------------------------
As previously disclosed, in June 2001, the Company filed a lawsuit against
Oracle Corporation for breach of contract, breach of warranty and rescission
with respect to a software package purchased from Oracle and the failed
implementation thereof. Oracle answered the complaint substantially denying all
of the Company's allegations and filed a counterclaim against the Company
alleging that it is owed approximately $1.2 million for prior services. In
November 2001, the Company amended its Complaint against Oracle to add a count
for fraud. Extensive discovery has been conducted by the parties. The Company
intends to aggressively prosecute its case against Oracle as well as defend
against the counterclaim of Oracle. This case is scheduled for trial in
November 2002.
As previously disclosed, on December 27, 2001, the Company received a
Notice of Default from certain holders of its $200 million 9-1/2% Senior
Subordinate Notes due 2007 (the "Notes") alleging a default under Section 4.9 of
the Indenture pursuant to which the Notes were issued. The alleged default
related to the proper calculation of Net Proceeds of an Asset Sale, particularly
with respect to the deduction for taxes paid or payable as a result of such
sale. On December 28, 2001, the Company filed a declaratory judgment action in
the United States District Court for the Southern District of West Virginia (the
"Court") against the holders of the Notes who issued the Notice of Default (the
"Noteholders"), asking the Court to confirm the proper calculation of Net
Proceeds of an Asset Sale under the Indenture. On January 25, 2002, the Court
entered an order denying the Noteholders' Motion to Dismiss and granting the
Company's Motion for Partial Summary Judgment, which order approved the
Company's methodology in calculating taxes paid or payable in connection with an
Asset Sale. On February 28, 2002, the Noteholders filed an answer and
counterclaim in the declaratory judgment action. The counterclaim alleges that
the Company's sale of Mountaineer in August of 2000 constituted a sale of
10
substantially all assets of the Company, as opposed to an Asset Sale, and
invoked certain obligations under the Indenture to repurchase the outstanding
Notes. On March 25, 2002, the Company filed its Second Motion for Partial
Summary Judgment, asserting that the Noteholders were barred from asserting the
counterclaim. On June 3, 2002, the United States District Court for the
Southern District of West Virginia entered an order granting the Company's
Second Motion for Partial Summary Judgment, which order dismissed the
Noteholders' claim on the basis of judicial admissions and equitable estoppel.
On May 22, 2002, the Noteholders filed a "Motion for Reconsideration of the
Court's January 25, 2002 Order and Permission to Take Limited Discovery in Order
to Supplement the Record". The Court entered an Order dated July 19, 2002,
denying the Noteholders' Motion for Reconsideration. On July 27, 2002 the
Noteholders filed a Notice of Appeal, and the appeal is pending in the United
States Court of Appeals for the Fourth Circuit. The foregoing text is qualified
in its entirety by Orders of the Court entered January 25, 2002, June 3, 2002
and July 19, 2002, which are attached as Exhibits and incorporated herein by
reference.
The Company is involved in various other legal actions and claims arising
in the ordinary course of business. While the outcome of these other 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
-----------------------------------------------------------
None.
PART II
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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
August 31, 2002, the Company had 35 holders of record of its common stock.
The Company declared dividends in fiscal years 2002, 2001 and 2000 of $1.1
million, $3.9 million and $0, respectively.
11
ITEM 6. SELECTED FINANCIAL DATA
-------------------------------
(Dollars in thousands, except per share items)
Year Ended June 30,
-----------------------------------------------------
2002 2001 2000 1999 1998
--------- --------- --------- --------- ---------
(1)
Operating revenue $ 86,142 $129,951 $101,919 $113,500 $193,459
Loss from continuing operations (26,180) (10,199) (26,508) (27,099) (3,773)
Loss from continuing operations
Per common share, basic and diluted (39.80) (15.34) (40.11) (40.27) (5.67)
Total assets 304,736 380,532 265,691 286,077 290,541
Long term debt 198,701 198,902 212,575 219,886 201,507
Dividends declared per common share $ 1.60 $ 5.80 $ - $ 0.95 $ 1.70
(1) Includes a $30.0 million contract settlement.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF
----------------------------------------------------------
OPERATIONS AND FINANCIAL CONDITION
----------------------------------
SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
- --------------------------------------------------------------------------------
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, intentions 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 under the
Private Securities Litigation Reform Act of 1995. The Company cautions that
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, foreign currency exchange rates,
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.
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.
12
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
- ----------------------------------------------
The discussion of financial condition and results of operation are based
upon the information reported in the consolidated financial statements. The
preparation of these financial statements requires the Company to make
assumptions and estimates that affect the reported amounts of assets,
liabilities, revenues and expenses as well as the disclosure of contingent
assets and liabilities at the date of the financial statements. Decisions are
based on historical experience and various other sources that are believed to be
reasonable under the circumstances. Actual results may differ from the
estimates due to changing business conditions or unexpected circumstances. The
Company believes the following policies are critical to understanding our
business and results of operations. For additional information on significant
accounting policies, see Notes to Consolidated Financial Statements,
particularly Note 2.
REVENUE RECOGNITION - The Company is engaged in the exploration,
development, acquisition, production and marketing of natural gas and crude oil.
The revenue recognition policy is significant because it is a key component of
the results of operations and forward looking statements contained in the
Liquidity and Capital Resources section. Revenue is derived primarily from the
sale of produced natural gas and crude oil. Revenue is recorded in the month
production is delivered to the purchaser, but payment is generally received
between 30 and 90 days after the date of production. Monthly, the Company makes
estimates of the amount of production delivered to the purchaser and the price
to be received. The Company uses its knowledge of properties, historical
performance, NYMEX and local spot market prices and other factors as the basis
for these estimates. Variances between the estimates and the actual amounts
received are recorded in the month revenue is distributed.
FAIR VALUE OF DERIVATIVE INSTRUMENTS - As of July 1, 2000, the estimated
fair values of the derivative instruments are recorded on the consolidated
balance sheet. All of the derivative instruments are entered into to mitigate
risks related to the prices to be received for future natural gas and oil
production. Derivative instruments are not used for trading purposes. Although
derivatives are reported on the balance sheet at fair value, to the extent that
instruments qualify for hedge accounting treatment, changes in fair value are
recorded, net of taxes, directly to stockholders' equity until the hedged oil or
natural gas quantities are produced. To the extent changes in the fair values of
derivatives relate to instruments not qualifying for hedge accounting treatment,
such changes are recorded to income in the period they occur. In determining the
amounts to be recorded, we are required to estimate the fair values of
derivatives. The estimates are based upon various factors that include contract
volumes and prices, contract settlement dates, quoted closing prices on the
NYMEX or over-the-counter, volatility and the time value of options. The
calculation of the fair value of collars and floors requires the use of the
Black-Scholes option-pricing model. The estimated future prices are compared to
the prices fixed by the derivatives agreements and the resulting estimated
future cash inflows or outflows over the lives of the hedges are discounted to
calculate the fair value of the derivative contracts. These pricing and
discounting variables are sensitive to market volatility as well as changes in
future price forecasts and regional price differences. Periodically the
valuations are validated using independent third party quotations.
RESERVE ESTIMATES - The Company's estimate of gas and oil reserves are
projections based on geologic and engineering data. There are uncertainties
inherent in the interpretation of such data as well as the projection of future
rates of production and the timing of development expenditures. Reserve
engineering is a subjective process of estimating underground accumulations of
gas and oil that are difficult to measure. The accuracy of any reserve estimate
is a function of the quality of available data, engineering and geological
interpretation and judgment. Estimates of economically recoverable gas and oil
reserves and future net cash flows depend upon a number of variable factors and
assumptions, such as expected future production rates, gas and oil prices,
operating costs, severance taxes, and development costs, all of which may vary
considerably from actual results. Expected cash flows are reduced to present
13
value using a discount rate. Reserve estimates are inherently imprecise and
estimates of new discoveries are more imprecise than those of proved producing
oil and gas properties. The future drilling costs associated with reserves
assigned to proved undeveloped locations may ultimately increase to an extent
that these reserves may be determined to be uneconomic. Any significant variance
in the assumptions could materially affect the estimated quantity and value of
the reserves, which could affect the carrying value of the Company's gas and oil
properties and their rates of depletion. Changes in these calculations, caused
by changes in reserve quantities or net cash flows are recorded on a prospective
basis. Actual production, revenues and expenditures with respect to the
Company's reserves will likely vary from estimates and such variances may be
material.
DEPLETION - The capitalized costs of oil and gas properties related to
proved reserves are amortized on a unit-of-production method based on an
estimate of proved developed oil and gas reserves. The quantities of estimated
reserves are a significant component of amortization and revisions may alter the
rate of future expense. Generally, if reserve volumes increase or decrease the
amortization rate per unit of production will change inversely. Production
volumes do not affect the per-unit rate.
VALUATION OF LONG-LIVED AND INTANGIBLE ASSETS - Property and equipment are
recorded at cost. The carrying value of property and equipment is reviewed for
possible impairment whenever events or changes in circumstances indicate that
the carrying amount may not be recoverable. Assets are determined to be impaired
if a forecast of undiscounted estimated future net operating cash flows directly
related to the asset, including disposal value if any, is less than the carrying
amount of the asset. If any asset is determined to be impaired, the loss is
measured as the amount by which the carrying amount of the asset exceeds its
fair value. An estimate of fair value is based on the best information
available, including prices for similar assets. Different pricing assumptions or
discount rates would result in a different calculated impairment.
INCOME TAXES - The Company provides for deferred income taxes on the
difference between the tax basis of an asset or liability and its carrying
amount in the financial statements. This difference will result in taxable
income or deductions in future years when the reported amount of the asset or
liability is recovered or settled, respectively. Federal and state income tax
returns are generally not filed before the consolidated financial statements are
prepared, therefore we estimate the tax basis of assets and liabilities at the
end of each period as well as the effects of tax rate changes, tax credits and
net operating loss carryforwards. Adjustments related to differences between the
estimates and actual amounts are recorded in the period the income tax returns
are filed.
COMPARISON OF RESULTS OF OPERATIONS FOR THE YEARS ENDED JUNE 30, 2002 AND 2001
- --------------------------------------------------------------------------------
The Company recorded a net loss from continuing operations of $26.2 million
for the year ended June 30, 2002 compared to a net loss of $10.2 million in
2001. The increase in net loss of $16.0 million is attributed to the net of a
$43.8 million decrease in revenue, a $22.4 million decrease in operating
expenses, a $4.6 million decrease in other non-operating income, a $0.4 million
decrease in interest expense and a $9.6 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 $27.4 million for the
current year compared to $33.0 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 $23.2 million versus $27.6 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 $3.7 million for the current period versus $3.9 million
for the prior period.
14
Production, marketing and pipeline volumes, revenue and average sales
prices for the years ended June 30 and their related variances are as follows:
Variance
-------------------
2002 2001 Amount Percent
------- -------- --------- --------
Natural Gas
Production (Mmcf) 9,941 8,822(1) 1,119 12.68%
Average sales price received ($per Mcf) 2.86 5.45 (2.59) -47.52%
------- -------- --------- --------
Sales ($in thousands) 28,463 48,063 (19,600) -40.78%
Oil
Production (Mbbl) 124 108(1) 16 14.81%
Average sales price received ($per Bbl) 21.11 25.94 (4.83) -18.62%
------- -------- --------- --------
Sales ($in thousands) 2,618 2,812 (194) -6.90%
Hedging 7,211 (9,567) 16,778 175.37%
Other 647 247 400 161.94%
------- -------- --------- --------
Total oil and gas sales ($in thousands) $38,939 $41,555 $ (2,616) -6.30%
======= ======== ========= ========
Marketing Revenue
Volume (Mdth) 9,903 12,126 (2,223) -18.33%
Average sales price received ($per Dth) 3.14 5.42 (2.28) -42.07%
------- -------- --------- --------
Sales ($in thousands) 31,125 64,890 (33,765) -52.03%
Pipeline Revenue
Volume (Mdth) 6,003 6,531 (528) -8.08%
Average sales price received ($per Dth) 1.68 2.47 (0.79) -31.98%
------- -------- --------- --------
($in thousands) 10,084 16,152 (6,068) -37.57%
------- -------- --------- --------
Total marketing and pipeline sales ($in thousands) $41,209 $81,042 $(39,833) -49.15%
======= ======== ========= ========
Marketing Cost
Volume (Mdth) 9,902 12,087 (2,185) -18.08%
Average price paid ($per Dth) 2.98 5.16 (2.18) -42.25%
------- -------- --------- --------
Cost ($in thousands) 29,525 62,219 (32,694) -52.55%
Pipeline Cost
Volume (Mdth) 4,870 5,455 (585) -10.72%
Average price paid ($per Dth) 1.64 2.74 (1.10) -40.15%
------- -------- --------- --------
Cost ($in thousands) 7,964 14,948 (6,984) -46.72%
------- -------- --------- --------
Total marketing and pipeline cost ($in thousands) $37,489 $77,167 $(39,678) -51.42%
======= ======== ========= ========
(1) Production does not include volumes related to the Penn Virginia
acquisition between the effective date and the closing date.
REVENUES. Total revenues decreased $43.8 million or 33.7% between the
---------
years. The net decrease was due to a 49.2% decrease in gas marketing and
pipeline sales, a 6.3% decrease in oil and gas sales, a 6.9% decrease in well
operations and service revenues and a 65.4% decrease in other operating revenue.
Revenues from gas marketing and pipeline sales decreased $39.8 million from
$81.0 million during the period ended June 30, 2001 to $41.2 million in the
period ended June 30, 2002. Gas marketing revenue decreased $33.7 million. The
price decline corresponds with related indexes. The decline was partially offset
by a $0.5 million bad debt write off during the prior period. Pipeline revenue,
which has a sales and transportation component, decreased $6.1 million. The
decrease in gas marketing and pipeline volumes is primarily due to the Company's
reduction in the purchase of third party volumes.
15
Revenues from oil and gas sales decreased a net of $2.6 million from $41.5
million for the year ended June 30, 2001 to $38.9 million for the year ended
June 30, 2002. Natural gas sales declined $19.6 million and oil sales declined
$0.2 million. The net decline is attributed to the following variances; gas
price decrease $25.7 million, gas production increase $6.1 million, oil price
decrease $0.6 million and oil production increase $0.4 million. The price
decline corresponds with related indexes. The increased volume is primarily due
to a full year of production related to the Penn Virginia acquisition, while the
prior period had six months. The decreased production revenue was offset by
recognized gains on related hedging transactions, which totaled a gain of $7.2
million for the year ended June 30, 2002 compared to a loss of $9.6 million for
the year ended June 30, 2001. The average price per Mcfe, after hedging, was
$3.64 and $4.39 for the years ended June 30, 2002 and 2001.
Other operating revenue decreased $1.0 million. The current year income of
$0.5 million is related to revenue earned by the Company's drilling subsidiary,
Deep Rig, with no related revenue in the prior period. The prior year revenue of
$1.5 million was related to a management contract with Allegheny that terminated
March 31, 2001.
COSTS AND EXPENSES. The Company's costs and expenses decreased $22.4
---------------------
million or 16.8% between the periods primarily as a net result of a 51.4%
decrease in gas marketing and pipeline costs, a 22.5% increase in field and
lease operating expenses, a 35.6% increase in general and administrative
expenses, a 35.8% decrease in taxes other than income, a 33.1% increase in oil
and gas related depreciation, depletion and amortization expenses and a 45.7%
increase in exploration and impairment costs.
Gas marketing and pipeline costs decreased $39.7 million. Gas marketing
cost decreased $32.7. The price decline corresponds with related indexes.
Pipeline costs decreased $7.0 million. The decrease in gas marketing and
pipeline volumes purchased is due to the decline in volumes sold.
Field and lease operating expenses increased $2.0 million. A full year of
expenses related to the Penn Virginia acquisition, while the prior period had
six months, accounted for a $0.4 million increase. The remaining increase is
primarily related to payroll expenses and for repairs to roads and dikes damaged
during flooding.
General and administrative expenses increased $4.6 million because of
higher costs, primarily related to payroll and employee benefits, legal fees,
bad debt reserves and increased Texas activity.
Taxes other than income decreased $1.2 million, of which $0.9 million is
due to decreased oil and gas prices. Production taxes are based on wellhead
prices and are not affected by hedging activity. The remaining $0.3 million is
related to decreased franchise taxes.
Oil and gas related depreciation, depletion and amortization expenses
increased $3.1 million. The increase in production volumes primarily due to the
Penn Virginia acquisition, accounted for $0.9 million. The remaining increase is
primarily a result of increased depletion rates and production in Texas.
Exploration and impairment expenses increased $8.7 million. The expenses
were primarily due to dry hole costs, impairment of wells and property and
various other geological and geophysical costs. The breakdown of costs by area
are $13.1 million in the Gulf Coast, $6.6 million in New Zealand, $4.4 million
in the Appalachian basin and $3.4 million in the West.
16
OTHER NON-OPERATING INCOME. Other non-operating income decreased $4.7
-----------------------------
million when comparing the periods. This is primarily the result of $6.0 million
less interest income due to decreases in the cash balances and interest rates
when comparing the periods. This was partially offset by a $1.3 million decrease
in other non-operating expense in fiscal year 2002.
INCOME TAX. The benefit for income taxes increased $9.6 million due to the
------------
$25.6 million increased loss from continuing operation.
COMPARISON OF RESULTS OF OPERATIONS FOR THE YEARS ENDED JUNE 30, 2001 AND 2000
- --------------------------------------------------------------------------------
The Company recorded a net loss from continuing operations of $10.2 million
for the year ended June 30, 2001 compared to a net loss of $26.5 million for the
same period in 2000. The improvement of $16.3 million is attributed to the net
of a $28.0 million increase in revenue, a $4.2 million increase in operating
expenses, a $10.7 million increase in impairment and exploratory costs, a $2.2
million decrease to interest expense, a $5.6 million increase in other
non-operating income and a $4.6 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 $33.0 million for the
current year compared to $7.8 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 $27.6 million versus $10.7 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) had income of $3.9 million for the current period versus a loss
of $2.9 million for the prior period.
17
Production, marketing and pipeline volumes, revenue and average sales
prices for the years ended June 30 and their related variances are as follows:
Variance
------------------
2001 2000 Amount Percent
---------- -------- -------- --------
Natural Gas
Production (Mmcf) (1) 8,822 7,399 1,423 19.23%
Average sales price received ($per Mcf) 5.45 2.81 2.64 93.95%
---------- -------- -------- --------
Sales ($in thousands) 48,063 20,808 27,255 130.98%
Oil
Production (Mbbl) (1) 108 113 (5) -4.42%
Average sales price received ($per Bbl) 25.94 21.64 4.30 19.87%
---------- -------- -------- --------
Sales ($in thousands) 2,812 2,455 357 14.54%
Hedging (9,567) (967) (8,600) -889.35%
Other 247 1,573 (1,326) -84.30%
---------- -------- -------- --------
Total oil and gas sales ($in thousands) $ 41,555 $23,869 $17,686 74.10%
========== ======== ======== ========
Marketing Revenue
Volume (Mdth) 12,126 21,050 (8,924) -42.39%
Average sales price received ($per Dth) 5.42 2.92 2.50 85.62%
---------- -------- -------- --------
Sales ($in thousands) 64,890 61,137 3,753 6.14%
Pipeline Revenue
Volume (Mdth) 6,531 7,142 (611) -8.56%
Average sales price received ($per Dth) 2.47 1.54 0.93 60.39%
---------- -------- -------- --------
($in thousands) 16,152 11,019 5,133 46.58%
---------- -------- -------- --------
Total marketing and pipeline sales ($in thousands) $ 81,042 $72,156 $ 8,886 12.31%
========== ======== ======== ========
Marketing Cost
Volume (Mdth) 12,087 21,048 (8,961) -42.57%
Average price paid ($per Dth) 5.16 2.94 2.22 75.51%
---------- -------- -------- --------
Cost ($in thousands) 62,219 61,893 326 0.53%
Pipeline Cost
Volume (Mdth) 5,455 6,066 (611) -10.07%
Average price paid ($per Dth) 2.74 1.35 1.39 102.96%
---------- -------- -------- --------
Cost ($in thousands) 14,948 8,208 6,740 82.12%
---------- -------- -------- --------
Total marketing and pipeline cost ($in thousands) $ 77,167 $70,101 $ 7,066 10.08%
========== ======== ======== ========
(1) Production does not include volumes related to the Penn Virginia
acquisition between the effective date and the closing date.
REVENUES. Total revenues increased $28.0 million or 27.5% between the
--------
years. The net increase was due to a 12.3% increase in gas marketing and
pipeline sales, a 74.1% increase in oil and gas sales and a 100% increase in
other operating revenue. Well operations and service revenues remained
relatively constant.
18
Revenues from gas marketing and pipeline sales increased $8.9 million from
$72.1 million during the period ended June 30, 2000, to $81.0 million in the
period ended June 30, 2001. Gas marketing revenue increased $3.8 million.
Pipeline revenue increased $5.1 million. The decrease in volumes is primarily
related to the Company's decision to exit the end-user market.
Revenues from oil and gas sales increased $17.7 million from $23.9 million
for the year ended June 30, 2000 to $41.5 million for the year ended June 30,
2001 due to an increase in both price and net production. The average Mcf price
received for the year ended June 30, 2000 was $2.81 compared to $5.45 for the
year ended June 30, 2001. The Company's net Mcf production for the year ended
June 30, 2000 compared to the year ended June 30, 2001 increased 1,423.6 Mmcf,
19.2%, which is attributable to drilling and acquisitions. The average Bbl price
received for the year ended June 30, 2000 was $21.64 compared to $25.94 for the
year ended June 30, 2001 This price increase was offset by a 5,092 Bbl, 4.4%,
drop in production for the year. The price and net production increases to
revenue were offset by recognized losses on related hedging transactions, which
totaled $9.6 million for the year ended June 30, 2001 compared to $1.0 million
for the year ended June 30, 2000. The average price per Mcfe, after hedging, was
$4.39 and $2.95 for the years ended June 30, 2001 and 2000.
Revenues from other operations increased from zero during the year ended
June 30, 2000 to $1.5 million during the year ended June 30, 2001. The increase
in revenue is due to a management contract with Allegheny, which terminated
March 31, 2001, whereby the Company provided Mountaineer with management
services, subsequent to the sale.
COSTS AND EXPENSES. The Company's costs and expenses increased $4.2 million
------------------
or 3.9% between the years primarily as a result of a 10.1% increase in gas
marketing and pipeline costs and a 127.1% increase to taxes other than income.
Field and lease operating expenses, general and administrative expenses and
depreciation, depletion and amortization expenses remained relatively constant
between the periods.
Gas marketing and pipeline costs increased $7.1 million. Gas marketing
cost increased $0.3 million primarily due to a 75.6% increase in the average
price paid per Mmbtu from $2.94 for the year ended June 30, 2000 to $5.16 for
the year ended June 30, 2001. This increase was diminished by a 41.8% decline
in purchased gas volumes from 20.6 million Mmbtu to 12.0 million Mmbtu for the
same period. Pipeline cost increased $6.8 million primarily due to a 109.6%
increase in the average price paid for gas purchased from $2.23 per Mmbtu for
the year ended June 30, 2000 to $4.67 for the year ended June 30, 2001. This
increase was offset by a 10.9% decline in purchased gas volumes from 3.6 million
Mmbtu to 3.2 million Mmbtu for the same period. During fiscal year 2000, the
Company recognized a $4.9 million gas purchase commitment expense related to the
Royalty Trust with no similar costs recorded during the current fiscal year.
See Note 14.
Taxes other than income increased $1.9 million as a result of higher oil
and gas prices and volumes. Production taxes are based on the wellhead price
received and are not affected by hedging activities.
EXPLORATION AND IMPAIRMENT. Exploration and impairment costs increased
----------------------------
$10.7 million when comparing the periods. The primary costs related to this
increase are the impairment of a computer conversion project, $5.7 million, and
impairment of the investment in a fiber optic company due to bankruptcy, $1.6
million. The balance of the increase is for other oil and gas exploratory costs,
which includes impairment of drilling costs related to dry holes, delay rentals,
lease expirations, geological and geophysical costs and seismic.
19
INTEREST EXPENSE. Interest expense decreased $2.2 million or 9.9%, when
-----------------
comparing the periods. This is primarily due to having 6.8% less debt at June
30, 2001.
OTHER NON-OPERATING INCOME. Other non-operating income increased $5.6
----------------------------
million when comparing the periods ended June 30, 2001 to June 30, 2000. This is
primarily due to interest income earned on cash and cash equivalents.
INCOME TAX. The provision for income taxes increased $4.6 million due to
-----------
the $20.9 million increase to pre-tax earnings from continuing operation.
CAPITAL EXPENDITURES
- ---------------------
Expenditures for the exploration, development and acquisition of oil and
gas properties are the Company's primary use of capital resources. The
following table summarizes certain costs incurred for the years ended June 30
(in thousands):
2002 2001 2000
------- -------- -------
Development $10,977 $ 13,649 $ 5,869
Exploration 20,737 15,115 8,693
Acquisitions 717 80,394 4,160
------- -------- -------
Total $32,431 $109,158 $18,722
======= ======== =======
ACQUISITIONS
- ------------
During the year ended June 30, 2002, the Company made the following
significant acquisitions:
- On July 6, 2001, the Company paid $18.1 million for interests in various
oil and gas leases, seismic and technical data, contracts, right-of-ways
and real and personal property in Texas. The acquisition had an effective
date before year-end and as a result was recorded at June 30, 2001 with the
purchase price reflected in other current liabilities. Also during fiscal
year 2002, the Company increased its working interest in Texas properties
to 80% in deep rights and 40% in shallow rights through the acquisition of
a net 5,400 acres for $0.36 million.
- A deposit of $1.2 million was paid for the purchase of certain oil and gas
properties located in southern West Virginia. The total acquisition will be
$6.0 million. The purchase includes proved developed producing gas
reserves, estimated at 4 Bcf, 90 producing wells and over 30,000 acres.
This acquisition is subject to the approval of the Public Service
Commission of West Virginia.
- The Company purchased an interest in Alliance Energy Services Partnership
for $2.8 million. The Company anticipates future expenditures related to
this investment. The investment is accounted for under the cost method, as
the Company does not have significant influence over management and
operation of the partnership. The partnership provides energy solutions to
customers.
20
LIQUIDITY AND CAPITAL RESOURCES
- ----------------------------------
The Company's financial condition has declined since June 30, 2001.
Stockholders' equity has decreased from $64.8 million at June 30, 2001 to $37.1
million at June 30, 2002. The Company's working capital decreased from $53.0
million at June 30, 2001 to $1.8 million at June 30, 2002. The Company's cash
decreased from $80.3 million at June 30, 2001 to $17.8 million at June 30, 2002.
The Company's cash at September 25, 2002 was $18.2 million. In addition,
earnings from continuing operations before interest charges, taxes,
depreciation, depletion and amortization and impairment and exploratory costs
("EBITDAX") decreased from $33.7 million in the twelve month period ended June
30, 2001, to $19.7 million in the twelve month period ended June 30, 2002. The
decrease in cash during the year was a result of the net use of approximately
$62.5 million of cash for various operating and capital expenditure activities
of the Company. The activities were primarily comprised of: the net investment
of approximately $37.6 million in property, plant and equipment; payments of
approximately $2.8 million for the acquisition of treasury stock and dividends;
and the use of approximately $22.1 million of cash by operations during the
year. The $22.1 million use of cash by operations during the year was primarily
due to the payment of $18.1 million in July 2001 for the Company's acquisition
of certain oil and gas interests in Texas, which had been accrued at June 30,
2001. (See Note 3 of Notes to Consolidated Financial Statements.)
On June 21, 2002 Moody's Investors Service ("Moody's") downgraded the
Company's debt rating. With a negative outlook, Moody's downgraded to Caa3 from
Caa1 the Company's 9.5% Senior Subordinated Notes ("Notes") due 2007. Moody's
stated that; "Further ratings actions are possible upon review of ECA's fiscal
year-end June 30, 2002 reserve replacements after a year of heavy reinvestment,
funded with cash-on-hand, and depending on whether ECA incurs additional secured
debt to fund its drilling program." Moody's also stated that; "The downgrades
reflect insufficient cash flow to cover interest expense and reserve replacement
capital expenditures; asset coverage that is below the par value of the bonds;
and declining production in spite of heavy FYE 2001 and FYE 2002 reinvestment in
reserve acquisitions and development and exploration drilling." This could
negatively impact the Company's ability to raise capital in the future or
increase the cost of such capital. The Company's total proved reserves decreased
by 9.5% in the fiscal year ended June 30, 2002. At July 1, 2002, total proved
reserves were 201,050 Mmcfe compared to total proved reserves at July 1, 2001 of
222,254 Mmcfe.
At June 30, 2002, the Company's principal source of liquidity consisted of
$17.8 million of cash, plus $2 million available under an unsecured short-term
credit facility currently in place. At June 30, 2002, no amounts were
outstanding or committed under the short-term credit facility.
On July 10, 2002, the Company entered into a $50 million revolving Credit
Agreement (the "Agreement") with Foothill Capital Corporation ("Foothill").
Depending on its level of borrowing under the Agreement, the applicable interest
rates are based on Wells Fargo's prime rate plus 0.50% to 2.50%. The Agreement
expires on July 10, 2005.
The Agreement is secured by approximately 80% of the existing proved
producing oil and gas assets of the Company. The Agreement, among other things,
restricts the ability of the Company and its subsidiaries to incur new debt,
grant additional security interests in its collateral, engage in certain merger
or reorganization activities, or dispose of certain assets. Upon the occurrence
of an event of default, the lenders may terminate the Agreement and declare all
obligations thereunder immediately due and payable. As of September 25, 2002,
there are $10 million in outstanding borrowings under the Agreement. Under the
Indenture for the Company's Notes, the Company is restricted from incurring
additional debt in excess of the $50 million available under the Agreement
unless the Company's fixed charge coverage ratio, as defined in the Indenture,
is at least 2.5 to 1. Currently, the Company's fixed charge coverage ratio is
less than 2.5 to 1.
21
The Company's net cash requirements will fluctuate based on timing and the
extent of the interplay of capital expenditures, cash generated by continuing
operations and interest expense. Management anticipates that EBITDAX for fiscal
year 2003 will approximate $35 million as compared to $19.7 million for fiscal
year 2002; however, such results will not be sufficient to fully fund fiscal
year 2003 projected interest charges of over $20 million and fund the Company's
anticipated fiscal year 2003 capital expenditures program of $32 million. The
Company's ability to achieve an EBITDAX of $35 million for fiscal year 2003 is
highly dependant on product price and drilling success. The Company budget of
$4.00 per Mmbtu for the price of natural gas and the Company's budget assumption
for gas production is approximately 13.8 Bcf, which is an increase of 30% over
production of approximately 10.6 Bcf in fiscal year 2002. There can be no
assurance given that the Company will be able to achieve these goals. EBITDAX
for fiscal years 2002, 2001 and 2000 was $19.7 million, $33.7 million and $4.1
million, respectively. Although cash provided from oil and gas operations will
not be sufficient to fully fund the Company's fiscal year 2003 projected
interest charges and capital expenditures program, management believes that cash
generated from continuing oil and gas operations, together with the liquidity
provided by existing cash balances and working capital, permitted borrowings and
the cash proceeds resulting from the sale of certain operating assets as well as
the divestment of certain non-core assets, will be sufficient to satisfy
commitments for capital expenditures, debt service obligations, working capital
needs and other cash requirements for the next year.
In order to reduce future cash interest payments, as well as future amounts
due at maturity or upon redemption, the Company may, from time to time, purchase
its outstanding debt securities in open market purchases and/or privately
negotiated transactions. The Company will evaluate any such transactions in
light of then existing market conditions, taking into account its liquidity,
uses of capital and prospects for future access to capital. The amounts involved
in any such transaction, individually or in the aggregate, may be material.
Recently the Company purchased certain of the outstanding debt securities in
privately negotiated transactions.
The Company believes that its existing capital resources and its expected
fiscal year 2003 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, levels and availability of
capital resources and continuing liquidity are dependent on future weather
patterns, oil and gas commodity prices and production volume levels, future
exploration and development drilling success and successful acquisition
transactions, no assurance can be given that the Company will remain in
compliance with the requirements of its Notes. See Item 3 "Legal Proceedings"
for a discussion related to the Company's receipt of Notice of Default from
certain holders of the Notes.
In addition to the revolving credit facility and Notes discussed above, the
Company had various other obligations. The following table lists the Company's
contractual obligations at June 30, 2002 (in thousands):
2003 2004 2005 Thereafter Total
-------- -------- ------ ----------- --------
Senior subordinated notes $ 197,672 $197,672
Installment notes payable 213 213 213 1,006 1,645
Operating leases 1,277 1,103 909 146 3,435
-------- -------- ------ ----------- --------
Total contractual cash obligations $ 1,490 $ 1,316 $1,122 $ 198,824 $202,752
======== ======== ====== =========== ========
22
RECENT ACCOUNTING PRONOUNCEMENTS
- ----------------------------------
In June 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standard ("SFAS") No. 141, "Business
Combinations." SFAS No. 141 is intended to improve the transparency of the
accounting and reporting for business combinations by requiring that all
business combinations be accounted for under the purchase method. The statement
also establishes criteria to assess when to recognize intangible assets
separately from goodwill. This statement is effective for all business
combinations initiated after June 30, 2001. At this time, the Company has no
pending business combinations that would be affected by the adoption of this
statement.
In June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible
Assets." This statement addresses the accounting for goodwill and other
intangible assets and provides specific guidance for testing goodwill and other
intangible assets for impairment. Under this statement, goodwill as well as
other intangibles determined to have an infinite life will no longer be
amortized. These assets are required to be reviewed for impairment on a periodic
basis. This statement is effective for the Company July 1, 2002. Management does
not believe the adoption of this statement will have a material effect on the
Company's financial position or results of operations.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." SFAS No. 143 provides the accounting requirements for
retirement obligations associated with long-lived assets. The statement
requires companies to recognize the fair value of an asset's retirement
liability in the financial statements by capitalizing that cost as part of the
cost of the related long-lived asset, which will then be systematically
allocated to expense. The statement is effective for the Company July 1, 2002.
As a preponderance of the Company's wells are within the Appalachian Basin,
which are historically long-lived, disposal costs have been negligible.
Therefore, management does not believe the adoption of this statement will have
a material effect on the Company's financial position or results of operations.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." This statement provides a single
accounting model for long-lived assets to be disposed of and changes the
criteria that would have to be met to classify an asset as held-for-sale. The
statement also requires expected future operating losses from discontinued
operations to be recognized in the periods in which the losses are incurred. The
statement is effective for the Company July 1, 2002. Management does not believe
the adoption of this statement will have a material effect on the Company's
financial position or results of operations.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13 and Technical
Corrections." One of the statement's requirements is to classify the resulting
gain or loss from early debt retirement as ordinary income. Although the
statement is effective in fiscal years beginning after May 15, 2002, the Company
has elected early adoption. Therefore, the gain on the early extinguishment of
debt during fiscal 2001 has been reclassified from extraordinary to other
non-operating income. The adoption of the statement did not have a net effect
on the Company's financial position or results of operations.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." The statement addresses financial
accounting and reporting for costs associated with exit or disposal activities
as certain costs were recognized as liabilities that did not meet the definition
of a liability. This statement is effective for all exit or disposal activities
initiated after December 31, 2002. Management does not believe the adoption of
this statement will have a material effect on the Company's financial position
or results of operations.
23
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES
-------------------------------------------------
ABOUT MARKET RISK
-----------------
COMMODITY RISK
- ---------------
The Company's operations consist primarily of exploring for, producing,
aggregating and selling natural gas and oil. 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. The Company hedges 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. Unrecognized gains and
losses are included as a component of other comprehensive income. See Note 5 to
the Consolidated Financial Statements for additional information. The Company
does not hold or issue derivative instruments for trading purposes. The Company
has elected to enter into swap transactions, covering approximately 19.5% of its
natural gas production through June 2004.
Notwithstanding the above, the Company's future cash flows from gas and oil
production are exposed to significant volatility as commodity prices change.
Assuming total oil and gas production and the percentage of gas production
hedged under physical delivery contracts remain at June 2002 levels, a 10%
change in the average unhedged prices realized during the year would change the
Company's gas and oil revenues by approximately $2.3 million on an annual basis.
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. As of June 30, 2002, all of the Company's debt has fixed
interest rates. 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 debt.
FOREIGN CURRENCY EXCHANGE RISK
- ----------------------------------
Some of the Company's transactions are denominated in New Zealand dollars.
For foreign operations with the local currency as the functional currency,
assets and liabilities are translated at the period end exchange rates, and
statements of income are translated at the average exchange rates during the
period. Gains and losses resulting from foreign currency translation are
included as a component of other comprehensive income.
* * * * *
24
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, 2002 and 2001, and the
related consolidated statements of operations, stockholders' equity (deficit),
cash flows, and comprehensive income for each of the three years in the period
ended June 30, 2002. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Energy Corporation of America and
Subsidiaries as of June 30, 2002 and 2001, and the results of their operations
and their cash flows for each of the three years in the period ended June 30,
2002 in conformity with accounting principles generally accepted in the United
States of America.
DELOITTE & TOUCHE LLP
Denver, Colorado
September 20, 2002
25
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF JUNE 30
(AMOUNTS IN THOUSANDS)
- --------------------------------------------------------------------------------
ASSETS 2002 2001
--------- ---------
CURRENT ASSETS:
Cash and cash equivalents $ 17,775 $ 80,336
--------- ---------
Accounts receivable:
Gas marketing and pipeline 5,323 8,056
Oil and gas sales 7,284 7,525
Other 6,924 8,264
--------- ---------
19,531 23,845
Less allowance for doubtful accounts (1,366) (457)
--------- ---------
18,165 23,388
Gas in storage, at lower of cost or market 199 1,069
Income taxes receivable 1,596 -
Deferred income tax asset 2,237 7,467
Derivatives 454 4,391
Prepaid and other current assets 4,035 1,978
--------- ---------
Total current assets 44,461 118,629
NET PROPERTY, PLANT AND EQUIPMENT (Note 2) 244,155 248,659
--------- ---------
OTHER ASSETS:
Deferred financing costs, less accumulated
amortization of $3,722 and $2,987 3,617 4,353
Notes receivable - related parties 1,756 1,867
Other 10,747 7,024
--------- ---------
Total other assets 16,120 13,244
--------- ---------
TOTAL $304,736 $380,532
========= =========
See notes to consolidated financial statements. (Continued)
26
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF JUNE 30
(AMOUNTS IN THOUSANDS)
- --------------------------------------------------------------------------------
LIABILITIES AND STOCKHOLDERS' EQUITY 2002 2001
--------- ---------
CURRENT LIABILITIES:
Accounts payable and accrued expenses $ 15,683 $ 18,979
Current portion of long-term debt 121 151
Funds held for future distribution 11,414 14,666
Income taxes payable - 470
Accrued taxes, other than income 8,221 7,860
Deferred income tax liability 180 -
Other current liabilities 7,078 23,462
--------- ---------
Total current liabilities 42,697 65,588
LONG-TERM OBLIGATIONS:
Long-term debt 198,701 198,902
Gas delivery obligation and deferred trust revenue 5,886 11,321
Deferred income tax liability 9,887 29,888
Other long-term obligations 8,689 10,007
Minority interest 1,732 -
--------- ---------
Total liabilities 267,592 315,706
--------- ---------
COMMITMENTS AND CONTINGENCIES (Note 14)
STOCKHOLDERS' EQUITY:
Common stock, par value $1.00; 2,000 shares authorized;
730 shares issued 730 730
Class A non-voting common stock, no par value; 100
shares authorized; 46 and 36 shares issued 5,092 3,732
Additional paid-in capital 5,503 5,503
Retained earnings 36,422 63,653
Treasury stock and notes receivable arising from
issuance of common stock (10,426) (9,293)
Accumulated other comprehensive income (loss) (177) 501
--------- ---------
Total stockholders' equity 37,144 64,826
--------- ---------
TOTAL $304,736 $380,532
========= =========
See notes to consolidated financial statements.
27
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED JUNE 30
(AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
- -----------------------------------------------------------------------------------------------------------
2002 2001 2000
--------- --------- ---------
REVENUES:
Oil and gas sales $ 38,939 $ 41,555 $ 23,869
Gas marketing and pipeline sales 41,209 81,042 72,156
Well operations and service revenues 5,490 5,899 5,894
Other 504 1,455 -
--------- --------- ---------
86,142 129,951 101,919
--------- --------- ---------
COSTS AND EXPENSES:
Field operating expenses 10,916 8,910 8,143
Gas marketing and pipeline cost of sales 37,489 77,167 70,101
Purchase commitment costs - - 4,945
General and administrative 17,360 12,804 13,647
Taxes, other than income 2,175 3,389 1,492
Depletion and depreciation of oil and gas properties 12,362 9,290 8,847
Depreciation of pipelines, other property and equipment 2,934 2,763 2,892
Exploration and impairment 27,694 19,014 8,347
--------- --------- ---------
110,930 133,337 118,414
--------- --------- ---------
Loss from operations (24,788) (3,386) (16,495)
--------- --------- ---------
OTHER (INCOME) AND EXPENSE:
Interest expense 19,671 20,094 22,302
Gain on sale of assets (319) (211) (101)
Interest income and other (1,135) (5,838) (377)
--------- --------- ---------
18,217 14,045 21,824
--------- --------- ---------
Loss from continuing operations before income taxes and minority interest (43,005) (17,431) (38,319)
Benefit for income taxes (16,822) (7,232) (11,811)
--------- --------- ---------
Loss from continuing operations before minority interest (26,183) (10,199) (26,508)
Minority interest (3) - -
--------- --------- ---------
Loss from continuing operations (26,180) (10,199) (26,508)
Disposal of utility operations:
Income (loss) from utility operations, net of tax - (1,847) 8,077
Gain on sale of utility, net of tax - 84,402 -
--------- --------- ---------
Net income from disposal of utility operations - 82,555 8,077
--------- --------- ---------
NET INCOME (LOSS) $(26,180) $ 72,356 $(18,431)
========= ========= =========
Earnings (loss) per common share, basic and diluted
Loss from continuing operations $ (39.80) $ (15.34) $ (40.11)
Discontinued operations - 124.20 12.22
--------- --------- ---------
Earnings (loss) per common share $ (39.80) $ 108.86 $ (27.89)
========= ========= =========
See notes to consolidated financial statements.
28
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)
FOR THE YEARS ENDED JUNE 30
(AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
- --------------------------------------------------------------------------------------------------------------------
Class A Additional Retained Notes Received/
Common Common Paid-In Earnings Treasury Issuance of
Stock Stock Capital (Deficit) Stock Stock
-------- -------- ------------ ---------- ---------- -----------------
Balance, June 30, 1999 $ 721 $ 2,940 $ 4,656 $ 13,598 $ (5,896) $ (1,365)
Comprehensive loss (18,388)
Common stock issued for services 2 146
Redemption of common stock and
related note receivable (5) (187) 192
Purchase of treasury stock - common (223)
Purchase of treasury stock - Class A (165)
Reduction of notes receivable 28
-------- -------- ------------ ---------- ---------- -----------------
Balance June, 30, 2000 718 2,940 4,615 (4,790) (6,284) (1,145)
Comprehensive income 72,991
Dividends ($5.80 per share) (3,870)
Common stock issued for services 12 888
Class A stock issued for services 792
Purchase of treasury stock - common (1,455)
Purchase of treasury stock - Class A (465)
Reduction of notes receivable 56
-------- -------- ------------ ---------- ---------- -----------------
Balance, June 30, 2001 730 3,732 5,503 64,331 (8,204) (1,089)
Comprehensive loss (26,858)
Dividends ($1.60 per share) (1,051)
Class A stock issued for services 1,360
Purchase of treasury stock - common (1,262)
Purchase of treasury stock - Class A (571)
Reduction of notes receivable 700
-------- -------- ------------ ---------- ---------- -----------------
Balance, June 30, 2002 $ 730 $ 5,092 $ 5,503 $ 36,422 $ (10,037) $ (389)
======== ======== ============ ========== ========== =================
Accum. Other
Comprehensive Stockholders'
Income (Loss) Equity
--------------- ---------------
Balance, June 30, 1999 $ (177) $ 14,477
Comprehensive loss (18,388)
Common stock issued for services 148
Redemption of common stock and
related note receivable -
Purchase of treasury stock - common (223)
Purchase of treasury stock - Class A (165)
Reduction of notes receivable 28
--------------- ---------------
Balance June, 30, 2000 (177) (4,123)
Comprehensive income 72,991
Dividends ($5.80 per share) (3,870)
Common stock issued for services 900
Class A stock issued for services 792
Purchase of treasury stock - common (1,455)
Purchase of treasury stock - Class A (465)
Reduction of notes receivable 56
--------------- ---------------
Balance, June 30, 2001 (177) 64,826
Comprehensive loss (26,858)
Dividends ($1.60 per share) (1,051)
Class A stock issued for services 1,360
Purchase of treasury stock - common (1,262)
Purchase of treasury stock - Class A (571)
Reduction of notes receivable 700
--------------- ---------------
Balance, June 30, 2002 $ (177) $ 37,144
=============== ===============
See notes to consolidated financial statements.
29
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED JUNE 30
(AMOUNTS IN THOUSANDS)
- --------------------------------------------------------------------------------------------------------------------
2002 2001 2000
--------- ---------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss from continuing operations $(26,180) $ (10,199) $(26,508)
Adjustments to reconcile net loss to net cash provided (used) by
operating activities:
Depletion, depreciation and amortization 16,031 12,911 12,538
Gain on sale of assets (319) (211) (101)
Deferred income taxes (12,492) 28,359 (11,099)
Exploration and impairment 27,227 18,591 5,979
Other, net 2,322 (4,711) 4,413
--------- ---------- ---------
6,589 44,740 (14,778)
Changes in assets and liabilities:
Accounts receivable 3,187 (2,936) 420
Gas in storage 870 (304) (408)
Income taxes receivable (2,066) (33,821) 1,079
Prepaid and other assets (1,900) (32) 163
Accounts payable (2,218) 6,341 (42)
Funds held for future distributions (3,253) 1,678 902
Other (23,405) 14,631 7,670
--------- ---------- ---------
Net cash provided (used) by operating activities from continuing operations (22,196) 30,297 (4,994)
Net cash provided (used) by operating activities from disposed operations - (48,335) 7,286
--------- ---------- ---------
Net cash provided (used) by operating activities (22,196) (18,038) 2,292
--------- ---------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment (38,294) (112,863) (19,299)
Proceeds from sale of assets 704 1,517 428
Notes receivable and other 86 (4,192) (300)
--------- ---------- ---------
Net cash used by investing activities from continuing operations (37,504) (115,538) (19,171)
Net cash provided (used) by investing activities from disposed operations - 224,765 (23,842)
--------- ---------- ---------
Net cash provided (used) by investing activities (37,504) 109,227 (43,013)
--------- ---------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt - 7,825 16,250
Principal payment on long-term debt (145) (21,850) (29,094)
Proceeds (payment) on short-term borrowing - (2,000) 2,000
Purchase of treasury stock and other financing activities (1,663) (1,072) (214)
Prepayment of future gas delivery - - 10,000
Dividends paid (1,053) (3,605) -
--------- ---------- ---------
Net cash used by financing activities from continuing operations (2,861) (20,702) (1,058)
Net cash provided by financing activities from disposed operations - 6,539 32,926
--------- ---------- ---------
Net cash provided (used) by financing activities (2,861) (14,163) 31,868
--------- ---------- ---------
Net increase (decrease) in cash and cash equivalents (62,561) 77,026 (8,853)
Cash and cash equivalents, beginning of period 80,336 3,310 12,163
--------- ---------- ---------
Cash and cash equivalents, end of period $ 17,775 $ 80,336 $ 3,310
========= ========== =========
See notes to consolidated financial statements.
30
ENERGY CORPORATION OF AMERICA
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
FOR THE YEARS ENDED JUNE 30
(AMOUNTS IN THOUSANDS)
- -------------------------------------------------------------------------------
2002 2001 2000
--------- -------- ---------
Net income (loss) $(26,180) $72,356 $(18,431)
--------- -------- ---------
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustment:
Current period change 1,627 (1,980) 43
Marketable securities:
Unrealized gain (loss) (106) 136
Oil and gas derivatives:
Net cumulative effect adjustment (2,153)
Current period transactions 1,999 (541)
Reclassification to earnings (4,198) 5,173 -
--------- -------- ---------
Other comprehensive income (loss), net of tax (678) 635 43
--------- -------- ---------
Comprehensive income (loss) $(26,858) $72,991 $(18,388)
========= ======== =========
See notes to consolidated financial statements.
31
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED JUNE 30, 2002, 2001 AND 2000
- --------------------------------------------------------------------------------
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,
Ohio, Virginia and Kentucky.
The Company, through its other 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 Texas, California and New Zealand.
In August 2000, the Company sold its wholly owned regulated gas
distribution utility, Mountaineer Gas Company and Subsidiaries
("Mountaineer"). See Note 4.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
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. Investments in affiliates in which the Company owns greater
than 50% are consolidated. Investments in which the Company owns from 20%
to 50% are accounted for by the equity method if the Company has the
ability to exert significant influence over the investee. Investments in
less than 20% owned affiliates and affiliates in which the Company does not
exhibit significant influence are accounted for under the cost method. 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 material intercompany
transactions have been eliminated in consolidation.
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 in income.
32
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 40 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):
2002 2001
---------- ----------
Oil and gas properties $ 320,148 $ 317,225
Pipelines 20,703 19,569
Other property and equipment 19,598 14,088
---------- ----------
360,449 350,882
Less accumulated depletion, depreciation and amortization (116,294) (102,223)
---------- ----------
Net property, plant and equipment $ 244,155 $ 248,659
========== ==========
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 year
ended June 30, 2002, the Company recognized impairment of oil and gas
property of approximately $19.3 million, and $0.1 million related to its
natural gas fueling operations. During fiscal year 2001, in addition to the
usual impairment of oil and gas property of approximately $11.4 million,
the Company recognized impairment expense of $5.7 million related to a
failed computer software conversion and $0.3 million related to its natural
gas fueling operations.
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 accounts using current
exchange rates in effect at the balance sheet date. 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". A valuation allowance is established for any
portion of a deferred tax asset for which it is more likely than not that a
tax benefit will not be realized.
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, and marketing and pipeline
-------------------------
revenues 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".
Use of Estimates - The preparation of financial statements in conformity
------------------
with generally accepted accounting principles in the United States of
America requires management to make estimates and assumptions that affect
the reported amounts of assets and liabilities and disclosure of contingent
assets and liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
33
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, realization of deferred tax assets is
based largely on estimates of future taxable income.
Derivatives - As of July 1, 2000, the Company adopted SFAS No. 133,
-----------
"Accounting for Derivative Instruments and Hedging Activities", as amended.
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; to the extent the hedge
is effective, until the hedged item is recognized in earnings. Hedge
effectiveness is measured monthly based on the relative changes in fair
value between the derivative contract and the hedged item over time. Any
change in fair value resulting from ineffectiveness, as defined by SFAS No.
133, is recognized immediately in earnings.
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, 2002,
the Company has not been fined or cited for any environmental violations,
which would have a material adverse effect upon capital expenditures,
operating results or the competitive position of the Company.
Recent Accounting Pronouncements - In June 2001, the Financial Accounting
----------------------------------
Standards Board ("FASB") issued Statement of Financial Accounting Standard
("SFAS") No. 141, "Business Combinations." SFAS No. 141 is intended to
improve the transparency of the accounting and reporting for business
combinations by requiring that all business combinations be accounted for
under the purchase method. The statement also establishes criteria to
assess when to recognize intangible assets separately from goodwill. This
statement is effective for all business combinations initiated after June
30, 2001. At this time, the Company has no pending business combinations
that would be affected by the adoption of this statement.
In June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible
Assets." This statement addresses the accounting for goodwill and other
intangible assets and provides specific guidance for testing goodwill and
other intangible assets for impairment. Under this statement, goodwill as
well as other intangibles determined to have an infinite life will no
longer be amortized. These assets are required to be reviewed for
impairment on a periodic basis. This statement is effective for the Company
July 1, 2002. Management does not believe the adoption of this statement
will have a material effect on the Company's financial position or results
of operations.
34
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." SFAS No. 143 provides the accounting requirements
for retirement obligations associated with long-lived assets. The statement
requires companies to recognize the fair value of an asset's retirement
liability in the financial statements by capitalizing that cost as part of
the cost of the related long-lived asset, which will then be systematically
allocated to expense. The statement is effective for the Company July 1,
2002. As a preponderance of the Company's wells are within the Appalachian
Basin, which are historically long-lived, disposal costs have been
negligible. Therefore, management does not believe the adoption of this
statement will have a material effect on the Company's financial position
or results of operations.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." This statement provides a
single accounting model for long-lived assets to be disposed of and changes
the criteria that would have to be met to classify an asset as
held-for-sale. The statement also requires expected future operating losses
from discontinued operations to be recognized in the periods in which the
losses are incurred. The statement is effective for the Company July 1,
2002. Management does not believe the adoption of this statement will have
a material effect on the Company's financial position or results of
operations.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13 and Technical
Corrections." One of the statement's requirements is to classify the
resulting gain or loss from early debt retirement as ordinary income.
Although the statement is effective in fiscal years beginning after May 15,
2002, the Company has elected early adoption. Therefore, the gain on the
early extinguishment of debt during fiscal 2001 has been reclassified from
extraordinary to other non-operating income. The adoption of the statement
did not have a net effect on the Company's financial position or results of
operations.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." The statement addresses
financial accounting and reporting for costs associated with exit or
disposal activities as certain costs were recognized as liabilities that
did not meet the definition of a liability. This statement is effective for
all exit or disposal activities initiated after December 31, 2002.
Management does not believe the adoption of this statement will have a
material effect on the Company's financial position or results of
operations.
Supplemental Disclosures of Cash Flow Information - Supplemental cash flow
--------------------------------------------------
information for the years ended June 30 is as follows (in thousands):
2002 2001 2000
------- ------- -------
Cash paid for:
Interest $18,935 $19,210 $21,360
Income taxes, net 114 37,983 242
Noncash investing and financing activities:
Dividends declared and unpaid at year end 262 265 -
Liabilities assumed in acquisition - 824 -
35
3. ACQUISITIONS
On December 29, 2000, the Company purchased Penn Virginia Oil and Gas
Corporation's ("Penn Virginia") interests in various oil and gas leases,
wells, pipelines, contracts, partnership interests, right-of-ways, personal
property and tax credits. After certain adjustments, the Company paid $57.2
million in cash and assumed a $0.8 million note.
On July 6, 2001, the Company paid $18.1 million for interests in various
oil and gas leases, seismic and technical data, contracts, right-of-ways
and real and personal property in Texas. The acquisition had an effective
date before year-end and as a result was recorded at June 30, 2001 with the
purchase price reflected in other current liabilities. Also during fiscal
year 2002, the Company increased its working interest in Texas properties
to 80% in deep rights and 40% in shallow rights through the acquisition of
a net 5,400 acres for $0.36 million.
A deposit of $1.2 million was paid for the purchase of certain oil and gas
properties located in southern West Virginia. The total acquisition will be
$6.0 million. The purchase includes proved developed producing gas
reserves, estimated at 4 Bcf, 90 producing wells and over 30,000 acres.
This acquisition is subject to the approval of the Public Service
Commission of West Virginia.
The Company purchased an interest in Alliance Energy Services Partnership
for $2.8 million. The Company anticipates future expenditures related to
this investment. The investment is accounted for under the cost method, as
the Company does not have significant influence over management and
operation of the partnership. The partnership provides energy solutions to
customers.
4. DISPOSITIONS
On August 18, 2000, the Company sold all of the stock of its wholly owned
natural gas distribution company, Mountaineer, to a subsidiary of Allegheny
Energy, Inc. ("Allegheny") for approximately $325.7 million, which included
the assumption of $100.1 million of debt and payment of approximately
$225.6 million to the Company. The Company realized an after-tax gain of
$84.4 million on this transaction. Net proceeds from the sale were subject
to certain reinvestment provisions of the Company's $200 million Senior
Subordinated Notes (the "Notes").
The operating results of the discontinued operations for the years ended
June 30 are as follows (in thousands):
2002 2001 (1) 2000
----- --------- --------
Net sales $ - $ 9,929 $178,882
----- --------- --------
Income (loss) before income taxes - (3,164) 11,048
Income taxes provision (benefit) - (1,317) 3,691
----- --------- --------
Income (loss) from discontinued operations $ - $ (1,847) $ 7,357
===== ========= ========
(1) Discontinued operations for one and one half months in fiscal year 2001
5. RISK MANAGEMENT
The Company periodically hedges a portion of its oil and gas production
through futures and swap agreements. The purpose of the hedge 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, 2002 are designated as cash flow hedges. At June 30, 2001, the Company
had swap agreements maturing from July 2001 through December 2002 covering
36
4,455,700 Mmbtu. At June 30, 2001 the company had recorded a $2.5 million
gain in accumulated other comprehensive income, $4.4 million of short term
derivative assets, $0.3 million short term derivative liabilities, $0.1
million long term derivative liability and $1.5 million in deferred tax
liability. At June 30, 2002, the Company had swap agreements maturing from
July 2002 through June 2004 covering 2,292,200 Mmbtu. As of June 30, 2002
the Company has recorded a $0.3 million gain in accumulated other
comprehensive income, $0.4 million in short term derivative asset, $0.1
million in long term derivative asset, $0.1 million short term derivative
liability, and $0.1 million in deferred tax liability.
For the year ended June 30, 2002 the Company recognized a net gain in
revenues on its natural gas hedging activities of $6.7 million. For the
years ended June 30, 2001 and 2000, the Company recognized a net loss in
revenues on its natural gas hedging activities of $8.3 million and $0.9
million, respectively. The estimated net amount of the existing gains
within other comprehensive income that are expected to be reclassified into
earnings within the next 12 months is approximately $0.3 million.
6. DEBT
Long-Term Debt - At June 30 long-term debt consisted of the following (in
---------------
thousands):
2002 2001
--------- ---------
ECA senior subordinated notes, interest at 9.5% payable
semi-annually, due May 15, 2007 $197,672 $197,672
Installment notes payable, at imputed interest rates ranging from
from 8.0% to 9.5% 1,150 1,381
--------- ---------
198,822 199,053
Less current portion (121) (151)
--------- ---------
$198,701 $198,902
========= =========
The Company's debt agreement contains certain restrictions and conditions
among which are limitations on indebtedness, dividends and investments, and
certain interest coverage ratio requirements. The agreement requires the
Company to maintain certain financial covenants, including restriction on
funded debt and restrictions on the amount of dividends that can be
declared.
Scheduled maturities of the Company's long-term debt at June 30, 2002 for
each of the next five years and thereafter are as follows (in thousands):
2003 $ 213
2004 213
2005 213
2006 213
2007 197,781
Thereafter 684
--------
Total payments 199,317
Less: imputed interest 495
--------
Present value of scheduled maturities $198,822
========
37
Early Extinguishment of Senior Subordinated Notes - On November 9, 2000,
----------------------------------------------------
the Company commenced a tender offer to purchase, for cash, all of the
Notes at a purchase price of $750 per $1,000 principal amount of Notes plus
accrued and unpaid interest. The offer to purchase the Notes expired on
December 11, 2000. Approximately $2.3 million of the notes were tendered
and retired, which resulted in a gain of $0.56 million.
Revolving Credit - On July 10, 2002, the Company entered into a $50 million
----------------
revolving Credit Agreement (the "Agreement") with Foothill Capital
Corporation ("Foothill"). Depending on its level of borrowing under the
Agreement, the applicable interest rates are based on Wells Fargo's prime
rate plus 0.50% to 2.50%. The Agreement expires on July 10, 2005. The
Agreement is secured by approximately 80% of the existing oil and gas
assets of the Company. The Agreement, among other things, restricts the
ability of the Company and its subsidiaries to incur new debt, grant
additional security interests in its collateral, engage in certain merger
or reorganization activities, or dispose of certain assets. Upon the
occurrence of an event of default, the lenders may terminate the Agreement
and declare all obligations thereunder immediately due and payable. As of
September 20, 2002, there are currently $10 million in outstanding
borrowings under the Agreement.
Other Credit Facilities - The Company has an unsecured revolving line of
-------------------------
credit totaling $2 million with a financial institution with an interest
rate of prime plus 0.5%, which expires November 30, 2002. There were no
amounts outstanding under the line of credit as of June 30, 2002 and 2001
respectively.
Other Notes - In December 2000, the Company assumed a note as part of the
------------
Penn Virginia acquisition. Per the agreement, the Company will pay
consecutive equal monthly payments with the first scheduled payment to be
made by the Company on January 15, 2000 and the final scheduled payment due
on April 15, 2014. As of June 30, 2002 and 2001, the balance due was $1.2
million and $1.3 respectively.
The Company purchased certain pipelines during 1998 constituting a natural
gas gathering system in the State of West Virginia. The Company will pay
the seller $1.2 million for the facilities. In accordance with the
agreement, the Company paid $0.3 million at closing with the balance due to
the seller in one hundred consecutive equal monthly installments beginning
in March 1998. As of June 30, 2002 and 2001, the balance due to the seller
was $0.5 and $0.6 million respectively.
7. INCOME TAXES
The following table summarizes components of the Company's provision
(benefit) for income taxes for the years ended June 30 (in thousands):
2002 2001 2000
--------- --------- ---------
Current:
Federal $ (3,436) $(27,749) $ (666)
State 1,385 (7,842) (46)
--------- --------- ---------
Total current (2,051) (35,591) (712)
--------- --------- ---------
Deferred:
Federal (13,381) 23,115 (11,477)
State (1,390) 5,244 378
--------- --------- ---------
Total deferred (14,771) 28,359 (11,099)
--------- --------- ---------
Total benefit for income taxes $(16,822) $ (7,232) $(11,811)
========= ========= =========
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):
38
2002 2001 2000
--------- -------- ---------
Tax benefit at the federal statutory rate $(15,051) $(6,101) $(13,028)
State taxes, net of federal tax effects (2,516) (1,151) (1,781)
Effect of rate change 103 (176)
Section 29 tax credits - (2,277)
Change in valuation allowance on federal, foreign
and state deferred tax assets, net of federal effect (2,048) 2,000
Investment tax credit expiration 532
Other, net 2,690 2,473 466
--------- -------- ---------
Benefit for income taxes $(16,822) $(7,232) $(11,811)
========= ======== =========
Components of the Company's deferred tax assets and liabilities, as of June
30 are as follows (in thousands):
2002 2001
--------- ---------
Deferred tax assets:
Royalty Trust agreements $ 7,830 $ 7,501
Tax credits and carryforwards 10,113 3,710
Other 3,874 3,238
--------- ---------
Total deferred tax assets 21,817 14,449
--------- ---------
Deferred tax liabilities:
Property, plant and equipment (25,249) (27,545)
Federal income tax on state tax credits - (1,261)
Other liabilities (4,218) (4,913)
--------- ---------
Total deferred tax liabilities (29,467) (33,719)
--------- ---------
Valuation allowance - (3,151)
--------- ---------
Net deferred income tax liability (7,650) (22,421)
Current deferred tax asset 2,237 7,467
--------- ---------
Net long-term deferred tax liability $ (9,887) $(29,888)
========= =========
At June 30, 2002 the Company has the following federal and state tax credits and
carryforwards (in thousands):
Year of
Amount Expiration
------- ----------
AMT tax credits $ 9,355 None
-------
Total federal credits $ 9,355
=======
Net operating loss carryovers $ 758 2005-2021
-------
Total state carryovers $ 758
=======
At June 30, 2001, the Company had West Virginia state tax credits of $3.7
million. The Company was eligible for relocation incentives taken in the
form of tax credits from West Virginia. The incentive amounts were based
upon investments made and jobs created in that state. Tax credits generated
by the Company were used primarily to offset the payment of severance,
property and state income taxes. Based on the then existing future taxable
temporary differences and projections of future West Virginia severance,
property and state income taxes, management had provided a valuation
allowance of $3.2 million for that portion of the credits that were not
expected to be utilized. At June 30, 2002 the Company had utilized the
entire $3.7 million of WV state tax credits and had reversed the related
$3.2 million valuation allowance.
39
8. 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; $1.3 million and $0.9 million of profit sharing
expense during the years ended June 30, 2002, 2001 and 2000.
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 $0.39 million, $0.24 million and $0.23 million
for the years ended June 30, 2002, 2001, and 2000.
9. 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 agreements with a stockholder covering the sale or
disposition of common stock that provides the stockholder cannot sell stock
without first offering such shares to the Company. At June 30, 2002 49,710
shares were subject to the agreements. 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.
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.
Treasury Stock - At June 30, 2002, the Company had 104,984 shares of voting
--------------
common stock in treasury, carried at cost. The Company purchased 10,630 and
16,342 shares of voting common stock during the years ended June 30, 2002
and 2001, respectively. At June 30, 2002, the Company had 14,380 shares of
non-voting Class A stock in treasury, carried at cost. The Company
purchased 3,993 and 4,160 shares of non-voting Class A stock during the
years ended June 30, 2002 and 2001.
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 per share,
based on the fair market value as determined by the Board of Directors and
are exercisable based on the following schedule:
40
Number of
Exercise Period Shares
- ------------------------------------- ---------
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
=========
No options were exercised for either of the years ended June 30, 2002 or
2001. Therefore, as of June 30, 2002, all the options were exercisable.
Fair value of the options at the grant dates, as estimated by management,
was nominal.
10. EARNINGS PER SHARE
A reconciliation of the components of basic and diluted net loss from
continuing operations per common share for the years ended June 30 is as
follows:
2002 2001 2000
--------- -------- ---------
Earnings (loss) (in thousands) $(26,180) $(10,199) $(26,508)
Shares 657,707 664,673 660,928
Per share amount $ (39.80) $ (15.34) $ (40.11)
The effect of stock options was not included in the computation of diluted
net loss per share because to do so would have been antidilutive.
11. UNCONSOLIDATED AFFILIATE
The Company owns a 25.35% members' interest in Breitburn Energy Corporation
("BEC"). The Company's investment in BEC is accounted for under the equity
method. Although BEC has current year earnings, the Company's share of net
losses since inception continues to exceed the carrying amount of the
investment. Therefore, 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
December 31, is as follows (in thousands):
41
2002 2001 2000
-------- -------- --------
Current assets $ 11,336 $10,744
Oil and gas properties 100,833 84,050
Other assets 1,966 3,233
-------- --------
Total assets $114,135 $98,027
======== ========
Current liabilities $ 14,505 $12,955
Long-term debt 51,700 54,200
Other liabilities 8,092 1,433
Redeemable preferred shares 34,287 33,650
Members' equity (deficit) 1,764 (4,211)
Accumulated other comprehensive income 3,787 -
-------- --------
Total liabilities and equity $114,135 $98,027
======== ========
Net sales $ 46,160 $36,551 $19,722
Operating income 14,578 9,338 200
Net income (loss) $ 10,259 $ 5,267 $(1,517)
12. OPERATING LEASES
The Company has noncancelable operating lease agreements for the rental of
office space, computers and other equipment. Certain of these leases
contain purchase options or renewal clauses. Rental expense for operating
leases was approximately $1.4 million, $1.3 million and $1.2 million for
the years ended June 30, 2002, 2001 and 2000.
At June 30, 2002 future minimum lease payments for each of the next five
years and thereafter are as follows (in thousands):
2003 $1,277
2004 1,103
2005 909
2006 98
2007 16
Thereafter 32
------
$3,435
======
13. RELATED PARTY TRANSACTIONS
The Company has entered into a rental arrangement for office space from a
corporation in which certain officers are shareholders. Rent payments
totaled $0.56 million, $0.56 million and $0.42 million for the years ended
June 30, 2002, 2001 and 2000.
The Company advanced funds to certain officers and other related parties,
at 7% to 8% interest. Balances totaled $0.3 million and $0.6 million, at
June 30, 2002 and 2001. A provision in the agreement cancels the principal
balance if the employee remains in the continuous employment of the Company
for three to four years, depending on the agreement.
42
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 carrying value of these notes was $0.2 million
at June 30, 2002 and $0.9 million at June 30, 2001. The notes have interest
rates of 6.5% and 8%. A provision in the agreements 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 for promissory notes. The carrying value of
these notes was $0.19 million at June 30, 2002 and 2001. Interest rates are
calculated at LIBOR plus 1.5%. No cancellation provision was included with
this stock incentive program.
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. The
remaining book value of this asset at June 30, 2002 is $1.0 million.
14. COMMITMENTS AND CONTINGENCIES
In 1993, the Company sold working interests in certain Appalachian gas
properties in connection with the formation of the Eastern American Natural
Gas Trust ("Royalty Trust"). 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 is currently classified as other current
and long-term liabilities. As of June 30, 2000, the Company determined that
due to the rising cost of transporting gas, the total deferred revenue
would not be realizable. Therefore, $4.9 million, the amount related to the
royalty portion, was impaired and $6.2 million, the amount related to the
term portion, was reclassified to other current and long-term liabilities.
These amounts are amortized as the associated volumes are sold. The
remaining unamortized other current and long-term liabilities are $9.0 and
$10.0 million at June 30, 2002 and 2001, respectively.
The Company has a gas sales contract, which requires the Company to sell up
to 4,800 but not less than 3,200 Mmbtu per day beginning January 1, 2002
through December 31, 2003. Under the contract the Company receives a 10.5
cent to 15.5 cent premium above the posted Appalachian Index.
The Company entered into a gas sale and purchase agreement with Allegheny
whereby it began the delivery of natural gas on November 1, 2001. The
Company received a $10 million prepayment pursuant to the agreement, which
is recorded as 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.
On November 30, 2001, the Company entered into a natural gas sales contract
with Mountaineer Gas Company, doing business as Allegheny Power, to deliver
5,500 Dth per day. Under the pricing terms, the Company will never receive
less than $2.75 per Dth plus the Columbia Gas Transmission ("TCO")
Appalachia Basis or more than $4.85 per day plus the TCO Appalachia Basis.
The contract began on December 1, 2001 and continues through October 31,
2004.
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.
43
15. 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 are not necessarily
indicative of the amount that the Company could realize upon the sale or
refinancing of such financial instruments. 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 - 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. At June 30, 2002, the fair value of
the Company's debt was $129.6 million and the book value was $198.8
million.
Derivative Financial Instruments - All derivative instruments held by the
----------------------------------
Company are designated as hedges, have high correlation with the underlying
exposure and are highly effective in offsetting underlying price movements.
Accordingly, gains and losses from changes in derivative fair values are
deferred until the underlying transaction occurs. Gains or losses are then
recognized in the income statement or recorded as part of the underlying
assets or liability, depending on the circumstances. Derivative positions
are settled if the underlying transaction is no longer expected to occur,
with the related gains and losses recognized in earnings in the period
settlement occurs. Option premiums paid are recorded as assets and expensed
over the life of the option. Derivatives generally have initial terms of
less than three years, and all currently hedged transactions are expected
to occur within the next three years. See Note 5 for additional information
regarding the Company's derivative holdings.
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, income taxes, depreciation, depletion,
amortization and impairment 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
drilling rig operations and corporate items (in thousands):
44
Exploration Marketing
and and
Production Pipeline Other Consolidated
------------- ----------- -------- --------------
2002
Sales to unaffiliated customers $ 44,429 $ 41,209 $ 504 $ 86,142
Depreciation, depletion, amortization 13,741 859 696 15,296
Impairment and exploratory costs 26,127 89 1,478 27,694
Operating profit (loss) (22,775) 279 (2,292) (24,788)
Interest expense, net 21,238 (6,922) 3,663 17,979
EBITDAX 18,795 1,498 (635) 19,658
Total assets 186,587 78,226 39,923 304,736
Capital expenditures 33,679 145 4,470 38,294
- --------------------------------------------------------------------------------------------
2001
Sales to unaffiliated customers $ 45,906 $ 81,042 $ 1,455 $ 128,403
Intersegment revenues 1,548 1,548
Depreciation, depletion, amortization 10,653 973 427 12,053
Impairment and exploratory costs 11,458 287 7,269 19,014
Operating profit (loss) (3,595) 41 168 (3,386)
Interest expense, net 13,521 (5,355) 4,237 12,403
EBITDAX 19,759 1,316 12,656 33,731
Total assets 201,111 77,977 101,444 380,532
Capital expenditures 108,343 1,315 3,205 112,863
- --------------------------------------------------------------------------------------------
2000
Sales to unaffiliated customers $ 29,763 $ 72,156 $ 101,919
Depreciation, depletion, amortization 10,349 1,031 359 11,739
Impairment and 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
- --------------------------------------------------------------------------------------------
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, including
drilling rig, corporate and elimination items. Included in the exploration
and production segment are net long-lived assets located in New Zealand of
$3.4 million, $3.0 million and $3.9 million, as of June 30, 2002, 2001 and
2000 and any related revenues and expenses.
17. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
The following represents selected quarterly financial information for the
years ended June 30 (in thousands, except per share data):
45
Quarter Ended
----------------------------------------------------
2002 September 30 December 31 March 31 June 30
-------------- ------------- ---------- ---------
Total revenue $ 23,394 $ 21,157 $ 18,573 $ 23,018
Gross profit (loss) 1,943 1,119 (3,585) (24,265) *
Loss from continuing operations (1,517) (2,086) (5,358) (17,219)
Loss per share on continuing
operations, basic and diluted (2.31) (3.17) (8.15) (26.17)
Net loss (1,517) (2,086) (5,358) (17,219)
Quarter Ended
----------------------------------------------------
2001 September 30 December 31 March 31 June 30
-------------- ------------- ---------- ---------
Total revenue $ 27,083 $ 31,898 $ 45,109 $ 25,861
Gross profit (loss) 1,473 1,363 (2,386) (3,836)
Loss from continuing operations (1,847) 106 (3,590) (4,868)
Earnings (loss) per share on continuing
operations, basic and diluted (2.77) 0.19 (5.41) (7.35)
Net income (loss) 82,661 (939) (3,622) (5,744)
*Gross profit decreased by $20.7 million from the quarter ended March 31,
2002 to the quarter ended June 30, 2002 primarily as a result of
exploratory dry hole cost and impairment recorded in the fourth quarter.
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
Costs - The following tables set forth capitalized costs and costs incurred,
- -----
including capitalized overhead, for oil and gas producing activities for the
years ended June 30 (in thousands):
2002 2001 2000
--------- --------- ---------
Capitalized costs:
Proved properties $310,495 $271,465 $208,271
Unproved properties 9,653 45,760 10,988
--------- --------- ---------
Total 320,148 317,225 219,259
Less accumulated depletion and depreciation (97,523) (85,748) (76,458)
--------- --------- ---------
Net capitalized costs $222,625 $231,477 $142,801
========= ========= =========
Company's share of equity method investee's net
capitalized costs (see Note 11) $ 25,185 $ 19,690 $ 18,693
========= ========= =========
Costs incurred:
Acquisition of proved and unproved properties $ 717 $ 80,394 $ 4,160
Development costs 10,977 13,649 5,869
Exploration costs 20,737 15,115 8,693
--------- --------- ---------
Total costs incurred $ 32,431 $109,158 $ 18,722
========= ========= =========
Company's share of equity method investee's total
costs incurred (see Note 11) $ 7,661 $ 3,594 $ 7,759
========= ========= =========
46
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):
2002 2001 2000
-------- ------- --------
Revenues from sale of oil and gas $38,939 $41,555 $23,869
Less:
Production costs 5,001 3,011 1,658
Production taxes 2,077 3,000 1,198
Exploration and impairment 27,605 11,458 8,347
Depletion, depreciation and amortization 12,362 9,290 8,847
Income tax expense (benefit) (2,999) 5,475 (1,181)
-------- ------- --------
Income (loss) from oil and gas operations $(5,107) $ 9,321 $ 5,000
======== ======= ========
Company's share of equity method investee's
income from oil and gas operations (see Note 11) $ 1,129 $ 5,054 $ 1,857
======== ======= ========
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.
Depletion, depreciation and amortization include costs associated with
capitalized acquisitions, 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.
47
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.
Natural Gas Crude Oil
(Mmcf) (Mbbls)
------------ ----------
Proved reserves:
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
Revisions of previous estimates (13,405) (99)
Extensions and discoveries 22,077 1,380
Purchases of reserves in place 49,665 485
Production (9,371) (116)
------------ ----------
June 30, 2001 206,456 2,633
Revisions of previous estimates (23,812) 74
Extensions and discoveries 10,642 368
Purchases of reserves in place
Production (9,941) (124)
------------ ----------
June 30, 2002 183,345 2,951
============ ==========
Proved developed reserves:
June 30, 2000 141,067 738
June 30, 2001 175,784 987
June 30, 2002 160,224 1,135
Company's share of equity method investee's proved reserve at:
June 30, 2000 7,402 13,681
June 30, 2001 9,497 11,811
June 30, 2002 7,445 12,063
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. 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.
48
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):
2002 2001 2000
---------- ---------- ----------
Future cash in flows $ 715,755 $ 828,403 $ 606,382
Future production and development costs (243,828) (271,051) (178,968)
Future income tax expense (116,000) (145,000) (121,000)
---------- ---------- ----------
Future net cash flows before discount 355,927 412,352 306,414
10% discount to present value (205,014) (240,071) (181,543)
---------- ---------- ----------
Standardized measure of discounted future net cash
flows related to proved oil and gas reserves $ 150,913 $ 172,281 $ 124,871
========== ========== ==========
Company's share of equity method investee's
standardized measure of discounted future net
cash flows $ 53,838 $ 69,478 $ 54,362
========== ========== ==========
Principal changes in the standardized measure of discounted future net cash
flows for the years ended June 30 are as follows (in thousands):
2002 2001 2000
--------- --------- ---------
Standardized measure of discounted future
net cash flows at beginning of period $172,281 $124,871 $ 84,883
Sales of oil and gas produced, net of
production costs (26,525) (28,347) (13,446)
Net changes in prices and production costs (13,507) 3,338 57,741
Changes in production rates and other (5,867) 15,526 (10,418)
Extensions, discoveries and other additions, net
of future production and development costs 13,622 33,991 2,886
Changes in estimated future development costs (4,820) (31,981) 2,099
Development costs incurred 10,977 9,232 5,869
Revisions of previous quantity estimates (24,772) (15,677) 5,731
Purchase of reserves in place 58,868 10,572
Accretion of discount 17,228 12,487 8,488
Net change in income taxes 12,296 (10,027) (29,534)
--------- --------- ---------
Standardized measure of discounted
future net cash flows at end of period $150,913 $172,281 $124,871
========= ========= =========
* * * * *
49
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.
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, 2002 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 2001
annual meeting of stockholders. Executive officers are appointed by the Board of
Directors.
John Mork 54 President and Chief Executive Officer; Director
Joseph E. Casabona 59 Executive Vice President; Director
Michael S. Fletcher 53 Chief Financial Officer
Donald C. Supcoe 46 Senior Vice President, Secretary and General Counsel
Edward J. Davies 60 Senior Vice President
J. Michael Forbes 42 Vice President and Treasurer
K. Ralph Ranson, II 60 Vice President Marketing
Julie Ann Kitano 46 Assistant Secretary
W. Gaston Caperton, III 61 Director
Peter H. Coors 54 Director
L. B. Curtis 77 Director
John J. Dorgan 77 Director
Arthur C. Nielsen, Jr. 82 Director
F. H. McCullough, III 54 Director
Julie Mork 51 Director
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, United Bankshares, West Virginia
Media Holdings, the Benedum Foundation, National Center for Learning
Disabilities, and Classroom, Inc.
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"), Certified Public Accountants, 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.
50
Peter H. Coors has been a Director of the Company since 1996. Mr. Coors is
Chairman of Coors Brewing Company and President 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 U. S. Bankcorp, Inc. and H.J. Heinz Company. Mr. Coors
is a trustee and member of the executive board of the Denver Area Council of the
Boy Scouts of America and a member of the executive committee for the National
Western Stock Show Association. He is also a member of the International Chapter
of Young Presidents' Organization, a member of the Advisory Board for the
University of Denver's Daniels School of Business, and a trustee for the Adolph
Coors Foundation, Castle Rock Foundation, Seeds of Hope Foundation and the
University of Northern Colorado.
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 is Senior Vice President of the Company. 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 of the Company since
December 1999. He also held the position of Treasurer of the Company from
December 1999 through December 2000. In addition, Mr. Fletcher was President of
Mountaineer Gas Company from August 1998 until the Company sold Mountaineer in
August 2000. Prior to August 1998, 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 graduate from Utah State University with a Bachelor Degree in
Accounting.
J. Michael Forbes is Vice President and Treasurer of the Company. Mr.
Forbes has been an officer of the Company since 1995 and prior to that 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.
Julie Ann Kitano has been Assistant Secretary of the Company since December
2000. Ms. Kitano joined the Company in 1998 as a Paralegal. She holds a Bachelor
of Arts Degree from Whitman College.
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 telecommunications carrier. Mr. McCullough is a graduate
51
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 Director
of the Independent Petroleum Association of America, and the Independent Oil and
Gas Association of West Virginia. Mr. Mork was a member of and held various
positions with the Young Presidents' Organization from 1984-1998. He 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.
K. Ralph Ranson, II, has been Vice President of Marketing for the Company
since December 2000. He joined Eastern American in 1993 and has served in
various capacities, most recently as Vice President of Land. Prior to joining
Eastern American, Mr. Ranson worked as an independent oil and gas consultant,
was an officer with Alamco, Inc. and an officer and director of Union Drilling,
Inc. Mr. Ranson is past President of the Independent Oil & Gas Association of
West Virginia, where he served two consecutive terms. Mr. Ranson received a
Bachelor of Arts Degree from West Virginia Wesleyan College.
Donald C. Supcoe is the Senior Vice President, Corporate Secretary and
General Counsel of the Company and is responsible for the Company's operations
in the east, which includes Eastern American. Mr. Supcoe was the Senior Vice
President of Mountaineer Gas Company from August 1998 until its sale in August
2000. Prior to joining Mountaineer in August of 1998, he was the Vice
President, General Counsel and Corporate Secretary of Eastern American with whom
he had been employed in various positions 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.
52
ITEM 11. EXECUTIVE COMPENSATION
-------------------------------
The following table sets forth for fiscal year 2002 the total value of
compensation of (i) the Company's Chief Executive Officer and (ii) each other
executive officer of the Company.
Annual Compensation
-------------------- All Other
Year Salary Bonus Other Compensation (1)
---- -------- ---------- -------- -----------------
John Mork 2002 $258,892 $ 125,000 $ 59,670 $ 26,067
President and Chief Executive Officer 2001 256,068 1,146,635 4,349 35,251
2000 253,141 116,350 29,041 11,010
Joseph E. Casabona 2002 $238,277 $ 125,942 $ 2,905 $ 4,574
Executive Vice President 2001 231,538 1,457,630 (2) 1,888 4,454
2000 223,762 55,853 2,603 8,760
Michael S. Fletcher 2002 $233,306 $ 100,510 $ 352 $ 4,504
Chief Financial Officer 2001 232,471 56,345 124,198 (3) 3,500
2000 228,298 168,702 19,496 10,557
Edward J. Davies 2002 $223,930 $ 95,714 $ 120 $ 4,592
Senior Vice President 2001 207,308 53,105 899 4,181
2000 184,885 31,000 1,507 4,080
Donald C. Supcoe 2002 $197,993 $ 100,435 $ 2,325 $ 3,949
Senior Vice President 2001 188,447 54,545 1,482
2000 180,833 41,599 27,987 216
- --------------------------------
(1) Includes compensation related to insurance policies provided for the benefit of named officer
and 401K matching contributions.
(2) Includes $900,000 received as Class A stock and $340,000 cash as related tax protection.
(3) Includes the forgiveness of debt to the Company.
DIRECTOR COMPENSATION. Directors are compensated $2,000 per meeting plus
----------------------
reimbursement for travel and related expenses. The Chairman of the Board
receives an additional $50,000. Annually, each Director also receives 160
shares of the Company's Class A Stock. During the current fiscal year, each
Director received the option of an additional 1,000 shares of the Company's
Common Stock or 600 shares and $60,000. Directors John Mork and Julie Mork, his
wife, declined the offer of either cash or shares. The total Board of
Directors' compensation for fiscal 2002 was $1.3 million.
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
53
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
August 31, 2002. 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.
Beneficial Ownership
Common Stock
-----------------
Shares Percent
------- --------
Kenneth W. Brill (1) 49,710 7.96%
W. Gaston Caperton, III 6,680 1.07%
Joseph E. Casabona 31,376 5.02%
Peter H. Coors 2,946 *
L. B. Curtis 11,610 1.86%
Edward J. Davies 3,000 *
John J. Dorgan 2,130 *
Michael S. Fletcher 1,000 *
J. Michael Forbes 2,200 *
F. H. McCullough, III (3) 71,009 11.37%
John Mork (2) 361,743 57.93%
Julie Mork (2) 361,743 57.93%
Arthur C. Nielsen, Jr. 36,480 5.84%
K. Ralph Ranson, II 800 *
Donald C. Supcoe 3,583 *
584,267 93.56%
All officers and directors as a group (14 persons)
- ---------------
* Less than one percent.
(1) Pursuant to agreements Kenneth W. Brill granted the Company options to
purchase all of the Company's Common Stock owned by him.
(2) Includes 353,180 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 68,929 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.
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 August 31, 2002. The business
address of each officer and director listed below is: c/o Energy Corporation of
American, 4643 South Ulster Street, Suite 1100, Denver, Colorado 80237.
54
Beneficial Ownership
Class A Stock
----------------
Shares Percent
------ --------
Dale P. Andrews 443 1.42%
W. Gaston Caperton, III 1,920 6.17%
Joseph E. Casabona 5,119 16.45%
Peter H. Coors 2,534 8.14%
L.B. Curtis 1,720 5.53%
Edward J. Davies 2,439 7.84%
John J. Dorgan 2,320 7.46%
Michael S. Fletcher 1,460 4.69%
F.H. McCullough, III 1,920 6.17%
John Mork (1) 3,458 11.11%
Julie Mork (1) 3,458 11.11%
Arthur C. Nielsen, Jr. 3,080 9.90%
K. Ralph Ranson, II 487 1.57%
Donald C. Supcoe 1,877 6.03%
28,777 92.48%
All officers and directors as a group (14 persons)
- ---------------
(1) Includes 2,116 shares held by John and Julie Mork as joint tenants and
1,342 shares held by Julie Mork individually.
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
following table identifies the participants' aggregate investment in the
calendar years shown (in thousands):
55
2002 2001 2000
---------- --------- ---------
(3)
Dale P. Andrews $ 12.63
Gaston Caperton, III $ 100.02 $ 56.76 98.58
Joseph E. Casabona 50.01 21.99 49.18
Peter Coors 100.02 28.38 49.18
L.B. Curtis 107.50 88.85 126.39
E.J. Davies 215.00 140.78 126.39
John J. Dorgan 25.00 14.19 24.59
Michael S. Fletcher 50.01 28.38 49.18
J. Michael Forbes 25.00 14.19
John Frederick 14.19
Thomas R. Goodwin 50.01 28.38 172.14
John Mork (1) 1,075.00 703.89 758.34
Alison Mork Trust (2) 50.01 28.38 24.59
Kyle Mork Trust (2) 50.01 28.38 24.59
Arthur C. Nielsen, Jr. 50.01 28.38 49.18
Kent Schamp 27.31 15.34 25.28
Donald C. Supcoe 25.00 14.19 -
---------- --------- ---------
$1,999.91 $1,254.65 $1,590.24
========== ========= =========
(1) Interest of John Mork and Julie Mork held as joint tenants.
(2) Trusts for the children of John Mork and Julie Mork.
(3) These amounts represent only the amounts committed to the 2002 Drilling
Program, the actual investment may vary based on the number of wells
drilled and the related costs.
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. The Company is amortizing the notes over their seven
year life and assuming continued employment. Certain of these notes will be
forgiven one-quarter per year, starting December 31, 2002. The following were
indebted to the Company (in thousands):
Unamortized
Original as of
Note June 30, 2002
--------- --------------
Dale P. Andrews $ 63 $ 21
Joseph E. Casabona 187 63
Michael S. Fletcher 187 63
J. Michael Forbes 96 96
K. Ralph Ranson, II 28 13
Donald C. Supcoe 209 133
--------- --------------
Total $ 770 $ 389
========= ==============
Certain officers, Directors and key employees of the Company have borrowed
money from the Company and have executed promissory notes. The notes bear
interest at 7% to 8% per annum. The following were indebted to the Company (in
thousands):
56
Note Plus Unamortized
Accrued as of
Interest June 30, 2002
---------- --------------
(1) Michael S. Fletcher $ 265 $ 83
(1) Linda Given 26 8
(1) David Jordan 52 16
(2) Dennis McGowan 49 49
(1) Donald C. Supcoe 158 49
---------- --------------
$ 550 $ 205
========== ==============
(1) Promissory note is being forgiven and amortized over three years, assuming
continuing employment.
(2) Promissory note is being forgiven and amortized over four years, assuming
continuing employment.
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 as of June
30, 2002:
Payment Volumes
(in thousands) Mmcf
--------------- -------
Dale P. Andrews $ 20 26.7
Gaston Caperton, III 600 800.0
Joseph E. Casabona 50 66.7
Peter Coors 50 66.7 (1)
L.B. Curtis 150 200.0
E.J. Davies 150 200.0
John J. Dorgan 50 66.7
F.H. McCullough, III 150 200.0
John Mork 750 1,000.0 (1)
Alison Mork Trust 50 66.7 (1)
Kyle Mork Trust 50 66.7 (1)
Arthur C. Nielsen, Jr. 94 125.3 (1)
--------------- -------
$ 2,164 2,885.5
=============== =======
(1) During fiscal year 2002, all interest in these properties was assigned to
the Company for nominal consideration
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 $0.56 million for fiscal year 2002. The Company believes that
such rental terms are no less favorable than could have been obtained from an
unaffiliated party.
57
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 report:
* 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 Intentionally omitted.
* 4.2 Intentionally omitted.
* 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 Intentionally omitted.
* 10.6 Intentionally omitted.
* 10.7 Intentionally omitted.
* 10.8 Intentionally omitted.
* 10.9 Intentionally omitted.
* 10.10 Intentionally omitted.
58
* 10.11 Intentionally omitted.
* 10.12 Intentionally omitted.
* 10.13 Intentionally omitted.
* 10.14 Intentionally omitted.
* 10.15 Intentionally omitted.
* 10.16 Intentionally omitted.
* 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.
* 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 Intentionally omitted.
* 10.28 Intentionally omitted.
* 10.29 Intentionally omitted.
* 10.30 Intentionally omitted.
* 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 Intentionally omitted.
* 10.34 Intentionally omitted.
* 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.
59
* 10.37 Purchase and Sale Agreement dated June 28, 2001
between Tavener E&P Ltd and Westech Energy Corporation.
* 10.38 Credit Agreement dated July 10, 2002 between Energy
Corporation of America and Foothill Capital Corporation,
as the Arranger and Administrative Agent for the Lenders.
10.39 Purchase and Sale Agreement dated August 2, 2002
between East Resources, Inc. and Energy Corporation of
America, without exhibits thereto.
10.40 Amendment, effective as of June 29, 1997, to Buy-Sell
Stock Option Agreement between Energy Corporation of
America and Kenneth W. Brill.
10.41 Agreement dated December 28, 1998 between Energy
Corporation of America and Kenneth W. Brill.
21.1 Subsidiaries of Energy Corporation of America.
24.1 Power of Attorney set forth on the signature page
contained in Part V.
* 99.1 Order of the United States District Court for the
Southern District of West Virginia entered January 25,
2002 in civil action number 3:01-1317.
* 99.2 Order of the United States District Court for the
Southern District of West Virginia entered June 3, 2002
in civil action number 3:01-1317.
99.3 Order of the United States District Court for the
Southern District of West Virginia entered July 2002 in
civil action number 3:01-1317.
* Previously filed
(b) Reports on Form 8-K
The Company filed a report on Form 8-K, Item 5, dated December 28, 2001,
reporting (1) a Notice of Default from certain holders of its $200 million
9-1/2% Senior Subordinate Notes due 2007 and (2) that the Company had filed
a declaratory judgment action in the United States District Court of the
Southern District of West Virginia, civil action number 3:01-1317, asking
the court to confirm the proper calculation of Net Proceeds of an Asset
Sale under the Indenture.
The Company filed a report on Form 8-K, Item 5, dated June 24, 2002,
reporting that on June 3, 2002 the United States District Court of the
Southern District of West Virginia entered an order granting the Company's
Second Motion for Partial Summary Judgment, which order dismissed the
Noteholder's claim on the basis of judicial admissions and equitable
estoppel.
The Company filed a report on Form 8-K, Item 5, dated July 12, 2002,
reporting that the Company entered into a $50 million revolving Credit
Agreement with Foothill Capital Corporation, as the Arranger and
Administrative Agent for the Lenders.
* * * * * *
60
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 30th day of
September 2002.
ENERGY CORPORATION OF AMERICA
By: /s/ John Mork
-------------------------------------
John Mork
President and Chief Executive Officer
61
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 30th day of September 2002, by the following persons in
the capacities indicated.
62
Signature Title
- -------------------------- ------------------------------------------------
/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
(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
63
CERTIFICATION
-------------
PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
---------------------------------------------------------
(SUBSECTIONS (A) AND (B) OF SECTION 1350, CHAPTER 63 OF TITLE 18, UNITED STATES
-------------------------------------------------------------------------------
CODE)
-----
Pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a)
---------------------------------------------------------------------------
and (b) of section 1350, chapter 63 of title 18, United States Code), the
- --------------------------------------------------------------------------------
undersigned officer of Energy Corporation of America, a West Virginia
- ------------------------------------------------------------------------------
corporation (the "Company"), hereby certifies that:
- --------------------------------------------------------
The Annual Report of the Company on Form 10-K for the year ended June 30,
2002 (the "Report"), fully complies with the requirements of section 13(a) or
15(d) of the Securities Exchange Act of 1934, and the information contained in
the Report fairly presents, in all material respects, the financial condition
and results of operations of the Company.
Dated: September 27, 2002 /s/ John Mork
----------------------------------
Name: John Mork
Title: Chief Executive Officer
The foregoing certification is being furnished solely pursuant to section
906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of section 1350,
chapter 63 of title 18, United States Code) and is not being filed as part of
the Report or as a separate disclosure document.
64
CERTIFICATION
-------------
PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
---------------------------------------------------------
(SUBSECTIONS (A) AND (B) OF SECTION 1350, CHAPTER 63 OF TITLE 18, UNITED STATES
-------------------------------------------------------------------------------
CODE)
-----
Pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a)
---------------------------------------------------------------------------
and (b) of section 1350, chapter 63 of title 18, United States Code), the
- --------------------------------------------------------------------------------
undersigned officer of Energy Corporation of America, a West Virginia
- ------------------------------------------------------------------------------
corporation (the "Company"), hereby certifies that:
- --------------------------------------------------------
The Annual Report of the Company on Form 10-K for the year ended June 30,
2002 (the "Report"), fully complies with the requirements of section 13(a) or
15(d) of the Securities Exchange Act of 1934, and the information contained in
the Report fairly presents, in all material respects, the financial condition
and results of operations of the Company.
Dated: September 27, 2002 /s/ Michael S. Fletcher
----------------------------------
Name: Michael S. Fletcher
Title: Chief Financial Officer
The foregoing certification is being furnished solely pursuant to section
906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of section 1350,
chapter 63 of title 18, United States Code) and is not being filed as part of
the Report or as a separate disclosure document.
65
CERTIFICATION
-------------
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
---------------------------------------------------------
(SECTION 7241, CHAPTER 98 OF TITLE 15, UNITED STATES CODE)
----------------------------------------------------------
Pursuant to section 302 of the Sarbanes-Oxley Act of 2002 (section 7241,
---------------------------------------------------------------------------
chapter 98 of title 15, United States Code), the undersigned officer of Energy
- --------------------------------------------------------------------------------
Corporation of America, a West Virginia corporation (the "Company"), hereby
- --------------------------------------------------------------------------------
certifies that:
- ----------------
I have reviewed the Annual Report of the Company on Form 10-K for the year
ended June 30, 2002 (the "Report"), and, to my knowledge, the Report does not
contain any untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances under which
such statements were made, not misleading, and the financial statements and
other financial information contained in the Report fairly presents, in all
material respects, the financial condition, results of operations, and cash
flows of the Company as of and for the periods presented in the Report.
Dated: September 27, 2002 /s/ John Mork
----------------------------------
Name: John Mork
Title: Chief Executive Officer
The foregoing certification is being furnished solely pursuant to section
302 of the Sarbanes-Oxley Act of 2002 (section 7241, chapter 98 of title 15,
United States Code) and is not being filed as part of the Report or as a
separate disclosure document.
66
CERTIFICATION
-------------
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
---------------------------------------------------------
(SECTION 7241, CHAPTER 98 OF TITLE 15, UNITED STATES CODE)
----------------------------------------------------------
Pursuant to section 302 of the Sarbanes-Oxley Act of 2002 (section 7241,
---------------------------------------------------------------------------
chapter 98 of title 15, United States Code), the undersigned officer of Energy
- --------------------------------------------------------------------------------
Corporation of America, a West Virginia corporation (the "Company"), hereby
- --------------------------------------------------------------------------------
certifies that:
- ----------------
I have reviewed the Annual Report of the Company on Form 10-K for the year
ended June 30, 2002 (the "Report"), and, to my knowledge, the Report does not
contain any untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances under which
such statements were made, not misleading, and the financial statements and
other financial information contained in the Report fairly presents, in all
material respects, the financial condition, results of operations, and cash
flows of the Company as of and for the periods presented in the Report.
Dated: September 27, 2002 /s/ Michael S. Fletcher
----------------------------------
Name: Michael S. Fletcher
Title: Chief Financial Officer
The foregoing certification is being furnished solely pursuant to section
302 of the Sarbanes-Oxley Act of 2002 (section 7241, chapter 98 of title 15,
United States Code) and is not being filed as part of the Report or as a
separate disclosure document.
67