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 ope