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, 2003.
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 13, 2003 was 38,250 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 13, 2003 was 616,893 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 . . . . . . . . . . . . . . . . . 27
Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . . 28
Statements of Operations . . . . . . . . . . . . . . . . . . . 30
Statements of Stockholders Equity. . . . . . . . . . . . . . . 31
Statements of Cash Flows . . . . . . . . . . . . . . . . . . . 32
Statements of Comprehensive Income . . . . . . . . . . . . . . 33
Notes to Consolidated Financial Statements . . . . . . . . . . 34
Supplemental Information on Oil and Gas Producing
Activities (Unaudited) . . . . . . . . . . . . . . . . . . . . 52
Item 9. Changes In and Disagreements With Accountants on
Accounting and Financial Disclosure. . . . . . . . . . . . . . . 55
Part III
Item 10. Directors and Officers of Registrant. . . . . . . . . . . . . . 55
Item 11. Executive Compensation. . . . . . . . . . . . . . . . . . . . . 59
Item 12. Security Ownership of Certain Beneficial Owners
and Management. . . . . . . . . . . . . . . . . . . . . . . . . 59
Item 13. Certain Relationships and Related Transactions. . . . . . . . . 61
Item 14. Controls and Procedures . . . . . . . . . . . . . . . . . . . . 63
Part IV
Item 15. Exhibits, Financial Statement Schedules and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . . . . . . . . 65
Part V
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69
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), billion cubic feet (Bcf), dekatherm (Dth), or thousand
dekatherms (Mdth). A dekatherm 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. 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 assumed to have the energy equivalent of six Mcf of natural gas. 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, gathering and
marketing of natural gas and oil, primarily in the Appalachian Basin and Gulf
Coast region. The Company conducts business primarily through its principal
wholly owned subsidiaries, Eastern American Energy Corporation ("Eastern"),
Westech Energy Corporation ("Westech") and Westech Energy New Zealand ("WENZ").
Eastern is one of the largest oil and gas operators in the Appalachian Basin,
including exploration, development and production, and is engaged in the
gathering 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. As used herein the "Company" refers to the Company alone or
together with one or more of its subsidiaries.
The Company was formed in June 1993 through an exchange of shares with the
common stockholders of Eastern.
As of June 30, 2003, the Company had approximately 226 full-time and 22
part-time employees. None of the employees were covered by a collective
bargaining agreement. Management believes that its relationship with its
employees is good.
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 17 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,
2003 at 190,796 Mmcf and 2,366 Mbbls, respectively. For the fiscal year ended
June 30, 2003, the Company's net gas production was 9,755 Mmcf and net oil
production was 104 Mbbls, for a total of 10,379 net Mmcfe.
DEVELOPMENT ACTIVITY
The Company, in fiscal year 2003, drilled 45 productive gross wells (39.1
net), and recompleted 9 wells, adding 2,224 gross Mcf of gas production per day.
The company also participated in 2 gross (0.4 net) wells drilled in California
which added 596 gross Mcfe per day of production.
4
EXPLORATORY ACTIVITY
Exploration wells and activity are summarized under their respective
project areas.
1. Newburg/Rose Run -- West Virginia, Ohio. The Company drilled four
successful exploration wells and two dry holes during the fiscal year. Current
production from the Newburg discovery is 850 Mcf per day and 21 Bbls per day,
net. The Company has an exploration plan for the area following the drilling
success and acquisition of 3-D seismic.
2. Texas. The Company, as operator, drilled eight wells with a success
rate of 67%. The principal producing formations are the Yegua and Meek at depths
ranging from 7,500 to 16,000 feet. The wells are producing approximately 16,000
Mcf per day, and 5,000 Mcf per day net. The Company is working on a development
drilling plan to exploit the exploration success.
3. New Zealand. The Company drilled a successful well in the Mt.
Messenger formation in the Taranaki region which is currently producing.
Therein, the Company is continuing its exploration efforts on the East Coast
offshore prospects.
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 may 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.
5
REGULATIONS AFFECTING OPERATIONS
The Company's operations are affected by extensive regulation pursuant to
various federal, state and local laws and regulations relating to the
exploration for and development, production, gathering, marketing,
transportation and storage of oil and gas. These regulations, among other
things, can affect the rate of oil and gas production. The Company's operations
are subject to numerous laws and regulations governing plugging and abandonment,
the discharge of materials into the environment or otherwise relating to
environmental protection. 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 its wholly owned subsidiary 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, 2003, Eastern Marketing aggregated and sold an average of 41.2 Mmcf of gas
per day, of which 39.1 Mmcf per day represented sales of gas produced from wells
operated by the Company. This represents a 7% decrease in the overall volumes
compared to fiscal year 2002, during which Eastern Marketing aggregated and sold
an average of 44.2 Mmcf of gas per day.
GAS SALES AND PURCHASE CONTRACTS
The Company has satisfied its obligations under all gas sales contracts
(15.1 Bcf in fiscal year 2003) through gas production attributable to its own
interests in oil and gas properties and through production attributable to third
party interests in the same oil and gas properties (14.3 Bcf in fiscal 2003),
and from natural gas aggregated by the Company pursuant to its aggregation and
marketing activities from third parties (0.8 Bcf in fiscal 2003).
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. Through May 31, 2003, 1,681,242 Mmbtu had been
delivered at a value of $6.9 million. This agreement was terminated as of May
31, 2003 pursuant to a settlement agreement effective as of May 14, 2003, and
the Company's obligations are deemed fully satisfied (See Item 8, Note 14 for
additional detail).
6
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 minimum price to be received by
the Company is $2.75 per Dth plus the Columbia Gas Transmission ("TCO")
Appalachia Basis and the maximum to be received is $4.85 per Dth plus the TCO
Appalachia Basis. The pricing terms also allow the Company to fix the price on
50% of the volumes. The Company has locked the price on 50% of the volumes from
July 1, 2003 through October 31, 2004 at a weighted average price of $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 Inside FERC Dominion
Transmission 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.
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
2003 2002 2001
-------- -------- --------
Net proved:
Gas (Mmcf) 190,796 183,345 206,456
Oil (Mbbls) 2,366 2,951 2,633
Total (Mmcfe) 204,992 201,051 222,254
Net proved developed:
Gas (Mmcf) 161,796 160,224 175,784
Oil (Mbbls) 1,064 1,135 987
Total (Mmcfe) 168,180 167,034 181,706
Estimated future net cash flows
before income taxes (in thousands) $916,885 $471,927 $557,352
Present value of estimated future net cash
flows before income taxes (in thousands) (1) $382,094 $200,087 $232,866
______________
(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, 2003:
Present Value
-------------------- Natural Gas
Amount Oil Natural Gas Equivalent
Region (thousands) % (Mbbls) (Mmcf) (Mmcfe)
------------------ ------------ ------ ------------ ----------- --------
Appalachian Basin $ 306,838 80.3% 631 166,539 170,325
Western Basins 17,717 4.6% 1,191 4,285 11,431
Gulf Coast 53,858 14.1% 225 18,933 20,283
New Zealand 3,681 1.0% 319 1,039 2,953
------------ ------ ------------ ----------- --------
Total $ 382,094 100.0% 2,366 190,796 204,992
============ ====== ============ =========== ========
PRODUCING WELLS
- ----------------
The following table sets forth certain information relating to productive
wells at June 30, 2003. 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 12.0 5,372.0 5,384.0 7.0 3,223.0 3,230.0
Western Basins 11.0 2.0 13.0 3.4 0.2 3.6
Gulf Coast - 13.0 13.0 - 3.9 3.9
New Zealand - 4.0 4.0 - 4.0 4.0
---- ------- ------- ---- ------- -------
Total 23.0 5,391.0 5,414.0 10.4 3,231.1 3,241.5
==== ======= ======= ==== ======= =======
8
ACREAGE
- -------
The following table sets forth the developed and undeveloped gross and net
acreage held at June 30, 2003:
Developed Acreage Undeveloped Acreage
-------------------- ------------------------
Gross Net Gross Net
--------- --------- ----------- -----------
Appalachian Basin 402,870.0 310,441.0 144,041.0 117,982.0
Western Basins 1,920.0 1,457.9 86,864.4 45,228.3
Gulf Coast 1,913.5 670.8 33,758.8 20,024.4
New Zealand 740.0 736.3 3,181,413.1 2,776,411.9
--------- --------- ----------- -----------
Total 407,443.5 313,306.0 3,446,077.3 2,959,646.6
========= ========= =========== ===========
PRODUCTION
- ----------
The following table sets forth certain net production data and average
wellhead sales prices attributable to the Company's properties for the years
ended June 30:
2003 2002 2001
------- ------- -------
Production Data:
Oil (Mbbls) 104 124 116
Natural gas (Mmcf) 9,755 9,941 9,371
Natural gas equivalent (Mmcfe) 10,379 10,685 10,067
Average Sales Price (before the effect of hedging):
Oil per Bbl $ 25.97 $ 21.11 $ 25.94
Natural gas per Mcf $ 5.13 $ 2.86 $ 5.43
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
2003 2002 2001
----------- ----------- -----------
Gross Net Gross Net Gross Net
----- ---- ----- ---- ----- ----
Development:
Productive
Appalachian 45.0 39.1 53.0 47.8 47.0 41.5
Other 2.0 0.4 1.0 0.3 - -
----- ---- ----- ---- ----- ----
Total 47.0 39.5 54.0 48.1 47.0 41.5
===== ==== ===== ==== ===== ====
Nonproductive
Appalachian 3.0 2.7 1.0 0.9 1.0 0.5
Other - - - - - -
----- ---- ----- ---- ----- ----
Total 3.0 2.7 1.0 0.9 1.0 0.5
===== ==== ===== ==== ===== ====
Exploratory:
Productive
Appalachian 4.0 1.4 4.0 1.6
Other 9.0 4.0 4.0 2.3 3.0 2.6
----- ---- ----- ---- ----- ----
Total 13.0 5.4 8.0 3.9 3.0 2.6
===== ==== ===== ==== ===== ====
Nonproductive
Appalachian 2.0 1.0 5.0 2.1 2.0 0.3
Other 4.0 2.2 4.0 3.2 8.0 3.8
----- ---- ----- ---- ----- ----
Total 6.0 3.2 9.0 5.3 10.0 4.1
===== ==== ===== ==== ===== ====
ITEM 3. LEGAL PROCEEDINGS
----------------------------
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 alleged that
the Company's sale of Mountaineer in August of 2000 constituted a sale of
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
10
Order dated July 19, 2002, denying the Noteholders' Motion for Reconsideration.
On July 27, 2002, the Noteholders filed a Notice of Appeal in the United States
Court of Appeals for the Fourth Circuit. The Noteholders subsequently filed a
motion to voluntarily dismiss the appeal without prejudice. This motion was
granted and the matter was remanded to the District Court. The District Court
entered a Stipulation and Final Judgment on December 3, 2002 and a Judgment
Order dated December 4, 2002. This discussion is qualified in its entirety by
the foregoing Stipulation and Final Judgment dated December 3, 2002 and the
Judgment Order dated December 4, 2002, which have been previously filed and are
incorporated herein by reference.
On December 9, 2002, certain Noteholders filed a Notice of Appeal to the
United States Court of Appeals for the Fourth Circuit from the Stipulation and
Final Judgment Order dated December 3, 2002, and the Judgment order entered on
December 4, 2002. Briefing is complete and oral argument has been scheduled for
September 25, 2003.
The Company and Prudential Securities Incorporated ("Prudential") have been
in a long-standing dispute related to certain fees. In March 2003, the dispute
resulted in Prudential filing suit against the Company in the District Court,
City and County of Denver, Colorado. Management does not believe the merits of
Prudential's allegations, and is of the opinion that the matter is not material
regardless of the outcome.
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
-------
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
13, 2003, the Company had 33 holders of record of its common stock.
The Company declared dividends in fiscal years 2003, 2002 and 2001 of $1.1
million, $1.1 million and $3.9 million, respectively.
11
ITEM 6. SELECTED FINANCIAL DATA
----------------------------------
(Dollars in thousands, except per share items)
Year Ended June 30,
----------------------------------------------------
2003 2002 2001 2000 1999
-------- --------- --------- --------- ---------
Operating revenue $117,426 $ 86,142 $129,951 $101,919 $113,500
Income (loss) from continuing operations 9,917 (26,180) (10,199) (26,508) (27,099)
Earnings per common share, basic 15.12 (39.80) (15.34) (40.11) (40.27)
diluted 14.79 (39.80) (15.34) (40.11) (40.27)
Total assets 295,834 304,736 380,532 265,691 286,077
Long term debt 173,197 198,701 198,902 212,575 219,886
Dividends declared per common share $ 1.72 $ 1.60 $ 5.80 $ - $ 0.95
(a) The effect of outstanding stock options was not included in the
computation of diluted earnings per share for years ended 2002, 2001, 2000,
or 1999 because to do so would have been antidilutive.
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.
DERIVATIVE INSTRUMENTS - As of July 1, 2000, the estimated fair values of
all 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 in operations in the period they occur. In determining the amounts to
be recorded, the Company is 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 of 10%, as required by accounting standards. 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.
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, 2003 AND 2002
- ------------------------------------------------------------------------------
The Company recorded net income of $9.9 million for the year ended June
30, 2003 compared to a net loss of $26.2 million in 2002. The improvement of
$36.1 million was primarily attributable to the net effect of a $31.3 million
increase in revenue, a $0.2 million decrease in costs and expenses, a $3.3
million decrease in interest expense, a $0.7 decrease in gain on sale of assets,
$24.7 million increase in other non-operating income and a $22.9 million
increase in income tax expense.
OPERATING MARGINS. Operating Margins (defined as revenue less operating
------------------
costs and taxes other than income taxes) for the Company's operating
subsidiaries totaled $50.3 million for the current year compared to $35.6
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 and taxes other than income) totaled $43.5 million
versus $31.3 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 $6.8 million for the current period versus
$3.7 million for the prior period. Other revenue was $0.04 million for the
current period versus $0.50 million for the prior period.
14
Production, marketing and pipeline volumes, revenue and average sales
prices for the years ended June 30 and their related variances are as follows:
TWELVE MONTHS ENDED
JUNE 30 VARIANCE
--------------- ------------------
2003 2002 AMOUNT PERCENT
------- ------ -------- --------
Natural Gas
Production (Mmcf) 9,755 9,941 (186) -1.9%
Average sales price received ($/Mcf) 5.13 2.86 2.27 79.4%
------- ------ -------- --------
Sales ($ in thousands) 50,031 28,462 21,569 75.8%
Oil
Production (Mbbl) 104 124 (20) -16.1%
Average sales price received ($/Bbl) 25.97 21.11 4.86 23.0%
------- ------ -------- --------
Sales ($ in thousands) 2,701 2,618 83 3.2%
Hedging (4,843) 7,212 (12,055) -167.2%
Other 3,521 647 2,874 444.2%
------- ------ -------- --------
Total oil and gas sales ($ in thousands) 51,410 38,939 12,471 32.0%
======= ====== ======== ========
Marketing Revenue
Volume (Mdth) 9,285 9,903 (618) -6.2%
Average sales price received ($ per Dth) 4.86 3.14 1.72 54.7%
------- ------ -------- --------
Sales ($ in thousands) 45,145 31,125 14,020 45.0%
Pipeline Revenue
Volume (Mdth) 5,675 6,003 (328) -5.5%
Average sales price received ($ per Dth) 2.70 1.68 1.02 60.7%
------- ------ -------- --------
Sales ($ in thousands) 15,338 10,084 5,254 52.1%
------- ------ -------- --------
Total marketing and pipeline sales ($ in thousands) 60,483 41,209 19,274 46.8%
======= ====== ======== ========
Marketing Gas Cost
Volume (Mdth) 9,285 9,902 (617) -6.2%
Average price paid ($ per Dth) 4.48 2.98 1.50 50.3%
------- ------ -------- --------
Cost ($ in thousands) 41,636 29,526 12,110 41.0%
Pipeline Gas Cost
Volume (Mdth) 4,550 4,870 (320) -6.6%
Average price paid ($ per Dth) 2.65 1.64 1.01 61.6%
------- ------ -------- --------
Cost ($ in thousands) 12,057 7,963 4,094 51.4%
------- ------ -------- --------
Total marketing and pipeline cost ($ in thousands) 53,693 37,489 16,204 43.2%
======= ====== ======== ========
---------------------------------------------------------------------------------------
REVENUES. Total revenues increased $31.3 million or 36.3% between the
--------
years. The net increase was due to a 32.0% increase in oil and gas sales, a
46.8% increase in gas marketing and pipeline sales, a 0.1% increase in well
operations and service revenues and a 93.1% decrease in other operating revenue.
15
Revenues from oil and gas sales increased a net of $12.5 million from $38.9
million for the year ended June 30, 2002 to $51.4 million for the year ended
June 30, 2003. Natural gas sales increased $21.6 million and oil sales increased
$0.08 million. The net increase is attributed to the following variances; gas
price increase $22.1 million, gas production decrease $.5 million, oil price
increase $0.5 million and oil production decrease $0.4 million. The price
increase corresponds with related indexes. The decrease in production was due in
part to the sale of certain oil and gas properties, extended curtailments on
third party transmission facilities, as well as normal production declines. The
decrease in production was partially offset by the purchase of certain oil and
gas properties and the drilling of new wells. The increased production revenue
was offset by recognized losses on related hedging transactions including
derivative instruments and fixed price delivery contracts, which totaled a loss
of $4.8 million for the year ended June 30, 2003 compared to a gain of $7.2
million for the year ended June 30, 2002. The average price per Mcfe, after
hedging, was $4.99 and $3.65 for the years ended June 30, 2003 and 2002,
respectively.
Revenues from gas marketing and pipeline sales increased $19.3 million from
$41.2 million during the period ended June 30, 2002 to $60.5 million in the
period ended June 30, 2003. Gas marketing revenue increased $14.0 million while
pipeline revenue, which has sale and transportation components, increased $5.3
million. The increase in gas marketing and pipeline sales is attributable to the
increase in average sales price received. The price increase corresponds with
related indexes.
Other operating revenue decreased $.5 million. The current year income of
$0.03 million is related to revenue earned by the Company's participation in
Deep Rig, L.P., while $0.5 million was recognized in the prior year.
COSTS AND EXPENSES. The Company's costs and expenses decreased $0.2 million
-------------------
or 0.2% between the periods primarily as a net result of a 7.2% decrease in
field and lease operating expenses, a 43.2% increase in gas marketing and
pipeline costs, a 11.1% decrease in general and administrative expenses, a 51.1%
increase in taxes other than income, a 1.8% decrease in oil and gas related
depreciation, a 46.4% increase in depletion and amortization expenses of
pipelines, property and equipment and a 57.6% decrease in exploration and
impairment costs.
Field and lease operating expenses decreased $0.8 million. The decrease in
lease operating expenses is primarily related to a reduction in contract labor
expenses, road and dike repair costs, and various other field and lease
operating expenses.
Gas marketing and pipeline costs increased $16.2 million. Gas marketing
cost increased $12.1 million while pipeline costs increased $4.1 million. The
increase in gas marketing and pipeline cost of sales is attributable to the
increase in average price paid. The price increase corresponds with related
indexes.
General and administrative expenses decreased $1.9 million primarily due to
an increase in exploration and development drilling capitalized costs, lower bad
debt expense, legal fees, and board fees.
Taxes other than income increased $1.1 million as a result of increased oil
and gas sales. Average wellhead oil and gas sales prices, on which production
taxes are based, were higher for the current year.
Oil and gas related depreciation, depletion and amortization expenses
decreased $0.2 million. The decrease in depletion is primarily due to reduced
production volumes resulting from the sale of
16
certain oil and gas properties and normal production declines, partially offset
by production related to the acquisition of certain oil and gas properties and
from new wells drilled during the year.
Exploration and impairment expenses decreased $16.0 million. In the current
year, the expenses were primarily due to dry hole costs, impairment of oil and
gas property and various other geological and geophysical costs. The breakdown
of costs by area in the current year are $6.8 million in the Gulf Coast, $1.0
million in New Zealand, $2.8 million in the Appalachian Basin and $1.1 million
in the West.
INTEREST EXPENSE. Interest expense decreased $3.3 million primarily due to
-----------------
the repurchase of $65.6 million face value of the Company's senior notes for the
year ended June 30, 2003.
INTEREST INCOME AND OTHER. Other non-operating income increased $24.7
----------------------------
million when comparing the periods. This is primarily the result of the Company
purchasing a portion of its senior bonds and recognizing a gain of $23.7
million. The Company also recognized $4.5 million in income from legal
settlements and $1.4 million in net contract settlements associated with
Allegheny Energy. Offsetting this increase in other non-operating income was a
reduction in interest income of $1.1 million due to decreases in the cash
balances and interest rates when comparing the periods. The Company also
recognized a loss of $2.1 million due to the write down of its investment in
Alliance Gas.
INCOME TAX. Income tax expense increased by $22.9 million in 2003 to an
-----------
income tax expense of $6.1 million as compared to an income tax benefit in 2002
of $16.8 million. This increase was due to a $58.8 million increase in income
from continuing operations.
COMPARISON OF RESULTS OF OPERATIONS FOR THE YEARS ENDED JUNE 30, 2002 AND 2001
- --------------------------------------------------------------------------------
The Company recorded a net loss 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
year ended June 30, 2002 as compared to $33.0 million for the year ended June
30, 2001. 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 for the year ended June 30, 2002 versus $27.6 million for the year ended
June 30, 2001. 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 $3.9 million for the
prior period.
17
Production, marketing and pipeline volumes, revenue and average sales
prices for the years ended June 30 and their related variances are as follows:
Variance
-------------------
2002 2001 Amount Percent
------- --------- --------- --------
Natural Gas
Production (Mmcf) 9,941 8,822(1) 1,119 12.68%
Average sales price received ($ 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%
------- --------- --------- --------
Sales ($ 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 acquisition of certain properties
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.
18
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 participation in Deep
Rig, L.P., 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.
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.
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.
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.
19
INTEREST INCOME AND OTHER. Other non-operating income decreased $4.6
----------------------------
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 income 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.
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):
2003 2002 2001
------- ------- --------
Development $14,105 $10,977 $ 13,649
Exploration 15,292 20,737 15,115
Acquisitions 5,879 717 80,394
------- ------- --------
Total $35,276 $32,431 $109,158
======= ======= ========
ACQUISITIONS
- ------------
On February 5, 2003, the Company purchased certain oil and gas properties
located in southern West Virginia for $5.6 million, after certain adjustments.
The purchase included proved developed producing gas reserves, estimated at 4
Bcf, 90 producing wells and over 30,000 acres.
LIQUIDITY AND CAPITAL RESOURCES
- ----------------------------------
The Company's financial condition has improved since June 30, 2002, but at
the same time, there has been a decrease in the Company's liquidity.
Stockholders' equity has increased from $37.1 million at June 30, 2002 to $43.7
million at June 30, 2003. However, the Company's working capital of $1.8
million at June 30, 2002 decreased to a negative $12.9 million at June 30, 2003.
The Company's cash decreased from $17.8 million at June 30, 2002 to $4.8 million
at June 30, 2003. The Company's cash at August 28, 2003 was $1.4 million. The
change in cash during the year of approximately $12.9 million resulted from
various operating, investing and financing activities of the Company. The
activities were primarily comprised of: the borrowing of approximately $39.2
million under the Company's $50 million revolving Credit Agreement (the
"Agreement"); the borrowing of $1 million under an unsecured credit facility;
the net investment of approximately $34.1 million in property, plant and
equipment; payments of approximately $40.9 million for the purchase of a portion
of the Company's outstanding Notes; payments of approximately $2.5 million for
the acquisition of treasury stock and dividends; and approximately $23.2 million
of cash provided by operations during the year.
On December 13, 2002, Standard & Poor's Rating Services ("S&P"), with a
negative outlook, lowered its corporate credit rating on the Company to CCC+
from B, and its rating on the Notes to CCC- from CCC+. S&P stated that "the
ratings downgrade reflects ECA's burdensome debt leverage with limited,
near-term prospects for significant deleveraging and a likely decline in
liquidity through 2003 as S&P expects ECA to outspend its internally generated
cash flow. Given the probable cash flow generation
20
of ECA's properties, it may be very challenging for the Company to continue
servicing its debt while averting depletion."
At June 30, 2003, the Company's principal source of liquidity consisted of
$4.8 million of cash, $1 million available under an unsecured credit facility
currently in place, plus amounts available under the Foothill Capital
Corporation (Foothill) Agreement. At June 30, 2003, $1 million was outstanding
or committed under the short-term credit facility and $39.2 million was
outstanding under the Agreement.
On July 10, 2002, the Company entered into the Agreement with 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 certain 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 August
28, 2003, there are $38.9 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 estimated to be greater than 2.5 to 1.
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, cash generated by the sale of assets and interest expense. EBITDAX,
before inclusion of the gain on the purchase of the Company's Notes, for fiscal
year 2003 was $37.2 million. EBITDAX for fiscal years 2002 and 2001 was $19.7
million and $33.7 million, respectively. See Note 17. Management anticipates
that EBITDAX from oil and gas operations for fiscal year 2004 will approximate
$50 million. The Company's ability to achieve EBITDAX of $50 million from oil
and gas operations for fiscal year 2004 is highly dependant on product price and
continued drilling success. For fiscal 2004, the Company is using an average
price assumption of over $5 per Mcfe and production of approximately 14.0 Bcfe,
which is an increase of approximately 35% in the production amount of
approximately 10.4 Bcfe in fiscal year 2003. There can be no assurance given
that the Company will be able to achieve these goals. Although cash provided
from oil and gas operations may not be sufficient to fully fund the Company's
fiscal year 2004 projected interest charges of over $15 million, capital
expenditures program of $32 million, and other uses, management believes that
cash generated from continuing oil and gas operations, together with the
liquidity provided by existing cash balances, permitted borrowings and the cash
proceeds resulting from the sale of certain assets, will be sufficient to
satisfy commitments for capital expenditures, debt service obligations, working
capital needs and other cash requirements for the next fiscal 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 Notes 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.
The Company believes that its existing capital resources and its expected
fiscal year 2004 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
21
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, 2003 (in thousands):
2004 2005 2006 Thereafter Total
------ ------ ------- ----------- --------
Senior subordinated notes $ - $ - $ - $ 132,073 $132,073
Installment notes payable 213 1,213 39,440 793 41,659
Operating leases 909 1,019 402 1,364 3,694
------ ------ ------- ----------- --------
Total contractual cash obligations $1,122 $2,232 $39,842 $ 134,230 $177,426
====== ====== ======= =========== ========
RECENT ACCOUNTING PRONOUNCEMENTS
- ----------------------------------
The FASB and representatives of the accounting staff of the Securities and
Exchange Commission ("SEC") are currently engaged in discussions regarding the
application of certain provisions of SFAS No. 141, "Business Combinations," and
SFAS No. 142, "Goodwill and Other Intangible Assets," to companies in the
extractive industries, including oil and gas companies. The FASB and the SEC
staff are considering whether the provisions of SFAS No. 141 and SFAS No.142
require registrants to classify costs associated with mineral rights, including
both proved and unproved lease acquisition costs, as intangible assets in the
balance sheet, apart from other capitalized oil and gas property costs, and
provide specific footnote disclosures. Historically, the Company has included
oil and gas lease acquisition costs as a component of oil and gas properties. In
the event the FASB and SEC staff determine that costs associated with mineral
rights are required to be classified as intangible assets, a portion of our oil
and gas property costs incurred since the June 30, 2001 effective date of SFAS
Nos. 141 and 142 would be separately classified on our balance sheets as
intangible assets. However, our results of operations and cash flows would not
be affected since such intangible assets would continue to be depleted and
assessed for impairment in accordance with successful efforts accounting rules
and impairment standards.
Effective July 1, 2002, the Company adopted SFAS No. 143, "Accounting for
Asset Retirement Obligations." SFAS No. 143 provides the accounting
requirements for retirement obligations associated with tangible long-lived
assets. When the liability is initially recorded, the entity capitalizes the
cost, thereby increasing the carrying amount of the related long-lived asset.
Over time, the liability is accreted, and the capitalized cost is depreciated
over the useful life of the related asset.
For the Company, asset retirement obligations primarily relate to the
abandonment of oil and gas producing facilities. While assets such as pipelines
and gas marketing assets may have retirement obligations covered by SFAS No.
143, certain of those obligations are not recognized since the fair value cannot
be estimated due to the uncertainty of the settlement date of the obligation.
The initial application of this accounting standard by ECA as of July 1,
2002, resulted in an increase in net plant assets of $0.4 million, an asset
retirement obligation liability of $0.5 million, and a cumulative effect of a
change in accounting principle of $0.1 million. Due to a change in estimate by
22
ECA in fiscal year 2003 regarding SFAS No. 143, the initial application was
changed to an asset retirement obligation liability of $0.7 million, a net plant
asset increase of $0.6 million, and a cumulative effect of a change in
accounting principle of $0.1 million as of June 30, 2003.
(IN THOUSANDS)
--------------
ASSET RETIREMENT OBLIGATIONS AS OF JULY 1, 2002: $ 471
Liabilities incurred:
Additional wells drilled 181
Liabilities settled:
Reduction for wells sold (86)
Accretion expense (included in depletion, deprec.,
amortiz.-other) 33
Change in estimate 125
-------
Asset retirement obligations as of June 30, 2003 $ 724
=======
In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities" This Statement addresses financial
accounting and reporting for costs associated with exit or disposal activities
and nullifies EITF Issue No. 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (including Certain
Costs Incurred in a Restructuring)". This Statement requires recognition of a
liability for a cost associated with an exit or disposal activity when the
liability is incurred, as opposed to when the entity commits to an exit plan
under EITF No. 94-3. SFAS No. 146 is to be applied prospectively to 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.
In December 2002, the FASB approved Statement of Financial Accounting
Standards No. 148, "Accounting for Stock-Based Compensation - Transition and
Disclosure - an amendment of FASB Statement No. 123" (SFAS No. 148). SFAS No.
148 amends Statement of Financial Accounting Standards No. 123, "Accounting for
Stock-Based Compensation" (SFAS No. 123) to provide alternative methods of
transition for a voluntary change to the fair value based method of accounting
for stock-based employee compensation. In addition, SFAS No. 148 amends the
disclosure requirements of SFAS No. 123 to require prominent disclosures in both
annual and interim financial statements about the method of accounting for
stock-based employee compensation and the effect of the method used on reported
results. SFAS No. 148 is effective for financial statements for fiscal years
ending after December 15, 2002. 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".
In April 2003, FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities" to amend and clarify financial
accounting and reporting for derivative instruments, including certain
derivative instruments embedded in other contracts for hedging activities. This
Statement is effective for contracts entered into or modified after June 30,
2003, and for hedging relationships designated after June 30, 2003. Management
believes SFAS No. 149 has no material impact on the Company's financial
condition or results of operation as of June 30, 2003. The Company will adopt
this Statement as of July 1, 2003.
23
In May 2003 the FASB issued Statement of Financial Accounting Standards No.
150, "Accounting for Certain Financial Instruments with Characteristics of both
Liabilities and Equity". SFAS No. 150 establishes standards for how an issuer
classifies and measures certain financial instruments with characteristics of
both liabilities and equity, and will require instruments that fall within the
scope of this pronouncement to be classified as liabilities. This statement is
effective for financial instruments entered into or modified after May 31, 2003,
and otherwise is effective at the beginning of the first interim period
beginning after June 15, 2003. The Company does not believe the adoption of
this statement will have a material effect on the Company's financial position
or results of operations.
In November 2002, the FASB issued Financial Interpretation No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, including
Indirect Guarantee of Indebtedness of Others" (FIN 45). FIN 45 requires that
upon issuance of a guarantee, the guarantor must recognize a liability for the
fair value of the obligation it assumes under that guarantee. FIN 45's
provisions for initial recognition and measurement should be applied on a
prospective basis to guarantees issued or modified after December 31, 2002. The
guarantor's previous accounting for guarantees that were issued before the date
of FIN 45's initial application may not be revised or restated to reflect the
effect of the recognition and measurement provisions of the Interpretation. The
disclosure requirements are effective for financial statements of both interim
and annual periods that end after December 15, 2002. The Company's adoption of
FIN 45 on January l, 2003 did not effect its financial position or results of
operations.
In January 2003, the FASB issued FASB Interpretation No. 46, "Consolidation
of Variable Interest Entities" (FIN 46). FIN 46 clarifies the application of
Accounting Research Bulletin No. 51, "Consolidated Financial Statements" to
certain entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated support from
other parties. FIN 46 requires existing unconsolidated variable interest
entities to be consolidated by their primary beneficiaries if the entities do
not effectively disperse risks among parties involved. All companies with
variable interests in variable interest entities created after January 31, 2003,
shall apply the provisions of FIN 46 to those entities immediately. FIN 46 is
effective for the first fiscal year or interim period beginning after June 15,
2003, for variable interest entities created before February 1, 2003. The
Company will prospectively apply the provisions of FIN 46 that were effective
January 31, 2003.
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 various transactions, covering
24
approximately 55% to 65% of its estimated natural gas production through June
2004 and 25% to 35% of its estimated natural gas production for the fiscal year
ended June 2005.
As of June 30, 2003, the Company's open gas derivative instruments and fixed
price delivery contracts were as follows:
Total Average
Market Volumes Contract Unrealized
Time period Index (MMBtu) Price (Gains) Losses
--------------------------------- ---------- ----------- --------- ----------------
Derivatives:
Natural Gas Swaps
July 2003 - March 2004 NYMEX 720,000 $ 6.32 $ (456,385)
July 2003 - June 2004 NYMEX 1,098,000 4.05 1,479,305
July 2004 - June 2005 NYMEX 3,240,000 4.54 1,319,482
----------- ----------------
Unrealized (Gains) Losses 5,058,000 $ 2,342,402
----------- ================
Physical Contracts:
Fixed Price Delivery Contracts
July 2003 - June 2004 5,735,500 $ 4.50
July 2003 - June 2004 338,250 4.85
-----------
Total 11,131,750
===========
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 or subject to fixed price contracts remain at June 2003 levels, a 10%
change in the average unhedged prices realized during the year would change the
Company's gas and oil revenues by approximately $1.5 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, 2003, all but $40.2 million 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. Assuming the variable interest debt remained
at the June, 2003 level, a 10% change in rates would have a $0.3 million impact
on interest expense on an annual basis. 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
25
the period. Gains and losses resulting from foreign currency translation are
included as a component of other comprehensive income.
* * * * *
26
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, 2003 and 2002, and the
related consolidated statements of operations, stockholders' equity, cash flows,
and comprehensive income for each of the three years in the period ended June
30, 2003. 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, 2003 and 2002, and the results of their operations
and their cash flows for each of the three years in the period ended June 30,
2003 in conformity with accounting principles generally accepted in the United
States of America.
As discussed in Note 2 to the consolidated financial statements, in 2001 the
Company adopted Statement of Financial Accounting Standards No. 133, "Accounting
for Derivative Instruments and Hedging Activities" and in 2003 adopted Statement
of Financial Accounting Standards No. 143, "Accounting for Asset Retirement
Obligations".
DELOITTE & TOUCHE LLP
Denver, Colorado
August 29, 2003
27
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF JUNE 30
(AMOUNTS IN THOUSANDS)
- --------------------------------------------------------------------
ASSETS 2003 2002
--------- ---------
CURRENT ASSETS:
Cash and cash equivalents $ 4,831 $ 17,775
Accounts receivable:
Oil and gas sales 10,380 7,284
Gas marketing and pipeline 9,458 5,323
Other 4,616 6,924
--------- ---------
Accounts receivable 24,454 19,531
Less allowance for doubtful accounts (1,616) (1,366)
--------- ---------
Accounts receivable net of allowance 22,838 18,165
Income taxes receivable - 1,596
Deferred income tax asset 41 2,237
Deferred taxes - comprehensive income 787 -
Derivatives - 454
Prepaid and other current assets 3,019 4,234
--------- ---------
Total current assets 31,516 44,461
NET PROPERTY, PLANT AND EQUIPMENT (Note 2) 253,270 244,155
--------- ---------
OTHER ASSETS:
Deferred financing costs, less accumulated
amortization of $4,728 and $3,722 3,098 3,617
Other 7,950 12,503
--------- ---------
Total other assets 11,048 16,120
--------- ---------
TOTAL $295,834 $304,736
========= =========
See notes to consolidated financial statements. (Continued)
28
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF JUNE 30
(AMOUNTS IN THOUSANDS)
- --------------------------------------------------------------------------------
LIABILITIES AND STOCKHOLDERS' EQUITY 2003 2002
--------- ---------
CURRENT LIABILITIES:
Accounts payable and accrued expenses $ 13,734 $ 15,683
Current portion of long-term debt 133 121
Funds held for future distribution 17,217 11,414
Income taxes payable 1,484 -
Accrued taxes, other than income 9,643 8,221
Deferred taxes - comprehensive income - 180
Derivatives 810 -
Other current liabilities 1,421 7,078
--------- ---------
Total current liabilities 44,442 42,697
LONG-TERM OBLIGATIONS:
Long-term debt 173,197 198,701
Gas delivery obligation and deferred trust revenue 2,917 5,886
Deferred income tax liability 20,376 9,887
Derivatives 1,319 -
Other long-term obligations 8,311 8,689
--------- ---------
Total liabilities 250,562 265,860
--------- ---------
COMMITMENTS AND CONTINGENCIES (Note 15)
Minority interest 1,594 1,732
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 shares issued 5,092 5,092
Additional paid-in capital 5,503 5,503
Retained earnings 45,150 36,422
Treasury stock and notes receivable arising from
issuance of common stock (11,824) (10,426)
Accumulated other comprehensive loss (973) (177)
--------- ---------
Total stockholders' equity 43,678 37,144
--------- ---------
TOTAL $295,834 $304,736
========= =========
See notes to consolidated financial statements.
29
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED JUNE 30
(AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
- --------------------------------------------------------------------------------------------------------------------
2003 2002 2001
--------- --------- ---------
REVENUES:
Oil and gas sales $ 51,410 $ 38,939 $ 41,555
Gas marketing and pipeline sales 60,483 41,209 81,042
Well operations and service revenues 5,498 5,490 5,899
Other 35 504 1,455
--------- --------- ---------
117,426 86,142 129,951
--------- --------- ---------
COSTS AND EXPENSES:
Field operating expenses 10,128 10,916 8,910
Gas marketing and pipeline cost of sales 53,693 37,489 77,167
General and administrative 15,437 17,360 12,804
Taxes, other than income 3,287 2,175 3,389
Depletion and depreciation of oil and gas properties 12,140 12,362 9,290
Depreciation of pipelines, other property and equipment 4,294 2,934 2,763
Exploration and impairment 11,729 27,694 19,014
--------- --------- ---------
110,708 110,930 133,337
--------- --------- ---------
Income (loss) from operations 6,718 (24,788) (3,386)
--------- --------- ---------
OTHER (INCOME) AND EXPENSE:
Interest expense 16,383 19,671 20,094
(Gain) loss on sale of assets 433 (319) (211)
Interest income and other (25,848) (1,135) (5,838)
--------- --------- ---------
(9,032) 18,217 14,045
--------- --------- ---------
Income (loss) from continuing operations before income taxes and minority interest 15,750 (43,005) (17,431)
Income tax expense (benefit) 6,073 (16,822) (7,232)
--------- --------- ---------
Income (loss) from continuing operations before minority interest 9,677 (26,183) (10,199)
Minority interest 240 3 -
--------- --------- ---------
Income (loss) from continuing operations 9,917 (26,180) (10,199)
Disposal of utility operations:
Loss from utility operations, net of tax - - (1,847)
Gain on sale of utility, net of tax - - 84,402
--------- --------- ---------
Net income from disposal of utility operations - - 82,555
--------- --------- ---------
Income (loss) before cumulative effect of changes in accounting principle: 9,917 (26,180) 72,356
Change in accounting principle, net of tax (73) - -
--------- --------- ---------
NET INCOME (LOSS) $ 9,844 $(26,180) $ 72,356
========= ========= =========
Earnings (loss) per common share, basic:
Income (loss) from continuing operations $ 15.23 $ (39.80) $ (15.34)
Discontinued operations - - 124.20
Change in accounting principle, net of tax (0.11) - -
--------- --------- ---------
Basic earnings (loss) per common share $ 15.12 $ (39.80) $ 108.86
========= ========= =========
Earnings (loss) per common share, diluted:
Income (loss) from continuing operations $ 14.90 $ (39.80) $ (15.34)
Discontinued operations - - 124.20
Change in accounting principle, net of tax (0.11) - -
--------- --------- ---------
Diluted earnings (loss) per common share $ 14.79 $ (39.80) $ 108.86
========= ========= =========
See notes to consolidated financial statements.
30
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERSEQUITY
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, 2000 $ 718 $ 2,940 $ 4,615 $ (4,833) $ (6,284) $ (1,145)
Comprehensive income 72,356
Dividends (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 $ 63,653 $ (8,204) $ (1,089)
======= ======== =========== ========== ========== =================
Comprehensive Loss (26,180)
Dividends (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)
======= ======== =========== ========== ========== =================
Comprehensive income (loss) 9,844
Dividends (1,116)
Purchase of treasury stock - common (854)
Purchase of treasury stock - Class A (639)
Reduction of notes receivable 95
------- -------- ----------- ---------- ---------- -----------------
Balance, June 30, 2003 $ 730 $ 5,092 $ 5,503 $ 45,150 $ (11,530) $ (294)
======= ======== =========== ========== ========== =================
Accum. Other
Comprehensive Stockholders
Income (Loss) Equity
--------------- --------------
Balance June, 30, 2000 $ (134) $ (4,123)
Comprehensive income 635 72,991
Dividends (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 $ 501 $ 64,826
=============== ==============
Comprehensive Loss (678) (26,858)
Dividends (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
=============== ==============
Comprehensive income (loss) (796) 9,048
Dividends (1,116)
Purchase of treasury stock - common (854)
Purchase of treasury stock - Class A (639)
Reduction of notes receivable 95
--------------- --------------
Balance, June 30, 2003 $ (973) $ 43,678
=============== ==============
See notes to consolidated financial statements.
31
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED JUNE 30
(AMOUNTS IN THOUSANDS)
- --------------------------------------------------------------------------------------------------------------------
2003 2002 2001
--------- --------- ----------
CASH FLOWS FROM OPERATING ACTIVITIES
Income (loss) from continuing operations $ 9,917 $(26,180) $ (10,199)
Adjustments to reconcile net income (loss) to net cash provided (used) by
operating activities:
Depletion, depreciation and amortization 16,434 16,031 12,911
(Gain) loss on sale of assets 433 (319) (211)
Gain on redemption of senior bonds (23,672) - -
Deferred income taxes 12,685 (12,492) 28,359
Exploration and impairment 11,508 27,227 18,591
Other, net 2,563 2,322 (4,711)
--------- --------- ----------
29,868 6,589 44,740
Changes in assets and liabilities:
Accounts receivable (4,817) 3,187 (2,936)
Gas in storage (196) 870 (304)
Income taxes 3,080 (2,066) (33,821)
Prepaid and other assets (1,364) (1,900) (32)
Accounts payable (627) (2,218) 6,341
Funds held for future distributions 5,803 (3,253) 1,678
Other (8,521) (23,405) 14,631
--------- --------- ----------
Net cash provided (used) by operating activities from continuing operations 23,226 (22,196) 30,297
Net cash used by operating activities from disposed operations - - (48,335)
--------- --------- ----------
Net cash provided (used) by operating activities 23,226 (22,196) (18,038)
--------- --------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment (37,632) (38,294) (112,863)
Proceeds from sale of assets 3,532 704 1,517
Notes receivable and other 1,259 86 (4,192)
--------- --------- ----------
Net cash used by investing activities from continuing operations (32,841) (37,504) (115,538)
Net cash provided by investing activities from disposed operations - - 224,765
--------- --------- ----------
Net cash (used) provided by investing activities (32,841) (37,504) 109,227
--------- --------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt 72,635 - 7,825
Principal payment on long-term debt (73,434) (145) (21,850)
Proceeds (payment) on short-term borrowing - - (2,000)
Purchase of treasury stock and other financing activities (1,447) (1,663) (1,072)
Dividends paid (1,083) (1,053) (3,605)
--------- --------- ----------
Net cash used by financing activities from continuing operations (3,329) (2,861) (20,702)
Net cash provided by financing activities from disposed operations - - 6,539
--------- --------- ----------
Net cash used by financing activities (3,329) (2,861) (14,163)
--------- --------- ----------
Net (decrease) increase in cash and cash equivalents (12,944) (62,561) 77,026
Cash and cash equivalents, beginning of period 17,775 80,336 3,310
--------- --------- ----------
Cash and cash equivalents, end of period $ 4,831 $ 17,775 $ 80,336
========= ========= ==========
See notes to consolidated financial statements.
32
ENERGY CORPORATION OF AMERICA
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
FOR THE YEARS ENDED JUNE 30
(AMOUNTS IN THOUSANDS)
- -------------------------------------------------------------------------------
2003 2002 2001
-------- --------- --------
Net income (loss) $ 9,844 $(26,180) $72,356
-------- --------- --------
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustment:
Current period change 854 1,627 (1,980)
Marketable securities:
Unrealized gain (loss) (5) (102) 136
Reclassification to earnings (25) (4)
Oil and gas derivatives:
Net cumulative effect adjustment - - (2,153)
Current period transactions (2,351) 1,999 (541)
Reclassification to earnings 731 (4,198) 5,173
-------- --------- --------
Other comprehensive income (loss), net of tax (796) (678) 635
-------- --------- --------
Comprehensive income (loss) $ 9,048 $(26,858) $72,991
======== ========= ========
See notes to consolidated financial statements.
33
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED JUNE 30, 2003, 2002 AND 2001
- --------------------------------------------------------------------------------
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 17.
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, but does not
otherwise have the ability to control. 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
34
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.
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 forty 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):
2003 2002
---------- ----------
Oil and gas properties $ 337,904 $ 320,148
Pipelines 20,594 20,703
Other property and equipment 23,537 19,598
---------- ----------
382,035 360,449
Less accumulated depletion, depreciation and amortization (128,765) (116,294)
---------- ----------
Net property, plant and equipment $ 253,270 $ 244,155
========== ==========
Long-Lived Assets - Statement of Financial Accounting Standards ("SFAS")
------------------
No. 144, "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, 2003, the Company recognized impairment of oil and gas
property of approximately $3.1 million. During fiscal year 2002, in
addition to the impairment of oil and gas property of approximately $19.3
million, the Company recognized impairment expense of $0.1 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 translation
adjustment is included in stockholders' equity as a component of other
comprehensive income.
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".
35
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.
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.
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 and Texas. 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, 2003,
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.
Prior Year Reclassifications - Certain amounts in the financial statements
-----------------------------
of prior years have been reclassified to conform to the current year
presentation.
Recent Accounting Pronouncements - The FASB and representatives of the
----------------------------------
accounting staff of the Securities and Exchange Commission ("SEC") are
currently engaged in discussions regarding the application of certain
provisions of SFAS No. 141, "Business Combinations," and SFAS No. 142,
"Goodwill and Other Intangible Assets," to companies in the extractive
industries, including oil and gas companies. The FASB and the SEC staff are
considering whether the provisions of SFAS No. 141 and SFAS No.142 require
registrants to classify costs associated with mineral rights, including
both proved and unproved lease acquisition costs, as intangible assets in
the balance sheet, apart from other capitalized oil and gas property costs,
and provide specific footnote disclosures. Historically, the Company has
included oil and gas lease acquisition costs as a component of oil and gas
properties. In the event the FASB and SEC staff determine that costs
associated with mineral rights are required to be classified as intangible
assets, a portion of our oil and gas property costs incurred since the June
30, 2001 effective date of SFAS Nos. 141 and 142 would be separately
36
classified on our balance sheets as intangible assets. However, our results
of operations and cash flows would not be affected since such intangible
assets would continue to be depleted and assessed for impairment in
accordance with successful efforts accounting rules and impairment
standards.
Effective July 1, 2002, the Company adopted SFAS No. 143, "Accounting for
Asset Retirement Obligations." SFAS No. 143 provides the accounting
requirements for retirement obligations associated with tangible long-lived
assets. When the liability is initially recorded, the entity capitalizes
the cost, thereby increasing the carrying amount of the related long-lived
asset. Over time, the liability is accreted, and the capitalized cost is
depreciated over the useful life of the related asset.
For the Company, asset retirement obligations primarily relate to the
abandonment of oil and gas producing facilities. While assets such as
pipelines and marketing assets may have retirement obligations covered by
SFAS No. 143, certain of those obligations are not recognized since the
fair value cannot be estimated due to the uncertainty of the settlement
date of the obligation.
The initial application of this accounting standard by ECA as of July 1,
2002, resulted in an increase in net plant assets of $0.4 million, an asset
retirement obligation liability of $0.5 million, and a cumulative effect of
a change in accounting principle of $0.1 million. Due to a change in
estimate by ECA in fiscal year 2003 regarding SFAS No. 143, the initial
application was changed to an asset retirement obligation liability of $0.7
million, a net plant asset increase of $0.6 million, and a cumulative
effect of a change in accounting principle of $0.1 million as of June 30,
2003.
(IN THOUSANDS)
--------------
ASSET RETIREMENT OBLIGATIONS AS OF JULY 1, 2002: $ 471
Liabilities incurred:
Additional wells drilled 181
Liabilities settled:
Reduction for wells sold (86)
Accretion expense (included in depletion, deprec.,
amortiz.-other) 33
Change in estimate 125
-------
Asset retirement obligations as of June 30, 2003 $ 724
=======
In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities" This Statement addresses
financial accounting and reporting for costs associated with exit or
disposal activities and nullifies EITF Issue No. 94-3, "Liability
Recognition for Certain Employee Termination Benefits and Other Costs to
Exit an Activity (including Certain Costs Incurred in a Restructuring)".
This Statement requires recognition of a liability for a cost associated
with an exit or disposal activity when the liability is incurred, as
opposed to when the entity commits to an exit plan under EITF No. 94-3.
SFAS No. 146 is to be applied prospectively to 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.
In December 2002, the FASB approved Statement of Financial Accounting
Standards No. 148, "Accounting for Stock-Based Compensation - Transition
and Disclosure - an amendment of FASB
37
Statement No. 123" (SFAS No. 148). SFAS No. 148 amends Statement of
Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation" (SFAS No. 123) to provide alternative methods of transition
for a voluntary change to the fair value based method of accounting for
stock-based employee compensation. In addition, SFAS No. 148 amends the
disclosure requirements of SFAS No. 123 to require prominent disclosures in
both annual and interim financial statements about the method of accounting
for stock-based employee compensation and the effect of the method used on
reported results. SFAS No. 148 is effective for financial statements for
fiscal years ending after December 15, 2002. 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".
In April 2003, FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities" to amend and clarify
financial accounting and reporting for derivative instruments, including
certain derivative instruments embedded in other contracts for hedging
activities. This Statement is effective for contracts entered into or
modified after June 30, 2003, and for hedging relationships designated
after June 30, 2003. Management believes SFAS No. 149 has no material
impact on the Company's financial condition or results of operation as of
June 30, 2003. The Company will adopt this Statement as of July 1, 2003.
In May 2003 the FASB issued Statement of Financial Accounting Standards No.
150, "Accounting for Certain Financial Instruments with Characteristics of
both Liabilities and Equity". SFAS No. 150 establishes standards for how an
issuer classifies and measures certain financial instruments with
characteristics of both liabilities and equity, and will require
instruments that fall within the scope of this pronouncement to be
classified as liabilities. This statement is effective for financial
instruments entered into or modified after May 31, 2003, and otherwise is
effective at the beginning of the first interim period beginning after June
15, 2003. The Company does not believe the adoption of this statement will
have a material effect on the Company's financial position or results of
operations.
In November 2002, the FASB issued Financial Interpretation No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees,
including Indirect Guarantee of Indebtedness of Others" (FIN 45). FIN 45
requires that upon issuance of a guarantee, the guarantor must recognize a
liability for the fair value of the obligation it assumes under that
guarantee. FIN 45's provisions for initial recognition and measurement
should be applied on a prospective basis to guarantees issued or modified
after December 31, 2002. The guarantor's previous accounting for guarantees
that were issued before the date of FIN 45's initial application may not be
revised or restated to reflect the effect of the recognition and
measurement provisions of the Interpretation. The disclosure requirements
are effective for financial statements of both interim and annual periods
that end after December 15, 2002. The Company's adoption of FIN 45 on
January l, 2003 did not effect its financial position or results of
operations. In January 2003, the FASB issued FASB Interpretation No. 46,
"Consolidation of Variable Interest Entities" (FIN 46). FIN 46 clarifies
the application of Accounting Research Bulletin No. 51, "Consolidated
Financial Statements" to certain entities in which equity investors do not
have the characteristics of a controlling financial interest or do not have
sufficient equity at risk for the entity to finance its activities without
additional subordinated support from other parties. FIN 46 requires
existing unconsolidated variable interest entities to be consolidated by
their primary beneficiaries if the entities do not effectively disperse
risks among parties involved. All companies with variable interests in
variable interest entities created after January 31, 2003, shall apply the
provisions of FIN 46 to those entities immediately. FIN 46 is effective for
the first fiscal year or interim period
38
beginning after June 15, 2003, for variable interest entities created
before February 1, 2003. The Company will prospectively apply the
provisions of FIN 46 that were effective January 31, 2003.
Supplemental Disclosures of Cash Flow Information - Supplemental cash flow
------------------------------------------------------
information for the years ended June 30 is as follows (in thousands):
2003 2002 2001
-------- -------- -------
Cash paid for:
Interest $16,383 $18,935 $19,210
Income taxes 15 114 37,983
Income taxes refunded (9,809) (111) -
Noncash investing and financing activities:
Dividends declared and unpaid at year end 297 262 265
Liabilities assumed in acquisition - - 824
3. 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.
On February 5, 2003, the Company purchased certain oil and gas properties
located in southern West Virginia for $5.6 million, after certain
adjustments. The purchase included proved developed producing gas reserves,
estimated at 4 Bcf, 90 producing wells and over 30,000 acres.
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 year ended
June 30 are as follows (in thousands):
2001 (1)
---------
Net sales $ 9,929
---------
Loss before income taxes (3,164)
Income taxes benefit (1,317)
---------
Loss from discontinued operations $ (1,847)
=========
(1) Discontinued operations for one and one half months in fiscal year
2001
39
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, 2003 are designated as cash flow hedges. 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 had 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. At June 30, 2003, the Company had swap agreements maturing
from July 2003 through June 2005 covering 5,058,000 Mmbtu. At June 30, 2003
the company had recorded a $1.3 million loss in accumulated other
comprehensive income, $0.8 million of short term derivative liabilities,
$1.3 million in long term derivative liabilities and $0.8 million in
deferred tax asset.
For the year ended June 30, 2003 the Company recognized a net loss in
revenues on its natural gas hedging activities of $1.2 million. 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 and a net loss of $8.3
million for the year ended June 30, 2001. The estimated net amount of the
existing losses within other comprehensive income that are expected to be
reclassified into earnings within the next twelve months is approximately
$0.5 million.
6. DEBT
Long-Term Debt - At June 30 long-term debt consisted of the following (in
---------------
thousands):
2003 2002
--------- ---------
ECA senior subordinated notes, interest at 9.5% payable
semi-annually, due May 15, 2007 $132,073 $197,672
Revolving credit agreements, variable rates 40,227 -
Installment notes payable, at imputed interest rates ranging from
from 8.0% to 9.5% 1,030 1,150
--------- ---------
173,330 198,822
Less current portion (133) (121)
--------- ---------
$173,197 $198,701
========= =========
The Company's debt agreements contain 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.
40
Scheduled maturities of the Company's long-term debt at June 30, 2003 for
each of the next five years and thereafter are as follows (in thousands):
2004 $ 213
2005 1,213
2006 39,440
2007 132,182
2008 100
Thereafter 584
--------
Total payments 173,732
Less: imputed interest 402
--------
Present value of scheduled maturities $173,330
========
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.
For the year ended June 30, 2003 the Company purchased approximately $65.6
million of the Notes that resulted in a gain of $23.7 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 then existing oil and gas
assets of the Company at the time the Agreement was entered into. 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 August 28, 2003, there are currently
$38.9 million in outstanding borrowings under the Agreement.
Other Credit Facilities - The Company has an unsecured revolving line of
------------------------
credit totaling $2.0 million with a financial institution with an interest
rate of prime plus 0.25%, which expires June 30, 2005. As of June 30, 2003
there was $1.0 million outstanding under the line of credit with no amounts
outstanding as of June 30, 2002.
Other Notes - In December 2000 the Company assumed a note which stipulated
------------
that 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, 2003 and
2002, the balance due was $1.1 million and $1.2 respectively.
The Company purchased certain pipelines during 1998 constituting a natural
gas gathering system in the State of West Virginia. The Company paid 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, 2003 and 2002, the balance due to the seller was $0.3
and $0.5 million respectively.
41
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):
2003 2002 2001
-------- --------- ---------
Current:
Federal $(6,610) $ (3,436) $(27,749)
State (2) 1,385 (7,842)
-------- --------- ---------
Total current (6,612) (2,051) (35,591)
-------- --------- ---------
Deferred:
Federal 11,502 (13,381) 23,115
State 1,183 (1,390) 5,244
-------- --------- ---------
Total deferred 12,685 (14,771) 28,359
-------- --------- ---------
Total provision (benefit) for income taxes $ 6,073 $(16,822) $ (7,232)
======== ========= =========
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 from continuing operations for the years ended June
30 is summarized below (in thousands):
2003 2002 2001
------- --------- --------
Tax provision (benefit) at the federal statutory rate $5,513 $(15,051) $(6,101)
State taxes, net of federal tax effects 663 (2,516) (1,151)
Effect of rate change 12 103 (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)
Investment tax credit expiration
Other, net (115) 2,690 2,473
------- --------- --------
Provision (benefit) for income taxes $6,073 $(16,822) $(7,232)
======= ========= ========
42
Components of the Company's deferred tax assets and liabilities, as of June
30 are as follows (in thousands):
2003 2002
--------- ---------
Deferred tax assets:
Royalty trust agreements $ 4,640 $ 7,830
Tax credits and carryforwards 7,795 10,113
Other 2,512 3,874
--------- ---------
Total deferred tax assets 14,947 21,817
--------- ---------
Deferred tax liabilities:
Property, plant and equipment (28,920) (25,249)
Other liabilities (6,362) (4,218)
--------- ---------
Total deferred tax liabilities (35,282) (29,467)
--------- ---------
Net deferred income tax liability (20,335) (7,650)
Current deferred tax asset 41 2,237
--------- ---------
Net long-term deferred tax liability $(20,376) $ (9,887)
========= =========
At June 30, 2003 and 2002 the Company has the following federal and state tax
credits and carryforwards (in thousands): 2003 2002
Year of Year of
Amount Expiration Amount Expiration
------- ---------- ------- ----------
AMT tax credits $ 4,444 None $ 9,355 None
Charitable Contribution Carryover 3 2007-2008 -
------- -------
Total federal credits and carryforwards $ 4,447 $ 9,355
======= =======
State net operating loss carryovers $ 3,348 2005-2022 $ 758 2005-2021
------- -------
Total state carryovers $ 3,348 $ 758
======= =======
Total federal and state carryovers $ 7,795 $10,113
======= =======
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. During 2003, the Company utilized $4.9
million in AMT Credits. The $4.4 million in remaining AMT credits may be
utilized in future periods.
43
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. 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 $2.4 million, $0 and $1.3 million of profit sharing expense
during the years ended June 30, 2003, 2002 and 2001.
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 $0.27 million, $0.25 million and $0.24 million
for the years ended June 30, 2003, 2002, and 2001.
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.
Pursuant to an Agreement dated December 28, 1998, the Company is required
to purchase all shares owned by Kenneth W. Brill upon notice by Mr. Brill's
estate or promptly after the passage of two years from Mr. Brill's death if
the estate does not sooner tender the shares. Mr. Brill died on July 20,
2003. The Agreement provides that the Company shall make installment
payments for the purchase of the stock over a five-year period. The Company
has not yet determined the purchase price of the stock.
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, 2003, the Company had 111,246 shares of voting
--------------
common stock in treasury, carried at cost. The Company purchased 6,262 and
10,630 shares of voting common stock during the years ended June 30, 2003
and 2002, respectively. At June 30, 2003, the Company had 18,853 shares of
non-voting Class A stock in treasury, carried at cost. The Company
purchased 4,473 and 3,993 shares of non-voting Class A stock during the
years ended June 30, 2003 and 2002.
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:
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
=========
44
No options were exercised for either of the years ended June 30, 2003 or
2002. Therefore, as of June 30, 2003, 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 income (loss)
per common share for the years ended June 30 is as follows:
2003 2002 2001
--------- --------- ---------
Income (loss) from continuing operations $ 9,917 $(26,180) $(10,199)
Discontinued operations 82,555
Change in accounting principle, net of tax $ (73)
-------------------------------
Net income (loss) $ 9,844 $(26,180) $ 72,356
==============================================================================
Shares:
Basic 651,205 657,707 664,673
Diluted 665,471 657,707 664,673
==============================================================================
Basic net income (loss) per common share:
Income (loss) from continuing operations
before extraordinary items $ 15.23 $ (39.80) $ (15.34)
Discontinued operations - - 124.20
Change in accounting principle, net of tax (0.11) - -
------------------------------------------------------------------------------
Basic net income (loss) per common share $ 15.12 $ (39.80) $ 108.86
==============================================================================
Diluted net income (loss) per common share:
Income (loss) from continuing operations
before extraordinary items $ 14.90 $ (39.80) $ (15.34)
Discontinued operations - - 124.20
Change in accounting principle, net of tax (0.11) - -
------------------------------------------------------------------------------
Diluted net income (loss) per common share $ 14.79 $ (39.80) $ 108.86
==============================================================================
For fiscal years 2002 and 2001 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.
45
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 and equity
and earnings will not be recognized 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):
2002 2001 2000
--------- -------- --------
Current assets $ 6,679 $ 11,336 $10,744
Oil and gas properties 110,555 100,833 84,050
Other assets 1,309 1,966 3,233
--------- -------- --------
Total assets $118,543 $114,135 $98,027
========= ======== ========
Current liabilities $ 14,149 $ 14,505 $12,955
Long-term debt 63,900 51,700 54,200
Other liabilities 7,953 8,092 1,433
Redeemable preferred shares 34,925 34,287 33,650
Members' equity (deficit) 2,262 1,764 (4,211)
Accumulated other comprehensive (loss) income (4,646) 3,787 -
--------- -------- --------
Total liabilities and equity $118,543 $114,135 $98,027
========= ======== ========
Net sales $ 38,002 $ 44,173 $36,551
Operating income 13,872 16,737 9,338
Net income $ 4,782 $ 10,259 $ 5,267
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 for the each of the years ended June
30, 2003 and 2002, and $1.3 million for the year ended June 30, 2001.
At June 30, 2003 future minimum lease payments for each of the next five
years and thereafter are as follows (in thousands):
2004 $ 909
2005 1,019
2006 402
2007 336
2008 338
Thereafter 690
------
$3,694
======
46
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 for each of the years ended June 30, 2003 and 2002
and $0.47 million for the year ended June 30, 2001.
The Company acquired interests in various Petroleum Exploration Permits in
New Zealand during the year ended June 30, 2003 from an entity controlled
by an officer of the Company for approximately $300,000.
The Company advanced funds to certain officers and other related parties,
at 7% to 8% interest. Balances totaled $0.3 million at June 30, 2003 and
2002. 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.
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 $0.1 million
at June 30, 2003 and $0.2 million at June 30, 2002. 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.
Between 1995 and 1997, the Company issued 4,800 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 $0.2 million at
June 30, 2003 and 2002. 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. During
fiscal years 2002 and 2003, certain officers and directors representing
approximately 74% of the total production, assigned back their interest in
these properties for nominal consideration. The remaining book value of
this asset at June 30, 2003 is $1.0 million.
14. CONTRACT SETTLEMENTS
Effective May 14, 2003, the Company entered into a Settlement Agreement
(the "Agreement") with Allegheny Energy ("Allegheny") which mutually
resolved all outstanding issues and claims. Under the Agreement, the
Company neither received nor paid any cash consideration, but recognized
the following revenue and expenses as a result of the settlement for the
year ended June 30, 2003: (i) gas sales of $3.1 million was recognized as a
result of the termination and release of the Gas Sale and Purchase
Agreement ("Gas Contract") dated December 20, 1999 which called for a
prepayment by Allegheny and subsequent delivery of gas volumes from the
Company to Allegheny and (ii) net other income of $1.4 million was also
recorded related to the transaction.
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. The Complaint was later amended to add a
claim for fraud. Oracle answered the complaint, substantially denying all
of the Company's allegations, and filed a counterclaim against the Company.
The case was scheduled for trial in January 2003; however, prior to the
commencement of the trial, the case was settled on terms satisfactory to
the Company.
47
15. 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 $8.1 and
$9.0 million at June 30, 2003 and 2002, 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.
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.
16. 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 revolving
lines of credit with variable rates and fixed rate facilities. At June 30,
2003, the estimated fair value of the Company's subordinated debt was $92.4
million and the book value was $132.1 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.
48
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.
17. 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"), a non-GAAP
financial measure, to evaluate each segment's operations. Reconciliation of
non-GAAP financial measure is as follows (in thousands):
2003 2002 2001
-------- --------- --------
Net income (loss) $ 9,844 $(26,180) $72,356
Add:
Interest expense 16,383 19,671 20,094
Depletion, depreciation, amortization-o&g 12,140 12,362 9,290
Depletion, depreciation, amortization-other 4,294 2,934 2,763
Impairment & exploratory costs 11,729 27,693 19,015
Income tax expense (benefit) 6,073 (16,822) (7,232)
Subtract:
Change in accounting principle, net of tax (73) - -
Discontinued operations - - 82,555
-------- --------- --------
EBITDAX $60,536 $ 19,658 $33,731
======== ========= ========
49
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):
Exploration Marketing
and and
Production Pipeline Other Consolidated
------------- ----------- --------- --------------
2003
Sales to unaffiliated customers $ 56,907 $ 60,484 $ 35 $ 117,426
Depreciation, depletion, amortization 13,559 661 2,214 16,434
Impairment and exploratory costs 11,729 - - 11,729
Operating profit 1,556 3,922 1,240 6,718
Interest expense, net 21,982 (6,485) 273 15,770
EBITDAX 29,125 4,718 26,693 60,536
Total assets 191,191 88,831 15,812 295,834
Capital expenditures 36,147 241 1,244 37,632
----------------------------------------------------------------------------------------------
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
----------------------------------------------------------------------------------------------
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
$6.1 million, $3.4 million and $3.0 million, as of June 30, 2003, 2002 and
2001 and any related revenues and expenses.
50
18. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
The following represents selected quarterly financial information for the
years ended June 30 (in thousands, except per share data):
Quarter Ended
-----------------------------------------------------
2003 September 30 December 31 March 31 June 30
--------------- ------------- ---------- ---------
Total revenue $ 22,589 $ 26,383 $ 34,038 $ 34,416
Gross profit (loss) 677 (1,720) 3,456 4,305
Income (loss) from continuing operations (1,562) 8,320 3,348 (188)
Income (loss) per share on continuing
operations, basic (2.43) 12.77 5.15 (0.38)
diluted (2.37) 12.49 5.04 (0.37)
Net income (loss) (1,562) 8,320 3,347 (261)
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 per share, basic and diluted (2.31) (3.17) (8.15) (26.17)
Net loss (1,517) (2,086) (5,358) (17,219)
*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.
51
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):
2003 2002 2001
---------- --------- ---------
Capitalized costs:
Proved properties $ 327,958 $310,495 $271,465
Unproved properties 9,946 9,653 45,760
---------- --------- ---------
Total 337,904 320,148 317,225
Less accumulated depletion and depreciation (107,233) (97,523) (85,748)
---------- --------- ---------
Net capitalized costs $ 230,671 $222,625 $231,477
========== ========= =========
Company's share of equity method investee's net
capitalized costs (see Note 11) * $ 27,167 $ 23,908 $ 19,729
========== ========= =========
Costs incurred:
Acquisition of proved and unproved properties $ 5,879 $ 717 $ 80,394
Development costs 14,105 10,977 13,649
Exploration costs 15,292 20,737 15,115
---------- --------- ---------
Total costs incurred $ 35,276 $ 32,431 $109,158
========== ========= =========
Company's share of equity method investee's total
costs incurred (see Note 11) * $ 7,674 $ 2,309 $ 2,695
========== ========= =========
* For the years ended December 31, 2002, 2001 and 2000.
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):
2003 2002 2001
------- -------- -------
Revenues from sale of oil and gas $51,410 $38,939 $41,555
Less:
Production costs 4,436 5,001 3,011
Production taxes 3,233 2,077 3,000
Exploration and impairment 11,729 27,605 11,458
Depletion, depreciation and amortization 12,140 12,362 9,290
Income tax expense (benefit) 7,353 (2,999) 5,475
------- -------- -------
Income (loss) from oil and gas operations $12,519 $(5,107) $ 9,321
======= ======== =======
Company's share of equity method investee's
income from oil and gas operations (see Note 11) * $ 4,354 $ 4,955 $ 3,224
======= ======== =======
* For the years ended December 31, 2002, 2001 and 2000.
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.
52
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.
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, 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
Revisions of previous estimates (11,847) (1,045)
Extensions and discoveries 23,623 580
Sales of reserves in place (2,941) (16)
Purchases of reserves in place 8,371 -
Production (9,755) (104)
------------ ----------
June 30, 2003 190,796 2,366
============ ==========
Proved developed reserves:
June 30, 2001 175,784 987
June 30, 2002 160,224 1,135
June 30, 2003 161,796 1,064
Company's share of equity method investee's proved reserve at:
June 30, 2001 9,497 11,811
June 30, 2002 7,445 12,063
June 30, 2003 7,755 11,427
53
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.
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):
2003 2002 2001
----------- ---------- ----------
Future cash in flows $1,152,845 $ 715,755 $ 828,403
Future production and development costs (235,960) (243,828) (271,051)
Future income tax expense (290,000) (116,000) (145,000)
----------- ---------- ----------
Future net cash flows before discount 626,885 355,927 412,352
10% discount to present value (365,662) (205,014) (240,071)
----------- ---------- ----------
Standardized measure of discounted future net cash
flows related to proved oil and gas reserves $ 261,223 $ 150,913 $ 172,281
=========== ========== ==========
Company's share of equity method investee's
standardized measure of discounted future net
cash flows $ 67,375 $ 53,838 $ 69,478
=========== ========== ==========
54
Principal changes in the standardized measure of discounted future net cash
flows for the years ended June 30 are as follows (in thousands):
2003 2002 2001
--------- --------- ---------
Standardized measure of discounted future
net cash flows at beginning of period $150,913 $172,281 $124,871
Sales of oil and gas produced, net of
production costs (35,155) (26,525) (28,347)
Net changes in prices and production costs 175,844 (13,507) 3,338
Changes in production rates and other 1,015 (5,867) 15,526
Extensions, discoveries and other additions, net
of future production and development costs 52,407 13,622 33,991
Changes in estimated future development costs (16,243) (4,820) (31,981)
Development costs incurred 14,105 10,977 9,232
Revisions of previous quantity estimates (35,028) (24,772) (15,677)
Purchase of reserves in place 16,185 58,868
Sale of reserves in place (5,560)
Accretion of discount 15,246 17,228 12,487
Net change in income taxes (72,506) 12,296 (10,027)
--------- --------- ---------
Standardized measure of discounted
future net cash flows at end of period $261,223 $150,913 $172,281
========= ========= =========
* * * * *
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, 2003 are listed below, together with a
description of their experience and certain other information. All of the
Directors were elected or re-elected for a one year term at the Company's
December 2002 annual meeting of stockholders. Executive officers are appointed
by the Board of Directors.
55
Name Position with Company or Subsidiary
- ----------------------- -----------------------------------
John Mork 54 President and Chief Executive Officer; Director
Joseph E. Casabona 59 Executive Vice President; Director
Michael S. Fletcher 54 Chief Financial Officer
Donald C. Supcoe 47 Senior Vice President, Secretary and General Counsel
Edward J. Davies 61 Senior Vice President
J. Michael Forbes 43 Vice President and Treasurer
George V. O'Malley 51 Vice President Accounting
K. Ralph Ranson, II 60 Vice President Marketing
Julie Ann Kitano 46 Assistant Secretary
W. Gaston Caperton, III 62 Director
Peter H. Coors 55 Director
L. B. Curtis 78 Director (Chairman)
John J. Dorgan 78 Director
Arthur C. Nielsen, Jr. 83 Director
F. H. McCullough, III 55 Director
Julie Mork 52 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 Board 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 Board of Directors of the West Virginia and Pennsylvania Independent Oil and
Gas Associations.
Peter H. Coors has been a Director of the Company since 1996. Mr. Coors is
Chairman of Coors Brewing Company and Chairman 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. Bancorp, 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 and Seeds of Hope Foundation.
L.B. Curtis has been a Director of the Company since 1993 and Chairman
since 1998. 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
56
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 and is responsible
for the Company's operations in the west and internationally, which includes
Westech and WENZ. He has served as President of Westech since 1994. Previously,
Mr. Davies was with Conoco Inc., where he held various positions culminating
with 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 starting in 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 1998 until the Company sold Mountaineer in
August of 2000. Prior to becoming President in 1998, he 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. Mr. McCullough is a graduate of the University of Southern
California with a Bachelor of Arts Degree in International Economics and two
Masters Degrees in Business Administration and Financial Systems Management. He
is a graduate of the Northwestern University Kellogg Graduate School of
Management Executive Marketing Program.
John Mork has been President and Chief Executive Officer of the Company and
a Director of the Company since its formation. Mr. Mork served in various
capacities at Union Oil Company until 1972 when he joined Pacific States Gas and
Oil, Inc. and subsequently founded Eastern American. Mr. Mork was President and
a Director of Eastern American from 1973 until 1993. Mr. Mork is a past 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.
57
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. She is currently Managing Director of the ECA Foundation, Inc. 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.
George V. O'Malley has been Vice President - Accounting for the Company
since December 2002. Before being elected Vice President, Mr. O'Malley served
as Director of Accounting. Mr. O'Malley joined Eastern American in April 1991
and served in various capacities including Vice President and Treasurer. Prior
to joining the Company, he held various positions in industry and public
accounting. Mr. O'Malley currently serves as President Elect and a member of
the Board of the West Virginia Society of CPA's. Mr. O'Malley graduated from
Marshall University with a Bachelor's Degree in Accounting and is a Certified
Public Accountant.
Arthur C. Nielsen, Jr., Chairman Emeritus of A.C. Nielsen Co., 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 1998 until its sale in August of 2000.
Prior to joining Mountaineer in 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.
58
ITEM 11. EXECUTIVE COMPENSATION
----------------------------------
The following table sets forth for fiscal year 2003 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 2003 $265,376 $ 125,000 $ 77,045 $ 5,867
President and Chief Executive Officer 2002 258,892 125,000 59,670 26,067
2001 256,068 1,146,635 4,349 35,251
Joseph E. Casabona 2003 $243,595 $ 80,000 $ 6,875 $ 4,763
Executive Vice President 2002 238,277 125,942 2,905 4,574
2001 231,538 1,457,630 (2) 1,888 4,454
Michael S. Fletcher 2003 $238,504 $ 45,000 $ 2,477 $ 4,558
Chief Financial Officer 2002 233,306 100,510 352 4,504
2001 232,471 56,345 124,198 (3) 3,500
Edward J. Davies 2003 $230,201 $ 45,000 $ 408 $ 6,113
Senior Vice President 2002 223,930 95,714 120 4,592
2001 207,308 53,105 899 4,181
Donald C. Supcoe 2003 $201,152 $ 65,000 $ 3,529 $ 4,005
Senior Vice President 2002 197,993 100,435 2,325 3,949
2001 188,447 54,545 1,482
_______________________________
(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. In prior years, each Director also received
160 shares of the Company's Class A Stock. The total Board of Directors'
compensation for fiscal 2003 was $0.1 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
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 29, 2003. The
59
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
------- --------
W. Gaston Caperton, III 6,680 1.08%
Joseph E. Casabona 31,376 5.09%
Colstab & Co. (Nominee for KWB Trust) (1) 49,110 7.96%
Peter H. Coors 2,946 *
L. B. Curtis 11,610 1.88%
Edward J. Davies 3,000 *
John J. Dorgan 2,130 *
J. Michael Forbes 2,200 *
F. H. McCullough, III (2) 70,035 11.35%
John Mork (3) 359,493 58.27%
Julie Mork (3) 359,493 58.27%
Arthur C. Nielsen, Jr. 36,480 5.91%
Donald C. Supcoe 3,583 *
------- --------
578,643 93.80%
All officers and directors as a group (12 persons) 529,533 85.84%
* Less than one percent.
(1) Pursuant to an agreement dated December 28, 1998 (previously attached
to the Company's Form 10-K as exhibit 10.41), the Company is required
to purchase all shares owned by Kenneth W. Brill upon notice by Mr.
Brill's estate or promptly after the passage of two years from Mr.
Brill's death if the estate does not sooner tender the shares. Mr.
Brill died on July 20, 2003. The Agreement provides that the Company
shall make installment payments for the purchase of the stock over a
five year period.
(2) Includes 67,955 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.
(3) Includes 280,930 shares held by John and Julie Mork as joint tenants,
2,663 shares held by Julie Mork individually, and 37,950 shares held
by each of the Alison Mork Trust and the Kyle Mork 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 29, 2003. 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.
60
Beneficial Ownership
Class A Stock
----------------
Shares Percent
------ --------
W. Gaston Caperton, III 1,920 6.15%
Joseph E. Casabona 3,619 11.60%
Peter H. Coors 2,534 8.12%
L.B. Curtis 1,560 5.00%
John J. Dorgan 2,320 7.44%
Michael S. Fletcher 3,355 10.75%
F.H. McCullough, III 1,920 6.15%
John Mork (1) 4,737 15.18%
Julie Mork (1) 4,737 15.18%
Arthur C. Nielsen, Jr. 3,080 9.87%
K. Ralph Ranson, II 487 1.56%
Donald C. Supcoe 2,785 8.93%
------ --------
28,317 90.75%
All officers and directors as a group (12 persons) 28,317 90.75%
_______________
(1) Includes 956 shares held by John and Julie Mork as joint tenants and
1,342 shares held by Julie Mork individually and 1,220 shares held by
the Alison Mork Trust and 1,219 shares held by the Kyle Mork Trust.
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):
61
2003 2002 2001
---------- --------- ---------
(3)
Gaston Caperton, III $ 100.01 $ 77.58 $ 56.76
Joseph E. Casabona 50.00 38.77 21.99
Peter Coors 135.00 77.58 28.38
L.B. Curtis 135.00 83.36 88.85
E.J. Davies 270.00 166.72 140.78
John J. Dorgan 29.97 19.39 14.19
Michael S. Fletcher 50.00 38.77 28.38
J. Michael Forbes 25.00 19.39 14.19
John Frederick 25.00 - 14.19
Thomas R. Goodwin 25.00 38.77 28.38
Denny McGowan 25.00 - -
John Mork (1) 1,350.00 833.60 703.89
Alison Mork Trust (2) 50.00 38.77 28.38
Kyle Mork Trust (2) 50.00 38.77 28.38
Arthur C. Nielsen, Jr. 50.00 38.77 28.38
George O'Malley 27.00 - -
Kent Schamp 28.35 21.17 15.34
Donald C. Supcoe 25.00 19.39 14.19
---------- --------- ---------
$2,450.33 $1,550.80 $1,254.65
========== ========= =========
(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 2003
Drilling Program, the actual amount of 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 January 1, 2003 . The following were
indebted to the Company (in thousands):
Outstanding Unamortized
Balance as of as of
June 30, 2003 June 30, 2003
-------------- --------------
Joseph E. Casabona $ 141 $ 33
Michael S. Fletcher 141 33
J. Michael Forbes 96 96
K. Ralph Ranson, II 28 16
Donald C. Supcoe 180 116
-------------- --------------
Total $ 586 $ 294
============== ==============
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):
62
Note Plus Unamortized
Accrued as of
Interest June 30, 2003
---------- --------------
(1) Michael S. Fletcher $ 284 $ 7
(1) Linda Given 28 1
(1) David Jordan 56 1
(2) Dennis McGowan 166 133
(1) Donald C. Supcoe 169 4
---------- --------------
$ 703 $ 146
========== ==============
(1) Promissory note is being amortized over three years, as of August 29,
2003 amounts have been forgiven.
(2) Of the $166,000 in promissory notes, $33,000 is being forgiven and
amortized over the next two 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, 2003:
Payment Volumes
(in thousands) Mmcf
--------------- -------
Joseph E. Casabona 50 66.7
L.B. Curtis 75 100.0
E.J. Davies 150 200.0
John J. Dorgan 50 66.7
F.H. McCullough, III 150 200.0
--------------- -------
$ 475 633.4
=============== =======
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 2003. The Company believes that
such rental terms are no less favorable than could have been obtained from an
unaffiliated party.
ITEM 14. CONTROLS AND PROCEDURES
--------------------------------
Under the supervision and with the participation of our management,
including our principal executive officer and principal financial officer, the
Company has evaluated the effectiveness of the design and operation of our
disclosure controls and procedures within 90 days of the filing date of this
annual report and, based on their evaluation, our principal executive officer
and principal financial officer have concluded that these controls and
procedures are effective. There were no significant changes in our internal
controls or in other factors that could significantly affect these controls
subsequent to the date of their evaluation. Disclosure controls and procedures
are our controls and other procedures that are
63
designed to ensure that information required to be disclosed by us in the
reports that we file or submit under the Securities Exchange Act of 1934, as
amended, is recorded, processed, summarized and reported, within the time
periods specified in the Securities and Exchange Commission's rules and forms.
Disclosure controls and procedures include, without limitation, controls and
procedures designed to ensure that information required to be disclosed by us in
the reports that we file under the Securities Exchange Act is accumulated and
communicated to our management, including our principal executive officer and
principal financial officer, as appropriate to allow timely decisions regarding
required disclosure.
64
PART IV
-------
ITEM 15. 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
Financial statement schedules have been omitted because they are not
applicable or the information required therein is included elsewhere
in the financial statements or notes thereto.
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.
65
* 10.8 Intentionally omitted.
* 10.9 Intentionally omitted.
* 10.1 Intentionally omitted.
* 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.
* 10.2 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.
* 10.3 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.
66
* 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.
* 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.
* 10.4 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.
31.1 Certification of Chief Executive Officer Pursuant to Section 302
of the Sarbanes-Oxley Act of 2002
31.2 Certification of Chief Financial Officer Pursuant to Section 302
of the Sarbanes-Oxley Act of 2002
* 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
67
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.
* * * * * *
68
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 25th day of
September 2003.
ENERGY CORPORATION OF AMERICA
By: /s/ John Mork
--------------------------------------
John Mork
President and Chief Executive Officer
69
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 25th day of September 2003, by the following persons in
the capacities indicated.
/s/ John Mork /s/ W. Gaston Caperton, III
- -------------------------------------------- ---------------------------------
John Mork W. Gaston Caperton, III, Director
President, Chief Executive Officer, Director
/s/ Peter H. Coors
---------------------------------
/s/ Joseph E. Casabona Peter H. Coors, Director
- --------------------------------------------
Joseph E. Casabona
Executive Vice President, Director
/s/ L. B. Curtis
---------------------------------
/s/ Michael S. Fletcher L.B. Curtis, Director
- --------------------------------------------
Michael S. Fletcher
Chief Financial Officer
/s/ John J. Dorgan
---------------------------------
John J. Dorgan, Director
/s/ F. H. McCullough III
---------------------------------
F. H. McCullough, III, Director
/s/ Julie Mork
---------------------------------
Julie Mork, Director
/s/ Arthur C. Nielsen, Jr.
---------------------------------
Arthur C. Nielsen, Jr., Director
70