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, 2004.
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]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act).
Yes [_] No [X]
The aggregate number of shares and market value of common stock held by
non-affiliates of the registrant at September 23, 2004 was 38,350 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 September 23, 2004 was 602,426 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. . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Item 7. Management's Discussion and Analysis of Results of Operations
and Financial Condition. . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Item 7A. Quantitative and Qualitative Disclosures About Market Risk . . . . . . . . . 24
Item 8. Consolidated Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm. . . . . . . . . . 26
Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Statements of Operations . . . . . . . . . . . . . . . . . . . . . . . . . 29
Statements of Stockholders Equity. . . . . . . . . . . . . . . . . . . . . 30
Statements of Cash Flows . . . . . . . . . . . . . . . . . . . . . . . . . 31
Statements of Comprehensive Income . . . . . . . . . . . . . . . . . . . . 32
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . 33
Supplemental Information on Oil and Gas Producing Activities (Unaudited) . 52
Item 9. Changes In and Disagreements With Accountants on Accounting
and Financial Disclosure . . . . . . . . . . . . . . . . . . . . . . . . . . 57
Item 9A. Controls and Procedures. . . . . . . . . . . . . . . . . . . . . . . . . . . 57
Part III
Item 10. Directors and Officers of Registrant . . . . . . . . . . . . . . . . . . . . 57
Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . 61
Item 12. Security Ownership of Certain Beneficial Owners and Management . . . . . . . 62
Item 13. Certain Relationships and Related Transactions . . . . . . . . . . . . . . . 65
Item 14. Principal Accounting Fees and Services . . . . . . . . . . . . . . . . . . . 66
Part IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K. . . . . . . 68
Part V
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72
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
aggregation of natural gas and oil, primarily in the Appalachian Basin and Gulf
Coast regions in the United States and New Zealand. The Company conducts
business primarily through its principal wholly owned subsidiaries and is one of
the largest oil and gas operators in the Appalachian Basin. 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 American Energy Corporation ("Eastern
American").
As of June 30, 2004, the Company had approximately 229 full-time and 27
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.
Definitions - 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.
BUSINESS ACTIVITY
- ------------------
SEGMENT INFORMATION
- --------------------
The Company's businesses constitute two operating segments (i) gas and oil
exploration and production and (ii) gas aggregation and pipelines. For
financial information on these segments, see Note 16 to the Consolidated
Financial Statements.
4
GAS AND OIL EXPLORATION AND PRODUCTION
- --------------------------------------
OPERATIONS AND SIGNIFICANT DEVELOPMENTS
The Company's proved net gas and oil reserves are estimated as of June 30,
2004 at 215,475 Mmcf and 1,280 Mbbls, respectively. For the fiscal year ended
June 30, 2004, the Company's net gas production was 10,718 Mmcf and net oil
production was 107 Mbbls, for a total of 11,360 net Mmcfe.
DEVELOPMENT ACTIVITY
The Company, in fiscal year 2004, drilled 27 productive gross wells (17.6
net), and recompleted 2 wells, adding 5,234 gross Mcf of gas production per day.
EXPLORATORY ACTIVITY
Exploration wells and activity are summarized under their respective
project areas.
1. Newburg/Silurian, Trenton/Black River -- West Virginia. The Company
drilled one successful well, two dry holes and one well that is currently
being tested and appears to be productive. Current production from the
Trenton/Black River discovery is approximately 700 gross Mcf per day and
140 net Mcf per day. The Company plans to continue to pursue select
extension and exploration opportunities in both trends.
2. Texas. The Company drilled four exploratory wells with a success
rate of 50%. The principal producing formation is the Wilcox at depths
ranging to 16,000 feet. The Company is working on a development drilling
plan to capitalize on its exploration success.
3. New Zealand. The Company drilled an unsuccessful well in the Mt.
Messenger formation in the Taranaki region. The Company continues with an
active drilling program in New Zealand.
4. Rocky Mountains. The Company drilled four unsuccessful exploration
wells in the northern Powder River Basin.
COMPETITION
- -----------
The Company encounters substantial competition in acquiring properties,
aggregating 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.
Natural gas competes with other forms of energy available to customers,
primarily based on price. These alternate forms of energy include electricity,
coal and fuel oils. Changes in the availability or price of natural gas or
other forms of energy, as well as business conditions, conservation,
legislation, regulations and the ability to convert to alternate fuels and other
forms of energy may affect the demand for natural gas.
REGULATIONS AFFECTING OPERATIONS
- ----------------------------------
The Company's operations are affected by extensive regulation pursuant to
various federal, state and local laws and regulations relating to the
exploration for and development, production, gathering, aggregation,
transportation and storage of oil and gas. These regulations, among other
things, can affect
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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 PIPELINES
- ---------------------------------
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, 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 2,280 miles of gathering lines
and intrastate pipelines that are used in connection with its gas aggregation
activities. The Company finalized the purchase of an additional 100-mile long
natural gas gathering system ("System 8000") from Columbia Gas Transmission
during the first quarter of fiscal year 2005. System 8000 is located in
northeastern West Virginia and is situate among one of the Company's existing
operating areas.
During the fiscal year ended June 30, 2004, Eastern Marketing aggregated
and sold an average of 40.4 Mmcf of gas per day, of which 38.9 Mmcf per day
represented sales of gas produced from wells operated by the Company. This
represents a 2% decrease in the overall volumes compared to fiscal year 2003,
during which Eastern Marketing aggregated and sold an average of 41.2 Mmcf of
gas per day.
GAS SALES AND PURCHASE CONTRACTS
- -------------------------------------
The Company has satisfied its obligations under all gas sales contracts
(14.7 Bcf in fiscal year 2004) 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 (14.2 Bcf in fiscal 2004),
and from natural gas purchased by the Company pursuant to its aggregation
activities from third parties (0.5 Bcf in fiscal 2004).
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 entered into a gas sales contract with AFG Industries, Inc.
("AFG") for the sale of up to 4,000 MMBtu per day from January 1, 2004 through
December 31, 2004. AFG is a "Float Glass" plant adjacent to an existing
Company pipeline. The sales contract price is based off the NYMEX settlement
price for Natural Gas Henry Hub Futures Contracts each month plus an Appalachian
Basis component.
6
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.
The purchase contract price is based off of the average of certain Hentry Hub
Gas Futures Contracts related to the month of production plus an Appalachian
Basis component.
REGULATIONS AFFECTING MARKETING AND TRANSPORTATION
- -------------------------------------------------------
As a purchaser of natural gas, the Company depends on the transportation,
gathering 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,
gathering 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
2004 2003 2002
---------- -------- --------
Net proved:
Gas (Mmcf) 215,475 190,796 183,345
Oil (Mbbls) 1,280 2,366 2,951
Total (Mmcfe) 223,155 204,992 201,051
Net proved developed:
Gas (Mmcf) 170,131 161,796 160,224
Oil (Mbbls) 626 1,064 1,135
Total (Mmcfe) 173,887 168,180 167,034
Estimated future net cash flows
before income taxes (in thousands) $1,074,207 $916,885 $471,927
Present value of estimated future net cash
flows before income taxes (in thousands) (1) $ 435,387 $382,094 $200,087
_______________
(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, 2004:
Present Value
-------------------- Natural Gas
Amount Oil Natural Gas Equivalent
Region (thousands) % (Mbbls) (Mmcf) (Mmcfe)
- ----------------- ------------ ------ ------- ------------ ------------
Appalachian Basin $ 364,258 83.7% 422 178,767 181,299
Western 53,958 12.4% 362 30,881 33,053
New Zealand 17,171 3.9% 496 5,827 8,803
------------ ------ ------- ------------ ------------
Total $ 435,387 100.0% 1,280 215,475 223,155
============ ====== ======= ============ ============
PRODUCING WELLS
- ----------------
The following table sets forth certain information relating to productive
wells at June 30, 2004. Wells are classified as oil or gas according to their
predominant production stream.
Gross Wells Net Wells
======================= ======================
Region Oil Gas Total Oil Gas Total
- ----------------- ----- ------- ------- ---- ------- -------
Appalachian Basin 21.0 5,299.0 5,320.0 13.0 3,347.0 3,360.0
Western 7.0 15.0 22.0 2.6 4.4 7.0
New Zealand - 4.0 4.0 - 4.0 4.0
----- ------- ------- ---- ------- -------
Total 28.0 5,318.0 5,346.0 15.6 3,355.4 3,371.0
===== ======= ======= ==== ======= =======
8
ACREAGE
- -------
The following table sets forth the developed and undeveloped gross and net
acreage held at June 30, 2004:
Developed Acreage Undeveloped Acreage
==================== ========================
Region Gross Net Gross Net
- ----------------- --------- --------- ----------- -----------
Appalachian Basin 405,030.0 312,105.4 115,940.9 98,410.9
Western 2,448.0 1,244.3 57,262.2 34,523.5
New Zealand 740.0 736.3 2,545,848.3 1,795,502.2
--------- --------- ----------- -----------
Total 408,218.0 314,086.0 2,719,051.4 1,928,436.6
========= ========= =========== ===========
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:
2004 2003 2002
------- ------- -------
Production Data:
Oil (Mbbls) 107 104 124
Natural gas (Mmcf) 10,718 9,756 9,941
Natural gas equivalent (Mmcfe) 11,360 10,380 10,685
Average Sales Price (before the effect of hedging):
Oil per Bbl $ 29.94 $ 25.97 $ 21.11
Natural gas per Mcf $ 5.49 $ 5.13 $ 2.86
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
2004 2003 2002
=========== =========== ===========
Gross Net Gross Net Gross Net
----- ---- ----- ---- ----- ----
DEVELOPMENT:
Productive
Appalachian 26.0 17.5 45.0 39.1 53.0 47.8
Western/New Zealand 1.0 0.1 2.0 0.4 1.0 0.3
----- ---- ----- ---- ----- ----
Total 27.0 17.6 47.0 39.5 54.0 48.1
===== ==== ===== ==== ===== ====
Nonproductive
Appalachian - - 3.0 2.7 1.0 0.9
Western/New Zealand 1.0 0.1 - - - -
----- ---- ----- ---- ----- ----
Total 1.0 0.1 3.0 2.7 1.0 0.9
===== ==== ===== ==== ===== ====
EXPLORATORY:
Productive
Appalachian 2.0 1.1 4.0 1.4 4.0 1.6
Western/New Zealand - - 9.0 4.0 4.0 2.3
----- ---- ----- ---- ----- ----
Total 2.0 1.1 13.0 5.4 8.0 3.9
===== ==== ===== ==== ===== ====
Nonproductive
Appalachian 2.0 0.7 2.0 1.0 5.0 2.1
Western/New Zealand 8.0 4.6 4.0 2.2 4.0 3.2
----- ---- ----- ---- ----- ----
Total 10.0 5.3 6.0 3.2 9.0 5.3
===== ==== ===== ==== ===== ====
ITEM 3. LEGAL PROCEEDINGS
-------------------------
As previously reported, the Company had been in litigation with certain
Holders of its $200,000,000 9 1/2% Senior Subordinated Notes due 2007 (the
"Noteholders") (the "Notes"). The dispute involved the calculation of the Net
Proceeds of an Asset Sale as defined in the Indenture dated May 23, 1997 between
the Company and The Bank of New York. The Company and the Noteholders have
settled the dispute, as memorialized in the Settlement Agreement executed as of
February 24, 2004, and attached to the Form 8-K filed by the Company on February
24, 2004 as Exhibit 99.11 (the "Settlement Agreement"). In settlement of the
dispute the Company agreed to repurchase $38 million in Notes. The Company has
met its obligations under the Settlement Agreement having finalized the first
Asset Sale Offer (as defined under the Indenture) in the amount of $4 million on
March 24, 2004 and the second Asset Sale Offer in the amount of $34 million on
July 29, 2004. The United States District Court for the Southern District of
West Virginia has entered a Dismissal Order dismissing the litigation with
prejudice.
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.
10
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
September 23, 2004, the Company had 32 holders of record of its common stock.
The Company declared dividends in fiscal years 2004, 2003 and 2002 of $1.2
million, $1.1 million and $1.1 million, respectively.
ITEM 6. SELECTED FINANCIAL DATA
-------------------------------
(Dollars in thousands, except per share items)
Year Ended June 30,
---------------------------------------------------
2004 2003 2002 2001 2000
-------- -------- --------- --------- ---------
Operating revenue $123,373 $117,426 $ 86,142 $129,951 $101,919
Income (loss) from operations 4,295 9,917 (26,180) (10,199) (26,508)
Earnings per common share, basic (a) 6.62 15.12 (39.80) (15.34) (40.11)
Earnings per common share, diluted (a) 6.52 14.79 (39.80) (15.34) (40.11)
Total assets 290,212 295,834 304,736 380,532 265,691
Long term debt 162,894 173,197 198,701 198,902 212,575
Dividends declared per common share $ 1.96 $ 1.72 $ 1.60 $ 5.80 $ -
(a) The effect of outstanding stock options was not included in the
computation of diluted earnings per share for years ended 2002, 2001, or
2000, 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
11
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.
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 aggregation 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, which historically have not been significant, are recorded in
the month revenue is distributed.
DERIVATIVE INSTRUMENTS - 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 as a component of other comprehensive
income 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
12
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 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
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 an estimate of the tax basis of assets and liabilities is
determined 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, 2004 AND 2003
- --------------------------------------------------------------------------------
The Company realized net income of $4.3 million for the year ended June
30, 2004 compared to a net income of $9.8 million in 2003. The decrease of $5.5
million was primarily attributable to the net effect of a $5.9 million increase
in revenue, a $3.9 million decrease in costs and expenses, a $1.3 million
13
decrease in interest expense, $27.5 million decrease in interest income and
other and a $10.8 million decrease 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 $51.7 million for the current year compared to $50.3
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 $46.8 million
versus $43.5 million for the prior year. The Company's Aggregation and Pipeline
Operating Margin (defined as gas aggregation and pipeline sales less gas
aggregation and pipeline cost of sales) totaled $4.8 million for the current
period versus $6.8 million for the prior period.
14
Production, aggregation and pipeline volumes, revenue and average sales
prices for the years ended June 30 and their related variances are as follows:
TWELVE MONTHS ENDED
JUNE 30 VARIANCE
----------------------- ------------------------
2004 2003 AMOUNT PERCENT
----------- ---------- ----------- -----------
Natural Gas
Production (Mmcf) 10,718 9,756 962 9.9%
Average sales price received ($/Mcf) 5.49 5.13 0.36 7.0%
----------- ---------- ----------- -----------
Sales ($ in thousands) 58,851 50,031 8,820 17.6%
Oil
Production (Mbbl) 107 104 3 2.9%
Average sales price received ($/Bbl) 29.94 25.97 3.97 15.3%
----------- ---------- ----------- -----------
Sales ($ in thousands) 3,204 2,701 503 18.6%
Hedging (5,213) (4,843) (370) 7.6%
Other 361 3,521 (3,160) -89.7%
----------- ---------- ----------- -----------
Total oil and gas sales ($ in thousands) 57,203 51,410 5,793 11.3%
=========== ========== =========== ===========
Aggregation Revenue
Volume (Million Mmbtu) 8,591 9,285 (694) -7.5%
Average sales price received ($/Mmbtu) 5.22 4.86 0.36 7.4%
----------- ---------- ----------- -----------
Sales ($ in thousands) 44,854 45,145 (291) -0.6%
Pipeline Revenue
Volume (Million Mmbtu) 5,528 5,675 (147) -2.6%
Average sales price received ($/Mmbtu) 2.89 2.70 0.19 7.0%
----------- ---------- ----------- -----------
Sales ($ in thousands) 15,965 15,338 627 4.1%
----------- ---------- ----------- -----------
Total aggregation and pipeline sales ($ in thousands) 60,819 60,483 336 0.6%
=========== ========== =========== ===========
Aggregation Gas Cost
Volume (Million Mmbtu) 8,591 9,285 (694) -7.5%
Average price paid ($/Mmbtu) 4.99 4.48 0.51 11.4%
----------- ---------- ----------- -----------
Cost ($ in thousands) 42,827 41,636 1,191 2.9%
Pipeline Gas Cost
Volume (Million Mmbtu) 4,469 4,550 (81) -1.8%
Average price paid ($/Mmbtu) 2.96 2.65 0.31 11.7%
----------- ---------- ----------- -----------
Cost ($ in thousands) 13,232 12,057 1,175 9.7%
----------- ---------- ----------- -----------
Total aggregation and pipeline cost ($ in thousands) 56,059 53,693 2,366 4.4%
=========== ========== =========== ===========
- -------------------------------------------------------------------------------------------------------
REVENUES. Total revenues increased $5.9 million or 5.1% between the
--------
years. The net increase was due to a 11.3% increase in oil and gas sales, a
0.6% increase in gas aggregation and pipeline sales, a 4.9% decrease in well
operations and service revenues and a 248.6% increase in other operating
revenue.
15
Revenues from oil and gas sales increased $5.8 million from $51.4 million
for the year ended June 30, 2003 to $57.2 million for the year ended June 30,
2004. Natural gas sales increased $8.8 million and oil sales increased $0.5
million. The increase is a result of an increase in both price and production.
The price increase corresponds with related indexes. The increase in production
was attributable to a decrease in extended curtailments on third party
transmission facilities compared to the prior year 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 $5.2 million for the year ended June
30, 2004 compared to a loss of $4.8 million for the year ended June 30, 2003.
Other gas sales decreased $3.2 million as a result of $3.1 million being
recognized in the year ended June 30, 2003 related to the termination and
release of a certain gas contract. The average price per Mcfe, after hedging,
was $5.03 and $4.95 for the years ended June 30, 2004 and 2003, respectively.
Revenues from gas aggregation and pipeline sales increased $0.3 million
from $60.5 million during the period ended June 30, 2003 to $60.8 million in the
period ended June 30, 2004. Gas aggregation revenue decreased $0.3 million
while pipeline revenue, which has sale and transportation components, increased
$0.6 million. The increase in gas aggregation and pipeline sales is
attributable to the increase in average sales price received offset by a decline
in production. The price increase corresponds with related indexes.
COSTS AND EXPENSES. The Company's costs and expenses decreased $3.9
--------------------
million or 3.5% between the periods primarily as a net result of a 13.1%
increase in field and lease operating expenses, a 4.4% increase in gas
aggregation and pipeline costs, a 0.9% increase in general and administrative
expenses, a 26.9% increase in taxes other than income, a 9.6% increase in oil
and gas related depletion, a 2.4% decrease in depreciation and amortization
expenses of pipelines, property and equipment, a 8.0% decrease in exploration
and impairment costs, and a gain on sale of assets compared to a loss in the
prior year.
Field and lease operating expenses increased $1.3 million. The increase
in lease operating expenses is primarily related to an increase in payroll
expenses, medical expense, and lease operating expenses for new wells drilled
during the fiscal year.
Gas aggregation and pipeline costs increased $2.4 million. Gas
aggregation cost increased $1.2 million while pipeline cost also increased $1.2
million. The increase in gas aggregation and pipeline cost of sales is
attributable to the increase in average price paid offset by a decline in
production. The price increase corresponds with related indexes.
Taxes other than income increased $0.9 million as a result of increased
wellhead oil and gas sales.
Oil and gas related depreciation, depletion and amortization expenses
increased $1.2 million. The increase in depletion is primarily due to increased
production volumes and an increase in depletion rate.
Gain or loss on sale of property went from a loss of $0.4 million for the
year ended June 30, 2003 to a gain of $8.3 million for the year ended June 30,
2004. The primary reason for the gain in the current fiscal year was the sale
of the Company's membership interest in Breitburn Energy Company, LLC ("BEC")
for gross proceeds of $9.2 million. A gain of $7.4 million was recognized and a
liability of $1.8 million established as a reserve against items for which the
Company was required to indemnify the buyer for a period of 180 days after
closing pursuant to the agreement. The Company also sold acreage position
holdings for a gain of $0.6 million during the current fiscal year.
16
Exploration and impairment expenses decreased $0.9 million. The decrease
is a result of lower expenses primarily related to dry hole costs, impairment of
oil and gas property and various other geological and geophysical costs.
INTEREST EXPENSE. Interest expense decreased $1.3 million primarily due
------------------
to the reduction of outstanding debt and also replacing a portion of the
Company's debt at a lower interest rate for the year ended June 30, 2004.
INTEREST INCOME AND OTHER. Other non-operating income decreased $27.5
----------------------------
million when compared to the prior year. The decrease is primarily the result
of a decrease of $23.2 million associated with the gains recognized on the early
retirement of bonds and a $4.5 million gain on a legal settlement that occurred
in fiscal year 2003.
INCOME TAX. Income tax expense decreased by $10.8 million in 2004 to an
-----------
income tax benefit of $4.7 million as compared to an income tax expense in 2003
of $6.1 million. The decrease is primarily due to the adjustment of the tax
contingency balance of $4.5 million for items that are closed or no longer
applicable and the decrease in income before income taxes of $16.4 million.
COMPARISON OF RESULTS OF OPERATIONS FOR THE YEARS ENDED JUNE 30, 2003 AND 2002
- --------------------------------------------------------------------------------
The Company recorded net income of $9.8 million for the year ended June
30, 2003 compared to a net loss of $26.2 million in 2002. The improvement of
$36.0 million was primarily attributable to the net effect of a $31.3 million
increase in revenue, a $0.5 million increase in costs and expenses, a $3.3
million decrease in interest expense, a $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 Aggregation and Pipeline
Operating Margin (defined as gas aggregation and pipeline sales less gas
aggregation 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 $0.5 million for the prior period.
17
Production, aggregation and pipeline volumes, revenue and average sales
prices for the years ended June 30 and their related variances are as follows:
TWELVE MONTHS ENDED
JUNE 30 VARIANCE
---------------------- ------------------------
2003 2002 AMOUNT PERCENT
----------- --------- ----------- -----------
Natural Gas
Production (Mmcf) 9,756 9,941 (186) -1.9%
Average sales price received ($/Mcf) 5.13 2.86 2.27 79.1%
----------- --------- ----------- -----------
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%
=========== ========= =========== ===========
Aggregation Revenue
Volume (Million Mmbtu) 9,285 9,903 (618) -6.2%
Average sales price received ($/Mmbtu) 4.86 3.14 1.72 54.7%
----------- --------- ----------- -----------
Sales ($ in thousands) 45,145 31,125 14,020 45.0%
Pipeline Revenue
Volume (Million Mmbtu) 5,675 6,003 (328) -5.5%
Average sales price received ($/Mnbtu) 2.70 1.68 1.02 60.9%
----------- --------- ----------- -----------
Sales ($ in thousands) 15,338 10,084 5,254 52.1%
----------- --------- ----------- -----------
Total aggregation and pipeline sales ($ in thousands) 60,483 41,209 19,274 46.8%
=========== ========= =========== ===========
Aggregation Gas Cost
Volume (Million Mmbtu) 9,285 9,902 (617) -6.2%
Average price paid ($/Mmbtu) 4.48 2.98 1.50 50.4%
----------- --------- ----------- -----------
Cost ($ in thousands) 41,636 29,526 12,110 41.0%
Pipeline Gas Cost
Volume (Million Mmbtu) 4,550 4,870 (320) -6.6%
Average price paid ($/Mmbtu) 2.65 1.64 1.01 62.0%
----------- --------- ----------- -----------
Cost ($ in thousands) 12,057 7,963 4,094 51.4%
----------- --------- ----------- -----------
Total aggregation 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 aggregation and pipeline sales, a 0.1% increase in well
operations and service revenues and a 93.1% decrease in other operating revenue.
18
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 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 $4.95 and $3.65 for the years
ended June 30, 2003 and 2002, respectively.
Revenues from gas aggregation 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 aggregation revenue increased $14.0 million
while pipeline revenue, which has sale and transportation components, increased
$5.3 million. The increase in gas aggregation and pipeline sales is
attributable to the increase in average sales price received. The price
increase corresponds with related indexes.
Other operating revenue decreased $0.5 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 increased $0.5
--------------------
million or 0.5% 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 aggregation 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, a 57.6% decrease in exploration and
impairment costs, and a gain instead of a loss on sale of assets.
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 aggregation and pipeline costs increased $16.2 million. Gas
aggregation cost increased $12.1 million while pipeline costs increased $4.1
million. The increase in gas aggregation 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 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.
19
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.
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
before income taxes.
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):
2004 2003 2002
------- ------- -------
Development $ 7,892 $14,105 $10,977
Exploration 10,449 15,292 20,737
Acquisitions 72 5,879 717
------- ------- -------
Total $18,413 $35,276 $32,431
======= ======= =======
ACQUISITIONS
- ------------
The Company finalized the purchase of an additional 100-mile long natural
gas gathering system ("System 8000") from Columbia Gas Transmission for a
purchase price of $1.2 million during the first quarter of fiscal year 2005.
System 8000 is located in northeastern West Virginia and is situate among one of
the Company's existing operating areas.
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 and liquidity have improved since June
30, 2003. Stockholders' equity has decreased from $43.7 million at June 30,
2003 to $42.4 million at June 30, 2004. The Company's cash increased from $4.8
million at June 30, 2003 to $5.8 million at June 30, 2004. The Company's cash
at September 23, 2004 was $0.9 million. The change in cash during the year of
approximately $1.0 million resulted from various operating, investing and
financing activities of the
20
Company. The activities were primarily comprised of: the paydown of
approximately $3.1 million under the Company's $50 million revolving loan; the
net investment of approximately $22.0 million in property, plant and equipment;
payments of approximately $5.5 million for the purchase of a portion of the
Company's outstanding Notes; payments of approximately $3.0 million for the
acquisition of treasury stock and dividends; cash received of approximately
$10.8 million from the sale of assets; $1.5 million received from the collection
of a note receivable; receipt of approximately $0.3 million of cash in
connection with the Company's restricted Class A stock purchase plan for
employees; and approximately $22.0 million of cash provided by operations during
the year.
On June 15, 2004 the Company sold its membership interest in Breitburn
Energy Company, LLC ("BEC") for gross proceeds of $9.2 million. Pursuant to the
terms of its Senior Subordinated Notes (the "Notes"), the Company has the
option, within 360 days of receipt of the "Net Proceeds" (as defined in the
Indenture dated May 23, 1997 between the Company as Issuer and The Bank of New
York as Trustee, hereinafter the "Indenture") from the sale of the membership
interest in BEC, to apply such proceeds to (a) reduce debt senior to or pari
passu with the Notes (provided that in connection with the reduction of pari
passu debt, a pro rata portion of the Notes is redeemed); (b) acquire a
controlling interest in another business engaged in either natural gas
distribution or the exploration, development or operation of oil, gas or other
hydrocarbon properties (an "Energy Business"); (c) make capital expenditures in
respect of the Company's or its restricted subsidiaries' Energy Business; (d)
purchase long term assets that are used or useful in the Energy Business; or (e)
repurchase the Notes. If the Company has not applied all of the Net Proceeds in
accordance with one of the above options within 360 days of receipt of such
proceeds, then with respect to those Net Proceeds that were not applied to one
of the above options, such Net Proceeds are then deemed to constitute "Excess
Proceeds". To the extent the Excess Proceeds exceed $10 million, the Company
must make an offer to the holders of the Notes, (and holders of pari passu debt,
to the extent required by the terms of the pari passu debt) to repurchase the
maximum principal amount of the Notes and any pari passu debt that may be
purchased out of the Excess Proceeds at an offer price in cash equal to 100% of
the principal amount thereof, plus accrued and unpaid interest thereon to the
date of the purchase. The Company anticipates that the requirement to reinvest
the Net Proceeds will be met by its budgeted capital expenditures program for
the year ending June 30, 2005.
As previously reported, on July 10, 2002, the Company entered into a $50
million revolving Credit Agreement with Foothill Capital Corporation, now Wells
Fargo Foothill, Inc. ("Foothill"). The Company and Foothill have entered into
an Amended and Restated Credit Agreement dated June 10, 2004 (the "Restated
Credit Agreement"). The Restated Credit Agreement provides for the $50 million
revolving credit facility to be extended and for the Company to be provided with
additional credit in the form of a single advance term loan in the amount of $50
million. The term loan contains requirements for principal payments of $1
million each at July 10, 2005, 2006 and 2007, with the remaining balance due on
July 10, 2008. Depending on the Company's level of borrowing under the Restated
Credit Agreement, the applicable interest rates for base rate loans are based on
Wells Fargo's prime rate plus 0.25% to 0.75%. The Company has the ability under
the Restated Credit Agreement to designate certain loans as Libor Rate Loans at
interest rates based upon the rate at which dollar deposits are offered to major
banks in the London interbank market plus 2.25% to 2.75%. The Restated Credit
Agreement expires on July 10, 2008.
The obligations under the Restated Credit Agreement are secured by certain
of the existing proved producing oil and gas assets of the Company. The
Restated Credit 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.
At June 30, 2004, the Company's principal source of liquidity consisted of
$5.8 million of cash, $0.2 million available under an unsecured credit facility
currently in place, plus amounts available under
21
both the term loan and revolving loan of the Restated Credit Agreement. At June
30, 2004, $1.0 million was outstanding and $1.8 million was committed through
letters of credit under the short-term credit facility and $36.1 million was
outstanding on the revolving loan under the Restated Credit Agreement. There
were no amounts outstanding on the $50 million term loan available under the
Restated Credit Agreement.
As previously reported, the Company had been in litigation with certain
Holders (the "Noteholders") of its Notes. The dispute involved the calculation
of "Net Proceeds" of an "Asset Sale" as defined in the Indenture. A settlement
agreement dated February 24, 2004, was negotiated with the Noteholders to
resolve the dispute. In settlement of the dispute the Company agreed to
repurchase $38 million in Notes. The repurchase was effected by the Company
making Asset Sale Offers (as defined in the Indenture) totaling $38 million.
The Company made an initial Asset Sale Offer of $4 million, which was completed
on March 25, 2004. The Company consummated another Asset Sale Offer of $34
million which was completed on July 29, 2004. The United States District
Court for the Southern District of West Virginia has entered a Dismissal Order
dismissing the litigation with prejudice. Upon the Company meeting all of the
terms and conditions of the Settlement Agreement it funded the $50 million term
loan under the Restated Credit Agreement.
As of September 23, 2004, there are $50 million in outstanding borrowings
under the term loan and $15 million in outstanding borrowings under the
revolving loan. Additional borrowings must comply with the terms of the
Indenture and the Foothill Amended and Restated Credit Agreement.
The Company's net cash requirements will fluctuate based on timing and the
extent of the interplay of capital expenditures, cash generated by 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
2004 was $42.4 million. EBITDAX for fiscal years 2003 and 2002, measured on a
similar basis, was $36.9 million and $19.7 million, respectively. Management
anticipates that EBITDAX from oil and gas operations for fiscal year 2005 will
approximate $44 million. The Company's ability to achieve EBITDAX of $44
million from oil and gas operations for fiscal year 2005 is highly dependant on
product price and continued drilling success. Management believes that cash
generated from oil and gas operations, together with the liquidity provided by
existing cash balances and permitted borrowings, will be sufficient to satisfy
commitments for budgeted capital expenditures of $29.8 million, 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, permitted
borrowings and its expected fiscal year 2005 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 and the Restated Credit Agreement.
However, since future results of operations, cash flow from operating
activities, debt service capability, levels and availability of capital
resources and continuing liquidity are dependent on future weather patterns, oil
and gas commodity prices and production volume levels, future exploration and
development drilling success and successful acquisition transactions, no
assurance can be given that the Company will remain in compliance with the
requirements of its Notes and the Restated Credit Agreement.
22
In addition to the Restated Credit Agreement, unsecured credit facility
and Notes discussed above, the Company had various other obligations. The
following table lists the Company's contractual obligations at June 30, 2004 (in
thousands):
Payments due by period (in thousands)
More
Less than 1 - 3 3 - 5 than 5
1 year years years years Total
---------- ------- ------- ------- ---------
Senior subordinated notes (a) $ 34,000 $92,033 $ - $ - $ 126,033
Revolving loan 1,000 - 36,109 - 37,109
Installment notes payable 145 224 127 401 897
Mandatorily redeemable stock 202 479 702 - 1,383
Operating leases 1,131 883 677 543 3,234
---------- ------- ------- ------- ---------
Total contractual cash
obligations $ 36,478 $93,619 $37,615 $ 944 $ 168,656
========== ======= ======= ======= =========
(a) The Company met its' current obligation through the Asset Sale Offer for
$34 million of its Senior Subordinated Notes which was consummated on July 29,
2004.
RECENT ACCOUNTING PRONOUNCEMENTS
- ----------------------------------
In March 2004, the Emerging Issues Task Force ("EITF") reached a consensus
that mineral rights, as defined in EITF Issue No. 04-2, "Whether Mineral Rights
Are Tangible or Intangible Assets," are tangible assets and that they should be
removed as examples of intangible assets in SFAS No. 141, "Business
Combinations" and No. 142, "Goodwill and Other Intangible Assets." The FASB has
recently ratified this consensus and directed the FASB staff to amend SFAS Nos.
141 and 142 through the issuance of FASB Staff Position ("FSP") FAS Nos. 141-1
and 142-1. In addition, proposed FSP 142-b confirms that SFAS 142 does not
change the balance sheet classification or disclosures of mineral rights of oil
and gas producing enterprises. Historically, the Company has included the costs
of such mineral rights as tangible assets, which is consistent with the EITF's
consensus. As such, EITF 04-02 and the related FSPs have not affected the
Company's consolidated financial statements.
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 requires instruments that fall within the scope
of this pronouncement to be classified as liabilities. The Company early
adopted SFAS No. 150 at the beginning of the fourth quarter of the year ended
June 30, 2004. The effect of this adoption was an increase to other current
liabilities of $0.2 million, other long term obligations of $1.2 million and a
$1.4 million decrease in stockholders' equity.
23
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES
-------------------------------------------------
ABOUT MARKET RISK
-----------------
COMMODITY RISK
- ----------------
The Company's operations consist primarily of exploring for, producing,
aggregating and selling natural gas and oil. Contracts to deliver gas at
pre-established prices mitigate the risk to the Company of falling prices but at
the same time limit the Company's ability to benefit from the effects of rising
prices. The Company occasionally uses derivative instruments to hedge its
commodity price risk. The Company hedges a portion of its projected natural gas
production through a variety of financial and physical arrangements intended to
support natural gas prices at targeted levels and to manage its exposure to
price fluctuations. The Company may use futures contracts, swaps, options and
fixed price physical contracts to hedge its commodity prices. Realized gains
and losses from the Company's price risk management activities are recognized in
oil and gas sales when the associated production occurs. Unrecognized gains and
losses are included as a component of other comprehensive income. See Note 4 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 approximately 45% to
50% of its estimated natural gas production for the fiscal year ended June 2005.
As of June 30, 2004, 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 2004 - December 2004 NYMEX 25,000 $ 5.20 $ (34,727)
December 2004 - February 2005 NYMEX 300,000 6.12 183,667
July 2004 - March 2005 NYMEX 1,080,000 5.57 915,180
July 2004 - March 2005 NYMEX 810,000 5.61 654,857
July 2004 - June 2005 NYMEX 2,160,000 4.54 5,549,623
---------- ----------------
Unrealized Losses 4,375,000 $ 7,268,600
---------- ================
Physical Contracts
Fixed Price Delivery Contracts
July 2004 - October 2004 338,250 $ 4.85
----------
Total Hedged Production 4,713,250
==========
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 2004 levels, a 10%
change in the average unhedged prices realized during the year would change the
Company's gas and oil revenues by approximately $0.8 million on an annual basis.
24
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, 2004, all but $36.9 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, 2004 level, a 10% change in rates would have a $0.2 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 the
period. Gains and losses resulting from foreign currency translation are
included as a component of other comprehensive income.
* * * * *
25
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
-----------------------------------------------------
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
- --------------------------------------------------------------
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 (the "Company") as of June 30, 2004 and
2003, and the related consolidated statements of operations, stockholders'
equity, cash flows and comprehensive income (loss) for each of the three years
in the period ended June 30, 2004. 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 standards of the Public Company
Accounting Oversight Board (United States). 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 the Company as of June 30, 2004
and 2003 and the results of their operations and their cash flows for each of
the three years ended June 30, 2004 in conformity with accounting principles
generally accepted in the United States of America.
As discussed in Note 2 to the consolidated financial statements, in 2003
the Company adopted Statement of Financial Accounting Standards No. 143,
"Accounting for Asset Retirement Obligations" and in 2004 adopted Statement of
Financial Accounting Standards No. 150, "Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity".
DELOITTE & TOUCHE LLP
Denver, Colorado
September 27, 2004
26
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF JUNE 30
(AMOUNTS IN THOUSANDS)
- ----------------------------------------------------------------------------
ASSETS 2004 2003
------------ ------------
CURRENT ASSETS:
Cash and cash equivalents $ 5,821 $ 4,831
Accounts receivable:
Oil and gas sales 8,632 10,380
Gas aggregation and pipeline 9,079 9,458
Other 4,000 4,616
------------ ------------
Accounts receivable 21,711 24,454
Less allowance for doubtful accounts (1,022) (1,616)
------------ ------------
Accounts receivable, net of allowance 20,689 22,838
Deferred income tax asset 2,087 41
Deferred taxes - other comprehensive loss 2,889 787
Notes receivable, related party 59 1,609
Prepaid and other current assets 4,141 1,410
------------ ------------
Total current assets 35,686 31,516
NET PROPERTY, PLANT AND EQUIPMENT (Note 2) 246,391 253,270
------------ ------------
OTHER ASSETS:
Deferred financing costs, less accumulated
amortization of $6,833 and $5,751 2,015 3,098
Notes receivable, related party 113 146
Other 6,007 7,804
------------ ------------
Total other assets 8,135 11,048
------------ ------------
TOTAL $ 290,212 $ 295,834
============ ============
See notes to consolidated financial statements. (Continued)
27
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF JUNE 30
(AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
- -------------------------------------------------------------------------------------------
LIABILITIES AND STOCKHOLDERS' EQUITY 2004 2003
------------ ------------
CURRENT LIABILITIES:
Accounts payable and accrued expenses $ 14,823 $ 13,734
Current portion of long-term debt 1,145 133
Funds held for future distribution 16,701 17,217
Income taxes payable 128 1,484
Accrued taxes, other than income 9,289 9,643
Derivatives 7,303 810
Other current liabilities 3,562 1,421
------------ ------------
Total current liabilities 52,951 44,442
LONG-TERM OBLIGATIONS:
Long-term debt 162,894 173,197
Deferred trust revenue 2,511 2,917
Deferred income tax liability 19,552 20,376
Derivatives - 1,319
Other long-term obligations 8,447 8,311
------------ ------------
Total liabilities 246,355 250,562
Minority Interest 1,495 1,594
COMMITMENTS AND CONTINGENCIES (Note 14)
STOCKHOLDERS' EQUITY:
Common stock, par value $1.00; 2,000 shares authorized;
730 shares issued and outstanding 730 730
Class A non-voting common stock, no par value; 100
shares authorized; 68 and 46 shares issued and outstanding 8,027 5,092
Additional paid-in capital 5,503 5,503
Retained earnings 48,200 45,150
Treasury stock and notes receivable arising from
issuance of common stock (14,954) (11,824)
Deferred compensation on restricted stock (1,887) -
Accumulated other comprehensive loss (3,257) (973)
------------ ------------
Total stockholders' equity 42,362 43,678
------------ ------------
TOTAL $ 290,212 $ 295,834
============ ============
See notes to consolidated financial statements.
28
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED JUNE 30
(AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
- ------------------------------------------------------------------------------------------------------------------
2004 2003 2002
----------- ----------- -----------
REVENUES:
Oil and gas sales $ 57,203 $ 51,410 $ 38,939
Gas aggregation and pipeline sales 60,819 60,483 41,209
Well operations and service revenues 5,229 5,498 5,490
Other 122 35 504
----------- ----------- -----------
123,373 117,426 86,142
----------- ----------- -----------
COSTS AND EXPENSES:
Field operating expenses 11,452 10,128 10,916
Gas aggregation and pipeline cost of sales 56,059 53,693 37,489
General and administrative 15,573 15,437 17,360
Taxes, other than income 4,170 3,287 2,175
Depletion and depreciation of oil and gas properties 13,300 12,140 12,362
Depreciation of pipelines, other property and equipment 4,190 4,294 2,934
Exploration and impairment 10,796 11,729 27,694
(Gain) loss on sale of assets (8,289) 433 (319)
----------- ----------- -----------
107,251 111,141 110,611
----------- ----------- -----------
Income (loss) from operations 16,122 6,285 (24,469)
----------- ----------- -----------
OTHER (INCOME) AND EXPENSE:
Interest expense 15,069 16,383 19,671
Interest income and other 1,656 (25,848) (1,135)
----------- ----------- -----------
16,725 (9,465) 18,536
----------- ----------- -----------
Income (loss) before income taxes and minority interest (603) 15,750 (43,005)
Income tax expense (benefit) (4,722) 6,073 (16,822)
----------- ----------- -----------
Income (loss) before minority interest 4,119 9,677 (26,183)
Minority interest 176 240 3
----------- ----------- -----------
Income (loss) before cumulative effect of change in accounting principle: 4,295 9,917 (26,180)
Change in accounting principle, net of tax - (73) -
----------- ----------- -----------
NET INCOME (LOSS) $ 4,295 $ 9,844 $ (26,180)
=========== =========== ===========
Earnings (loss) per common share, basic:
Income (loss) before change in accounting principle $ 6.62 $ 15.23 $ (39.80)
Change in accounting principle, net of tax - (0.11) -
----------- ----------- -----------
Basic earnings (loss) per common share $ 6.62 $ 15.12 $ (39.80)
========== ============ ===========
Earnings (loss) per common share, diluted:
Income (loss) before change in accounting principle $ 6.52 $ 14.90 $ (39.80)
Change in accounting principle, net of tax - (0.11) -
----------- ----------- -----------
Diluted earnings (loss) per common share $ 6.52 $ 14.79 $ (39.80)
========== ============ ===========
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)
- ------------------------------------------------------------------------------------------------------------------------------
Notes
Class A Restricted Additional Received/
Common Common Class A Paid-In Retained Treasury Issuance of
Stock Stock Stock Capital Earnings Stock Stock
------- -------- ------------ ----------- ---------- ---------- -------------
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 stock - common (854)
Purchase of stock - Class A (639)
Reduction of notes receivable 95
------- -------- ------------ ----------- ---------- ---------- -------------
Balance, June 30, 2003 $ 730 $ 5,092 $ - $ 5,503 $ 45,150 $ (11,530) $ (294)
======= ======== ============ =========== ========== ========== =============
Comprehensive income (loss) 4,295
Dividends (1,245)
Issuance of stock - Class A 554 2,410
Restricted stock amortization
Purchase of stock - common (1,473)
Purchase of stock - Class A (29) (336)
Shares subject to mandatory redemption
upon adoption of SFAS No. 150 (1,383)
Reduction of notes receivable 62
------- -------- ------------ ----------- ---------- ---------- -------------
Balance, June 30, 2004 $ 730 $ 5,646 $ 2,381 $ 5,503 $ 48,200 $ (14,722) $ (232)
======= ======== ============ =========== ========== ========== =============
Accum. Other Total
Deferred Comprehensive Stockholders'
Compensation Income (Loss) Equity
-------------- --------------- ---------------
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 stock - common (854)
Purchase of stock - Class A (639)
Reduction of notes receivable 95
-------------- --------------- ---------------
Balance, June 30, 2003 $ - $ (973) $ 43,678
============== =============== ===============
Comprehensive income (loss) (2,284) 2,011
Dividends (1,245)
Issuance of stock - Class A (2,133) 831
Restricted stock amortization 246 246
Purchase of stock - common (1,473)
Purchase of stock - Class A (365)
Shares subject to mandatory redemption
upon adoption of SFAS No. 150 (1,383)
Reduction of notes receivable 62
-------------- --------------- ---------------
Balance, June 30, 2004 $ (1,887) $ (3,257) $ 42,362
============== =============== ===============
30
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED JUNE 30
(AMOUNTS IN THOUSANDS)
- -----------------------------------------------------------------------------------------------------------
2004 2003 2002
--------- --------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ 4,295 $ 9,844 $(26,180)
Adjustments to reconcile net income (loss) to net cash provided (used) by
operating activities:
Depletion, depreciation and amortization 17,490 16,434 16,031
(Gain) loss on sale of assets (8,289) 433 (319)
Gain on redemption of senior bonds (513) (23,672) -
Deferred income taxes (2,870) 12,685 (12,492)
Exploration and impairment 10,730 11,508 27,227
Other, net 481 2,636 2,322
--------- --------- ---------
21,324 29,868 6,589
Changes in assets and liabilities:
Accounts receivable 2,149 (4,817) 3,187
Income taxes receivable - - (2,066)
Income taxes payable (1,357) 3,081 -
Prepaid and other assets (165) (1,560) (1,030)
Accounts payable and accrued expenses 521 (627) (2,218)
Funds held for future distributions (516) 5,803 (3,253)
Other 52 (8,522) (23,405)
--------- --------- ---------
Net cash provided (used) by operating activities 22,008 23,226 (22,196)
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment (21,910) (37,632) (38,294)
Proceeds from sale of assets 10,844 3,532 704
Notes receivable and other 1,560 1,259 86
--------- --------- ---------
Net cash used by investing activities from operations (9,506) (32,841) (37,504)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt 67,281 72,635 -
Principal payment on long-term debt (76,005) (73,434) (145)
Proceeds from issuance of stock 257 - -
Purchase of treasury stock and other financing activities (1,811) (1,447) (1,663)
Dividends paid (1,234) (1,083) (1,053)
--------- --------- ---------
Net cash used by financing activities from operations (11,512) (3,329) (2,861)
--------- --------- ---------
Net (decrease) increase in cash and cash equivalents 990 (12,944) (62,561)
Cash and cash equivalents, beginning of period 4,831 17,775 80,336
--------- --------- ---------
Cash and cash equivalents, end of period $ 5,821 $ 4,831 $ 17,775
========= ========= =========
See notes to consolidated financial statements.
31
ENERGY CORPORATION OF AMERICA
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
FOR THE YEARS ENDED JUNE 30
(AMOUNTS IN THOUSANDS)
- -------------------------------------------------------------------------------
2004 2003 2002
-------- -------- ---------
Net income (loss) $ 4,295 $ 9,844 $(26,180)
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustment:
Current period change 755 854 1,627
Marketable securities:
Unrealized loss - (5) (102)
Reclassification to earnings - (25) (4)
Oil and gas derivatives:
Net cumulative effect adjustment - - -
Current period transactions (2,775) (2,351) 1,999
Reclassification to earnings (264) 731 (4,198)
-------- -------- ---------
Other comprehensive loss, net of tax (2,284) (796) (678)
-------- -------- ---------
Comprehensive income (loss) $ 2,011 $ 9,048 $(26,858)
======== ======== =========
See notes to consolidated financial statements.
32
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED JUNE 30, 2004, 2003 AND 2002
- --------------------------------------------------------------------------------
1. NATURE OF ORGANIZATION
Energy Corporation of America (the "Company") was formed in June 1993
through an exchange of shares with the common stockholders of Eastern
American Energy Corporation ("Eastern American"). The Company is an
independent energy company. All references to the "Company" include Energy
Corporation of America and its consolidated subsidiaries. The Company's
industry segments are discussed at Note 16.
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 and its subsidiaries. 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
significant intercompany transactions have been eliminated in
consolidation.
Cash and Cash Equivalents - Cash and cash equivalents include short-term
----------------------------
investments maturing in three months or less from the date acquired.
Property, Plant and Equipment - Oil and gas properties are accounted for
--------------------------------
using the successful efforts method of accounting. Under this method,
certain expenditures such as exploratory geological and geophysical costs,
exploratory dry hole costs, delay rentals and other costs related to
exploration are recognized currently as expenses. All direct and certain
indirect costs relating to property acquisition, successful exploratory
wells, development costs, and support equipment and facilities are
capitalized. The Company computes depletion, depreciation and amortization
of capitalized oil and gas property costs on the units-of-production method
using proved developed reserves. Direct production costs, production
overhead and other costs are charged against income as incurred. Gains and
losses on the sale of oil and gas property interests are generally
recognized in income.
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.
33
At June 30 property, plant and equipment consisted of the following (in
thousands):
2004 2003
---------- ----------
Oil and gas properties $ 345,556 $ 337,904
Pipelines 21,856 20,594
Other property and equipment 22,825 23,537
---------- ----------
390,237 382,035
Less accumulated depletion, depreciation and amortization (143,846) (128,765)
---------- ----------
Net property, plant and equipment $ 246,391 $ 253,270
========== ==========
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, 2004, the impairment recognized by the Company primarily
consists of oil and gas property of $2.4 million and other property of $1.1
million. The other property is primarily related to the sale of an interest
in a drilling rig held with Breitburn Energy Company L.P. ("BECLP") and is
discussed further in Note 10. During the fiscal year ended June 30, 2003
the Company recognized impairment of oil and gas property of $3.1 million.
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.
Deferred Trust Revenue- In 1993, the Company sold working interests in
------------------------
certain Appalachian gas properties in connection with the formation of the
Eastern American Natural Gas Trust ("the Royalty Trust"). A portion of the
proceeds from the sale of these interests, representing term net profits
interest, was accounted for as a production payment and was classified as
deferred trust revenue. The deferred revenue is recognized as production
occurs for the term properties.
Revenues and Gas Costs - Oil and gas sales, and aggregation and pipeline
-------------------------
revenues are recognized as income when the oil or gas is produced and sold.
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. 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". Stock
34
compensation expense of $0.5 million and $0.9 million was recognized in
June 30, 2004 and June 30, 2002, respectively, with no expense recorded for
the year ended June 30, 2003.
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 - In accordance with SFAS No. 133, "Accounting for Derivative
-----------
Instruments and Hedging Activities", as amended, all derivative instruments
are recorded as assets or liabilities in the Company's balance sheet and
measurement of those instruments at its' estimated 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 and any derivatives not
qualifying as hedges are recognized immediately in earnings.
Accumulated Other Comprehensive Loss- At June 30 accumulated other
---------------------------------------
comprehensive loss consisted of the following (in thousands):
2004 2003
-------- --------
Foreign currency translation $ 1,122 $ 367
Natural gas hedging (4,379) (1,340)
-------- --------
Accumulated other comprehensive loss $(3,257) $ (973)
======== ========
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, 2004,
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.
35
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 - In March 2004, the Emerging Issues Task
---------------------------------
Force ("EITF") reached a consensus that mineral rights, as defined in EITF
Issue No. 04-2, "Whether Mineral Rights Are Tangible or Intangible Assets,"
are tangible assets and that they should be removed as examples of
intangible assets in SFAS No. 141, "Business Combinations" and No. 142,
"Goodwill and Other Intangible Assets." The FASB has recently ratified this
consensus and directed the FASB staff to amend SFAS Nos. 141 and 142
through the issuance of FASB Staff Position ("FSP") FAS Nos. 141-1 and
142-1. In addition, proposed FSP 142-b confirms that SFAS 142 does not
change the balance sheet classification or disclosures of mineral rights of
oil and gas producing enterprises. Historically, the Company has included
the costs of such mineral rights as tangible assets, which is consistent
with the EITF's consensus. As such, EITF 04-02 and the related FSPs have
not affected the Company's consolidated financial statements.
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 requires instruments
that fall within the scope of this pronouncement to be classified as
liabilities. The Company early adopted SFAS No. 150 at the beginning of the
fourth quarter of the year ended June 30, 2004. The effect of this adoption
was an increase to other current liabilities of $0.2 million, other long
term obligations of $1.2 million and a $1.4 million decrease in
stockholders' equity.
Asset Retirement Obligations - The Company accounts for its' asset
------------------------------
retirement obligations according to 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.
36
The following table presents a reconciliation of the beginning and ending
carrying amounts of the asset retirement obligations.
(IN THOUSANDS)
2004 2003
------ ------
Asset retirement obligation as of the beginning of the year $ 724 $ 471
Accretion expense 44 33
Liabilities incurred 22 181
Liabilities settled (175) (86)
Change in estimate 58 125
------ ------
Asset retirement obligation as of the end of the year $ 673 $ 724
====== ======
Supplemental Disclosures of Cash Flow Information - Supplemental cash flow
--------------------------------------------------
information for the years ended June 30 is as follows (in thousands):
2004 2003
-------- --------
Cash paid for:
Interest $15,069 $16,383
Income taxes 25 15
Income taxes refunded (38) (9,809)
Noncash investing and financing activities:
Dividends declared and unpaid at year end 308 297
3. ACQUISITIONS
The Company finalized the purchase of an additional 100-mile long natural
gas gathering system ("System 8000") from Columbia Gas Transmission for a
purchase price of $1.2 million during the first quarter of fiscal year
2005. System 8000 is located in northeastern West Virginia and is situate
among one of the Company's existing operating areas.
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. 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 exposure to commodity price risk under existing sales or
purchase commitments. All of the Company's price swap agreements in place
at June 30, 2004 are designated as cash flow hedges. At June 30, 2004, the
Company had swap agreements maturing from July 2004 through June 2005
covering 4,375,000 Mmbtu. At June 30, 2004, the
37
Company had recorded a $4.4 million loss in accumulated other comprehensive
income, $0.03 million of short term derivative assets, $7.3 million in
short term derivative liabilities and $2.9 million in deferred tax asset.
At June 30, 2003, the Company had swap agreements maturing from July 2003
through June 2005 covering 5,058,000 Mmbtu. As of June 30, 2003 the Company
had recorded a $1.3 million loss in accumulated other comprehensive income,
$0.8 million in 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, 2004 the Company recognized a net loss in
revenues on its natural gas hedging activities of $0.4 million. 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 and a net gain of $6.7
million for the year ended June 30, 2002. 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
$4.4 million.
5. DEBT
Long-Term Debt - At June 30 long-term debt consisted of the following (in
---------------
thousands):
2004 2003
--------- ---------
ECA senior subordinated notes, interest at 9.5% payable
semi-annually, due May 15, 2007 $126,033 $132,073
Revolving credit agreements, variable rates 37,109 40,227
Installment notes payable, at imputed interest rates ranging from
from 8.0% to 9.5% 897 1,030
--------- ---------
164,039 173,330
Less current portion (1,145) (133)
--------- ---------
$162,894 $173,197
========= =========
Scheduled maturities of the Company's long-term debt at June 30, 2004 for
each of the next five years and thereafter are as follows (in thousands):
2005 $ 35,213
2006 213
2007 92,142
2008 100
2009 36,209
Thereafter 484
--------
Total payments 164,361
Less: imputed interest 322
--------
Present value of scheduled maturities $164,039
========
Senior Subordinated Notes -The Company has 9 1/2 % Senior Subordinated
---------------------------
Notes ("Notes") that are due May 15, 2007. The agreement contains certain
restrictions and conditions among which are limitations on indebtedness,
dividends and investments, and certain interest coverage ratio
requirements.
38
The Company purchased $6.04 million of its Notes during the twelve months
ended June 30, 2004, $2.04 million in privately negotiated transactions and
$4.0 million pursuant to an Asset Sale Offer as defined in the Indenture
for the Notes that resulted in a gain of $0.5 million which was included in
interest income and other.
The Company purchased $34 million of the Notes on July 29, 2004 pursuant to
an Asset Sale Offer as defined in the Indenture for the Notes. The Company
classified this debt as long term at June 30, 2004 as a result of entering
into an amended and restated credit agreement in place that allowed the
Company to refinance the debt on a long term basis. See Note 18 for further
discussion.
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 which was
included in interest income and other.
Revolving Credit and Term Loan -As previously reported, on July 10, 2002,
--------------------------------
the Company entered into a $50 million revolving Credit Agreement with
Foothill Capital Corporation, now Wells Fargo Foothill, Inc. ("Foothill").
The Company and Foothill have entered into an Amended and Restated Credit
Agreement dated June 10, 2004 (the "Restated Credit Agreement"). The
Restated Credit Agreement provides for the $50 million revolving credit
facility to be extended and for the Company to be provided with additional
credit in the form of a single advance term loan in the amount of $50
million. The term loan contains requirements for principal payments of $1
million each at July 10, 2005, 2006 and 2007, with the remaining balance
due on July 10, 2008. Depending on the Company's level of borrowing under
the Restated Credit Agreement, the applicable interest rates for base rate
loans are based on Wells Fargo's prime rate plus 0.25% to 0.75%. The
Company has the ability under the Restated Credit Agreement to designate
certain loans as Libor Rate Loans at interest rates based upon the rate at
which dollar deposits are offered to major banks in the London interbank
market plus 2.25% to 2.75%. The Restated Credit Agreement expires on July
10, 2008.
The obligations under the Restated Credit Agreement are secured by certain
of the existing proved producing oil and gas assets of the Company. The
Restated Credit 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. As of September 23, 2004, there
are $50.0 million in outstanding borrowings under the term loan and $15
million in outstanding borrowings under the revolving loan.
Other Credit Facilities - The Company has an unsecured revolving line of
-------------------------
credit totaling $3.0 million with a financial institution with an interest
rate of prime plus 0.25%, which reduces by $1.0 million in November 2004
and expires on June 30, 2005. As of June 30, 2004, there was $1.0 million
outstanding under the line of credit and $1.8 million was committed through
letters of credit. As of June 30, 2003, there was $1.0 million outstanding
under the line of credit.
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, 2004 and
2003, the balance due was $1.0 million and $1.1 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, 2004 and 2003, the balance due to the seller was $0.2
and $0.3 million respectively.
39
6. INCOME TAXES
The following table summarizes components of the Company's provision
(benefit) for income taxes for the years ended June 30 (in thousands):
2004 2003 2002
-------- -------- ---------
Current:
Federal $(1,523) $(6,610) $ (3,436)
State (329) (2) 1,385
-------- -------- ---------
Total current (1,852) (6,612) (2,051)
-------- -------- ---------
Deferred:
Federal (2,116) 11,502 (13,381)
State (754) 1,183 (1,390)
-------- -------- ---------
Total deferred (2,870) 12,685 (14,771)
-------- -------- ---------
Total provision (benefit) for income taxes $(4,722) $ 6,073 $(16,822)
======== ======== =========
A reconciliation of the provision for income taxes computed at the
statutory rate to the provision for income taxes as shown in the consolidated
statements of operations for the years ended June 30 is summarized below (in
thousands):
2004 2003 2002
-------- ------- ---------
Tax provision (benefit) at the federal statutory rate $ (150) $5,513 $(15,051)
State taxes, net of federal tax effects (25) 663 (2,516)
Effect of rate change - 12 103
Change in valuation allowance on federal, foreign
and state deferred tax assets, net of federal effect - - (2,048)
Change in tax contingency (4,514) - -
Other, net (33) (115) 2,690
-------- ------- ---------
Total provision (benefit) for income taxes $(4,722) $6,073 $(16,822)
======== ======= =========
40
Components of the Company's deferred tax assets and liabilities, as of June 30
are as follows (in thousands):
2004 2003
--------- ---------
Deferred tax assets:
Royalty Trust agreements $ 4,087 $ 4,640
Tax credits and carryforwards 7,236 7,795
Other 3,294 2,512
--------- ---------
Total deferred tax assets 14,617 14,947
--------- ---------
Deferred tax liabilities:
Property, plant and equipment (31,770) (28,920)
Other liabilities (312) (6,362)
--------- ---------
Total deferred tax liabilities (32,082) (35,282)
--------- ---------
Net deferred tax liability $(17,465) $(20,335)
========= =========
Current deferred tax asset $ 2,087 $ 41
Long-term deferred tax liability (19,552) (20,376)
--------- ---------
Net deferred tax liability $(17,465) $(20,335)
========= =========
At June 30 the Company has the following federal and state tax credits and
carryforwards (in thousands):
2004 2003
Year of Year of
Amount Expiration Amount Expiration
------- ---------- ------- ----------
AMT tax credits $ 3,591 None $ 4,444 None
Charitable contribution carryforwards 166 2007-2008 3 2007-2008
------- -------
Total federal credits and carryforwards $ 3,757 $ 4,447
======= =======
State net operating loss carryforwards $ 3,479 2005-2022 $ 3,348 2005-2022
------- -------
Total state carryforwards $ 3,479 $ 3,348
======= =======
Total federal and state carryforwards $ 7,236 $ 7,795
======= =======
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, 2003 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 2004, the Company utilized $0.9 million in AMT Credits. The $3.6
million in remaining AMT credits may be utilized in future periods.
41
In March 2004, the U.S. Internal Revenue Service ("IRS") notified the
Company that it was initiating an audit of the Company's federal income tax
return for the tax year ending June 30, 2002. The IRS is also reviewing the
refund claim filed by the Company due to the amended federal income tax
return for the tax year ending June 30, 1999. The Company has not received
any notices of proposed adjustments and believes that it has adequately
provided for any potential tax liability that may be assessed by the IRS.
In connection with the evaluation of contingencies, the Company continues
to perform periodic reviews. During 2004, the Company adjusted the
contingency balance for items that are closed or no longer applicable.
7. EMPLOYEE BENEFIT PLANS
The Company and certain subsidiaries, have a Profit Sharing/Incentive Stock
Plan (the "Plan") for the stated purpose of expanding and improving profits
and prosperity and to assist the Company in attracting and retaining key
personnel. The Plan is noncontributory, and its continuance from year to
year is at the discretion of the Board of Directors. The annual profit
sharing pool is based on calculations set forth in the Plan. 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 $1.7 million and $2.4 million of profit sharing expense during
the years ended June 30, 2004 and 2003, respectively, while no profit
sharing expense was recognized for the year ended June 30, 2002.
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 $0.29 million, $0.27 million and $0.25 million
for the years ended June 30, 2004, 2003, and 2002.
8. CAPITAL STOCK
Voting Common Stock- In May 1995, the Company was reincorporated in the
---------------------
State of West Virginia. As part of this reincorporation, each outstanding
share of then existing no-par value common stock was converted to one share
of $1 par value common stock.
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. The Company entered into a
repurchase agreement on January 21, 2004 with the KWB Trust to define the
purchase price and establish the conditions for the repurchase of stock
owned by the Kenneth W. Brill, estate. The agreement outlines the
repurchase of 49,110 shares of stock by the Company or through third
parties, at an anticipated value of approximately $3.7 million over the
next five years, and provides for payments in twenty quarterly installments
on the majority of the shares to be repurchased. The repurchase of shares
is subject to certain restrictions in the Company's credit agreements. On
June 30, 2004, the Company's remaining repurchase obligation under the
Agreement is approximately $2.9 million. Upon adoption of SFAS No. 150, as
described in Note 2, $1.4 million of the obligation was reclassified as a
liability and the remaining $1.5 million is included in stockholders'
equity as third parties have agreed to purchase such amount.
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.
During October, 2003, ECA offered its employees that were participants in
the 2003 Profit Sharing program, the opportunity to purchase Class A stock
42
having certain restrictions. Employees were awarded the right to purchase a
specified number of shares, with the restrictions expiring over a specified
period of time. As a result of this program, 16,850 shares of restricted
stock were issued for $15 per share vesting over five years. Deferred
compensation was recognized based on the fair value of the stock at
issuance and is being amortized over the vesting period. The Company
repurchased 201 shares of the restricted stock during the year ended June
30, 2004.
Treasury Stock - At June 30, 2004, the Company had 126,613 shares of voting
--------------
common stock in treasury, carried at cost. The Company purchased 15,367 and
6,262 shares of voting common stock during the years ended June 30, 2004
and 2003, respectively. At June 30, 2004, the Company had 21,202 shares of
non-voting Class A stock in treasury, carried at cost. The Company
purchased 2,349 and 4,473 shares of non-voting Class A stock during the
years ended June 30, 2004 and 2003.
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, 2000 to December 31, 2004 10,002
January 1, 2001 to December 31, 2005 9,996
---------
19,998
=========
No options were exercised for either of the years ended June 30, 2004 or
2003. Therefore, as of June 30, 2004, all the remaining options were
exercisable. Fair value of the options at the grant dates, as estimated by
management, was nominal.
9. EARNINGS PER SHARE
In accordance with SFAS No. 128, "Earnings Per Share," basic earnings per
share has been computed based upon the weighted average shares outstanding.
Diluted earnings per share gives effect to outstanding stock options.
43
A reconciliation of the components of basic and diluted net income (loss) per
common share for the years ended June 30 is as follows:
2004 2003 2002
-------- --------- ---------
Income (loss) before cumulative effect of
change in accounting principle $ 4,295 $ 9,917 $(26,180)
Change in accounting principle, net of tax - (73) -
------------------------------
Net income (loss) $ 4,295 $ 9,844 $(26,180)
- ----------------------------------------------------------------------------
Weighted average common shares:
Basic 648,835 651,205 657,707
Diluted 658,345 665,471 657,707
- ----------------------------------------------------------------------------
Basic net income (loss) per common share:
Income (loss) from operations before
extraordinary items $ 6.62 $ 15.23 $ (39.80)
Change in accounting principle, net of tax - (0.11) -
- ----------------------------------------------------------------------------
Basic net income (loss) per common share $ 6.62 $ 15.12 $ (39.80)
- ----------------------------------------------------------------------------
Diluted net income (loss) per common share:
Income (loss) from operations before
extraordinary items $ 6.52 $ 14.90 $ (39.80)
Change in accounting principle, net of tax - (0.11) -
- ----------------------------------------------------------------------------
Diluted net income (loss) per common share $ 6.52 $ 14.79 $ (39.80)
- ----------------------------------------------------------------------------
For fiscal year 2002 the effect of 14,226 shares related to outstanding
stock options were not included in the computation of diluted net loss per
share because to do so would have been antidilutive
10. UNCONSOLIDATED AFFILIATE
The Company owned a 25.35% members' interest in Breitburn Energy Company,
LLC ("BEC"). The Company's investment in BEC was accounted for under the
equity method. Although BEC had current year earnings, the Company's share
of net losses since inception continued to exceed the carrying amount of
the investment. Therefore, the investment had been reduced to zero and
equity and earnings would not have been recognized until the Company's
share of net income equaled its share of unrecognized net losses.
During June 2004, the Company sold its' membership interest in BEC for
gross proceeds of $9.2 million. A pre-tax gain of $7.4 million was
recognized and a liability of $1.8 million established as a reserve against
items for which the Company was required to indemnify the buyer for a
period of 180 days after closing pursuant to the agreement. Net proceeds
from the sale are subject to certain reinvestment provisions of the
Company's Notes.
44
Summarized financial information for BEC as of and for the years ended December
31, is as follows (in thousands):
2003 2002 2001
--------- --------- --------
Current assets $ 7,181 $ 6,679 $ 11,336
Oil and gas properties 96,846 110,555 100,833
Other assets 1,326 1,309 1,966
--------- --------- --------
Total assets $105,353 $118,543 $114,135
========= ========= ========
Current liabilities $ 55,736 $ 14,149 $ 14,505
Long-term debt - 63,900 51,700
Other liabilities 6,459 7,953 8,092
Redeemable preferred shares 37,785 34,925 34,287
Members' equity (deficit) 14,674 2,262 1,764
Accumulated other comprehensive (loss) income (9,301) (4,646) 3,787
--------- --------- --------
Total liabilities and equity $105,353 $118,543 $114,135
========= ========= ========
Net sales $ 42,181 $ 38,002 $ 44,173
Operating income 18,892 13,872 16,737
Net income $ 17,112 $ 4,782 $ 10,259
The Company owned working interest in certain oil and gas properties and an
interest in a drilling rig with BECLP. The Company completed the sale of
its' interest in these properties to BECLP for $2.5 million as of September
2004 with an effective date of June 30, 2004. As of June 30, 2004, the
Company has recognized impairment for these assets of $2.0 million and has
reclassified $2.5 million in property assets as assets held for sale which
is included in other current assets.
11. 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 $1.1 million for the year ended June 30, 2004 and
$1.4 million for each of the years ended June 30, 2003 and 2002.
At June 30, 2004 future minimum lease payments for each of the next five
years and thereafter are as follows (in thousands):
2005 $1,131
2006 497
2007 386
2008 370
2009 307
Thereafter 543
------
$3,234
======
45
12. 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, 2004, 2003 and
2002.
The Company sold its' Royalty Trust units to a Foundation controlled by a
director of the Company, at the then fair market value in December 2003.
The Company acquired interests in various Petroleum Exploration Permits in
New Zealand during the year ended June 30, 2003 from an entity controlled
by a former 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 $0.2 million at June 30, 2004 and
$0.3 million at June 30, 2003. A provision in the agreements 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 minimal at
June 30, 2004 and $0.1 million at June 30, 2003. The notes have interest
rates of 6.5% and 8%. A provision in the agreements cancels the principal
balance over a period of four years 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, 2004 and 2003. 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 2003 and 2002, 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, 2004 is $1.0 million.
13. 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
46
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.
14. COMMITMENTS AND CONTINGENCIES
In 1993, the Company sold working interests in certain Appalachian gas
properties in connection with the formation of the Eastern American Natural
Gas Trust ("Royalty Trust"). A portion of the proceeds from the sale of
these interests, representing a term net profits interest, was accounted
for as a production payment and is currently classified as other current
and long-term liabilities. As of June 30, 2000, the Company determined that
due to the rising cost of transporting gas, the total deferred revenue
would not be realizable. Therefore, $4.9 million, the amount related to the
royalty portion, was impaired and $6.2 million, the amount related to the
term portion, was reclassified to other current and long-term liabilities.
These amounts are amortized as the associated volumes are sold. The
remaining unamortized other current and long-term liabilities are $7.1 and
$8.1 million at June 30, 2004 and 2003, respectively.
The Company entered into a gas sales contract with AFG Industries, Inc.
("AFG") for the sale of up to 4,000 MMBtu per day from January 1, 2004
through December 31, 2004. AFG is a "Float Glass" plant adjacent to an
existing Company pipeline. The sales contract price is based off the NYMEX
settlement price for Natural Gas Henry Hub Futures Contracts each month
plus an Appalachian Basis component.
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.
15. FINANCIAL INSTRUMENTS
The estimated fair values of the Company's financial instruments, as of
June 30, have been determined using appropriate market information and
valuation methodologies. Considerable judgment is required to develop the
estimates of fair value; thus, the estimates provided are not necessarily
indicative of the amount that the Company could realize upon the sale or
refinancing of such financial instruments. The Company in estimating the
fair value of its financial instruments used the following methods and
assumptions:
Notes Receivable - The notes receivable accrue interest at a fixed rate.
-----------------
The carrying value approximates fair value which was estimated using
discounted cash flows based on current interest rates for notes with
similar credit characteristics and maturities.
47
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,
2004, the fair value of the Company's subordinated debt was $118.5 million
and the book value was $126.0 million. At June 30, 2003, the 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. Option premiums paid are recorded as assets and expensed
over the life of the option. Derivatives generally have initial terms of
less than three years, and all currently hedged transactions are expected
to occur within the next three years. See Note 5 for additional information
regarding the Company's derivative holdings.
16. INDUSTRY SEGMENTS
The Company's reportable business segments have been identified based on
the differences in products and service provided. Revenues for the
exploration and production segment are derived from the production and sale
of natural gas and crude oil. Revenues for the aggregation and pipeline
segment arise from the aggregation 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.
48
Reconciliation of non-GAAP financial measure is as follows (in thousands):
Twelve Months Ended June 30
(in thousands)
-----------------------------
2004 2003 2002
-------- -------- ---------
Net income (loss) $ 4,295 $ 9,844 $(26,180)
Add:
Interest expense 15,069 16,383 19,671
Depletion and depreciation of oil and gas properties 13,300 12,140 12,362
Depreciation of pipelines, other property and equipment 4,190 4,294 2,934
Exploration and impairment 10,796 11,729 27,693
Income tax expense (benefit) (4,722) 6,073 (16,822)
Subtract:
Change in accounting principle, net of tax - (73) -
-------- -------- ---------
EBITDAX $42,928 $60,536 $ 19,658
-------- -------- ---------
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 Aggregation
and and
Production Pipeline Other Consolidated
------------- ------------- -------- --------------
2004
Sales to unaffiliated customers $ 62,432 $ 60,819 $ 122 $ 123,373
Depreciation, depletion, amortization 14,721 630 2,139 17,490
Impairment and exploratory costs 10,780 16 - 10,796
Operating profit 15,381 2,218 (1,477) 16,122
Interest expense, net 22,180 (7,453) 82 14,809
EBITDAX 42,388 2,710 (2,170) 42,928
Total assets 174,540 96,362 19,310 290,212
Capital expenditures 19,012 1,927 971 21,910
- ----------------------------------------------------------------------------------------------
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 1,106 3,922 1,257 6,285
Interest expense, net 21,982 (6,486) 273 15,769
EBITDAX 29,125 4,718 26,694 60,537
Total assets 191,190 88,831 15,812 295,833
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) (22,507) 330 (2,292) (24,469)
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
- ----------------------------------------------------------------------------------------------
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
$7.4 million, $6.1 million and $3.4 million, as of June 30, 2004, 2003 and
2002, respectively and revenues of $0.3 million for the year ended June 30,
2004 with no significant revenue recorded for the years ended June 30, 2003
and June 30, 2002.
50
Revenues from two purchasers of the Company's production during the year
ended June 30, 2004 represent $24.1 million and $12.8 million respectively
of the Company's consolidated revenues within the Exploration and
Production and Gas Aggregation and Pipeline segments. During the year ended
June 30, 2003, revenues from three purchasers of the Company's production
represented $17.0 million, $16.5 million and $14.6 million respectively of
the Company's consolidated revenues within the Exploration and Production
and Gas Aggregation and Pipeline segments.
17. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
The following represents selected quarterly financial information for the
years ended June 30 (in thousands, except per share data):
Quarter Ended
---------------------------------------------------
2004 September 30 December 31 March 31 June 30
-------------- ------------- --------- ---------
Total revenue $ 31,041 $ 30,272 $ 32,204 $ 29,856
Gross profit (loss) 3,911 2,893 4,510 4,808
Income per share (a)
basic 0.91 (0.53) 6.98 (0.91)
diluted 0.89 (0.53) 6.88 (0.91)
Net income (loss) 587 (348) 4,631 (575)
Quarter Ended
---------------------------------------------------
2003 September 30 December 31 March 31 June 30
-------------- ------------- --------- ---------
Total revenue $ 22,589 $ 26,383 $ 34,038 $ 34,416
Gross profit (loss) 448 (1,735) 3,506 4,066
Income (loss) before change in
accounting principle (1,562) 8,320 3,347 (188)
Income per share
basic (2.43) 12.77 5.15 (0.38)
diluted (2.43) 12.49 5.04 (0.38)
Net income (loss) (1,562) 8,320 3,347 (261)
18. SUBSEQUENT EVENT
As previously reported, the Company had been in litigation with certain
Holders of its $200,000,000 9 1/2% Senior Subordinated Notes due 2007 (the
"Noteholders") (the "Notes"). The dispute involved the calculation of the
Net Proceeds of an Asset Sale as defined in the Indenture dated May 23,
1997 between the Company and The Bank of New York. The Company and the
Noteholders have settled the dispute, as memorialized in the Settlement
Agreement executed as of February 24, 2004, and attached to the Form 8-K
filed by the Company on February 24, 2004 as Exhibit 99.11 (the "Settlement
Agreement"). In settlement of the dispute the Company agreed to repurchase
$38 million in Notes. The Company met its obligations under the Settlement
Agreement having finalized the first Asset Sale Offer (as defined under the
Indenture) in the amount of $4 million on March 24, 2004 and the second
Asset Sale Offer in the amount of $34 million, at face value, on July 29,
51
2004. The United States District Court for the Southern District of West
Virginia has entered a Dismissal Order dismissing the litigation with
prejudice.
At June 30, 2004, the Company classified $34 million of the Notes that was
paid on July 29, 2004 as long term debt as a result of having an amended
and restated credit agreement in place that allowed the Company to
refinance the debt on a long term basis.
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):
2004 2003 2002
---------- ---------- ---------
Capitalized costs:
Proved properties $ 337,451 $ 327,958 $310,495
Unproved properties 8,105 9,946 9,653
---------- ---------- ---------
Total 345,556 337,904 320,148
Less accumulated depletion and depreciation (119,613) (107,233) (97,523)
---------- ---------- ---------
Net capitalized costs $ 225,943 $ 230,671 $222,625
========== ========== =========
Company's share of equity method investee's net
capitalized costs (see Note 10) $ - $ 27,167 $ 23,908
========== ========== =========
Costs incurred:
Acquisition of proved and unproved properties $ 72 $ 5,879 $ 717
Development costs 7,892 14,105 10,977
Exploration costs 10,449 15,292 20,737
---------- ---------- ---------
Total costs incurred $ 18,413 $ 35,276 $ 32,431
========== ========== =========
Company's share of equity method investee's total
costs incurred (see Note 10) $ 3,329 $ 7,674 $ 2,309
========== ========== =========
52
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):
2004 2003 2002
------- ------- --------
Revenues from sale of oil and gas $57,203 $51,410 $38,939
Less:
Production costs 6,454 4,436 5,001
Production taxes 4,143 3,233 2,077
Exploration and impairment 9,578 11,729 27,605
Depletion, depreciation and amortization 13,300 12,140 12,362
Income tax expense (benefit) 9,432 7,353 (2,999)
------- ------- --------
Income (loss) from oil and gas operations $14,296 $12,519 $(5,107)
======= ======= ========
Company's share of equity method investee's
income from oil and gas operations (see Note 10) $ 5,846 $ 4,354 $ 4,955
======= ======= ========
Production costs include those costs incurred to operate and maintain productive
wells and related equipment and include costs such as labor, repairs and
maintenance, materials, supplies, fuel consumed and insurance. Production costs
are net of well tending fees, which are included in well operations revenues in
the accompanying consolidated statements of operations.
Exploration and impairment expenses include the costs of geological and
geophysical activity, unsuccessful exploratory wells and leasehold impairment
allowances.
Depletion, depreciation and amortization include costs associated with
capitalized acquisitions, exploration and development costs.
The provision for income taxes is computed at the statutory federal income tax
rate and is reduced to the extent of permanent differences which have been
recognized in the Company's tax provision, such as investment tax credits, and
the utilization of Federal tax credits permitted for fuel produced from a
non-conventional source.
Reserve Quantity Information - Reserve estimates are subject to numerous
- ------------------------------
uncertainties inherent in the estimation of quantities of proved reserves and in
the projection of future rates of production and timing of development
expenditures. The accuracy of such estimates is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Results of subsequent drilling, testing and production may cause either upward
or downward revisions of previous estimates. Further, the volumes considered
commercially recoverable fluctuate with changes in prices and operating costs.
Reserve estimates, by their nature, are generally less precise than other
financial statement disclosures.
53
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, 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) (964)
Extensions and discoveries 23,623 580
Sales of reserves in place (2,941) (16)
Purchases of reserves in place 8,371 -
Production (9,755) (185)
------------ ----------
June 30, 2003 190,796 2,366
============ ==========
Revisions of previous estimates 9,309 (252)
Extensions and discoveries 28,732 176
Sales of reserves in place (2,644) (903)
Purchases of reserves in place - -
Production (10,718) (107)
------------ ----------
June 30, 2004 215,475 1,280
============ ==========
Proved developed reserves:
June 30, 2002 160,224 1,135
June 30, 2003 161,796 1,064
June 30, 2004 170,131 626
Company's share of equity method investee's proved reserve at:
June 30, 2002 7,445 12,063
June 30, 2003 7,755 11,427
June 30, 2004 (See Note 10) - -
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.
54
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):
2004 2003 2002
----------- ----------- ----------
Future cash in flows $1,429,645 $1,152,845 $ 715,755
Future production and development costs (355,438) (235,960) (243,828)
Future income tax expense (308,000) (290,000) (116,000)
----------- ----------- ----------
Future net cash flows before discount 766,207 626,885 355,927
10% discount to present value (455,663) (365,662) (205,014)
----------- ----------- ----------
Standardized measure of discounted future net cash
flows related to proved oil and gas reserves $ 310,544 $ 261,223 $ 150,913
=========== =========== ==========
Company's share of equity method investee's
standardized measure of discounted future net
cash flows (See Note 10) $ - $ 67,375 $ 53,838
=========== =========== ==========
55
Principal changes in the standardized measure of discounted future net cash flow
for the years ended June 30 are as follows (in thousands):
2004 2003 2002
--------- --------- ---------
Standardized measure of discounted future
net cash flows at beginning of period $261,223 $150,913 $172,281
Sales of oil and gas produced, net of
production costs (41,724) (35,155) (26,525)
Net changes in prices and production costs 21,120 175,844 (13,507)
Changes in production rates and other (16,394) (5,484) (5,867)
Extensions, discoveries and other additions, net
of future production and development costs 60,609 52,407 13,622
Changes in estimated future development costs (18,826) (16,243) (4,820)
Development costs incurred 7,892 14,105 10,977
Revisions of previous quantity estimates 15,866 (34,089) (24,772)
Purchase of reserves in place - 16,185 -
Accretion of discount 28,073 15,246 17,228
Net change in income taxes (7,295) (72,506) 12,296
--------- --------- ---------
Standardized measure of discounted
future net cash flows at end of period $310,544 $261,223 $150,913
========= ========= =========
* * * * *
56
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.
ITEM 9A. 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 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.
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, 2004 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 2003 annual meeting of stockholders. Executive officers are appointed
by the Board of Directors.
Name Position with Company or Subsidiary
- ----------------------- -----------------------------------------------------
John Mork 56 President and Chief Executive Officer; Director
Joseph E. Casabona 60 Executive Vice President; Director
Michael S. Fletcher 55 Chief Financial Officer
Donald C. Supcoe 48 Senior Vice President, Secretary and General Counsel
J. Michael Forbes 44 Vice President and Treasurer
George V. O'Malley 52 Vice President Accounting
K. Ralph Ranson, II 61 Vice President Marketing
C. Clark Clement, Jr. 55 Vice President Western Operations
Julie Ann Kitano 47 Assistant Secretary
W. Gaston Caperton, III 63 Director
Peter H. Coors 56 Director
L. B. Curtis 79 Director (Chairman)
John J. Dorgan 79 Director
F. H. McCullough, III 56 Director
Julie Mork 53 Director
Arthur C. Nielsen, Jr. 84 Director
Jay S. Pifer 67 Director
57
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, Classroom, Inc. and Prudential Financial.
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 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. He has been a Certified Public Accountant
since 1969. Mr. Casabona serves on the Board of Directors of Gonex, Inc. and
has been a member of the Board of Directors of the West Virginia and
Pennsylvania Independent Oil and Gas Associations.
Clark Clement has been Vice-President of Western Operations since 2003 and
is responsible for the Company's operations in the west, including New Zealand.
Mr. Clement has thirty-four years of experience in the oil industry including
positions with major service companies, independents, and a major oil company.
Prior to joining the Company in 2001, he held positions with BP as Drilling Team
Leader in the Mid-Continent Asset of the U.S. and Well Engineering and
Operations Superintendent in Colombia, South America. Mr. Clement holds a
Bachelor of Science Degree in Chemistry from New Mexico Highlands University and
is a Registered Professional Engineer in Petroleum Engineering. He has written
over fifty technical papers, holds five U.S. patents, several foreign patents,
and is a member of the Society of Petroleum Engineers, American Petroleum
Institute, American Association for Drilling Engineers and Oilfield Helping
Hands.
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 Board of University of Colorado
Hospital, 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 production) segment of the industry. Mr. Curtis graduated from The Colorado
School of Mines with an Engineer of Petroleum Professional Degree.
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.
58
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. He is currently a member of
the Chief Executives Organization, the World President's Organization, the
University of Southern California Engineering School Board of Councilors and a
Trustee of the Denver Museum of Nature and Science. Mr. Mork holds a Bachelor
of Science Degree in Petroleum Engineering from the University of Southern
California and he is a graduate of the Stanford Business School Program for
Chief Executive Officers. He is the husband of Julie Mork.
Julie M. Mork has been a Director of the Company since 1993. She was a
Director of Eastern American from 1974 until 1993. Mrs. Mork served as a
founder and Secretary/Treasurer of Pacific States Gas and Oil, Inc. and Eastern
American. 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 of 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 of the West Virginia
Society of CPA's and as a member of the Board of the Independent Oil and Gas
59
Association of West Virginia. 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.
Jay S. Pifer has been a Director of the Company since 2003. Mr. Pifer
recently retired as Chief Operating Officer of Allegheny Energy with over forty
years of service, where he was responsible for managing over 12,000 megawatts of
generating facilities and providing electric and gas service to over four
million people in Pennsylvania, West Virginia, Maryland, Virginia and Ohio. Mr.
Pifer graduated from Clarion University and Penn State University where he
received the Outstanding Engineering Alumni Award and the Alumni Fellow Award.
Mr. Pifer serves on the boards of numerous community organizations.
K. Ralph Ranson, II has been Vice President of Marketing and Land 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.
60
ITEM 11. EXECUTIVE COMPENSATION
-------------------------------
The following table sets forth for fiscal year 2004 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 2004 $315,166 $372,880 (2) $49,864 $8,873
President and Chief Executive Officer 2003 265,376 125,000 77,045 5,867
2002 258,892 125,000 59,670 26,067
Joseph E. Casabona 2004 $250,919 $259,755 (3) $19,128 $5,803
Executive Vice President 2003 243,595 80,000 6,875 4,763
2002 238,277 125,942 2,905 4,574
Michael S. Fletcher 2004 $244,536 $842,040 (4) $20,275 $6,077
Chief Financial Officer 2003 238,504 45,000 2,477 4,558
2002 233,306 100,510 352 4,504
Edward J. Davies 2004 $245,434 $135,000 (5) $ - $6,514
Senior Vice President 2003 230,201 45,000 408 6,113
2002 223,930 95,714 120 4,592
Donald C. Supcoe 2004 $208,919 $569,530 (6) $13,111 $4,433
Senior Vice President 2003 201,152 65,000 3,529 4,005
2002 197,993 100,435 2,325 3,949
_______________________________
(1) Includes compensation related to insurance policies provided for the
benefit of named officer and 401K matching contributions.
(2) Includes stock based award of $22,880.
(3) Includes stock based award of $22,880 and Class A stock note forgiveness of
$46,875.
(4) Includes Class A stock note forgiveness of $46,875, employment contract
stock of $338,910 and employment contract note forgiveness of $286,255.
(5) Mr. Davies left the Company as of June 22, 2004.
(6) Includes Class A stock note forgiveness of $28,131, employment contract
stock of $201,344 and employment contract note forgiveness of $170,055.
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. Each Director also receives 160 shares of the
Company's Class A Stock. The total Board of Directors' compensation for fiscal
2004 was $0.1 million.
61
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
------------------------------------------------------------------------
The following table sets forth certain information regarding (i) the share
ownership of the Company by each person known to the Company to be the
beneficial owner of more than 5% of the outstanding shares of Common Stock, (ii)
the share ownership of the Company by each Director, (iii) the share ownership
of the Company by certain executive officers and (iv) the share ownership of the
Company by all directors and executive officers as a group, in each case as of
September 23, 2004.
62
The business address of each officer and director listed below is: c/o
Energy Corporation of America, 4643 S. Ulster, Suite 1100, Denver, Colorado
80237.
Beneficial Ownership
Common Stock
----------------------
Shares Percent
---------- ----------
W. Gaston Caperton, III 6,930 1.15%
Joseph E. Casabona 31,376 5.21%
Colstab & Co. (Nominee for KWB Trust) (1) 35,443 5.88%
Peter H. Coors 3,196 *
L. B. Curtis 11,210 1.86%
John J. Dorgan 4,130 *
J. Michael Forbes 2,200 *
F. H. McCullough, III (2) 70,035 11.63%
John Mork (3) 359,493 59.67%
Julie Mork (3) 359,493 59.67%
Arthur C. Nielsen, Jr. 36,480 6.06%
Donald C. Supcoe 3,583 *
---------- ----------
564,076 93.63%
All officers and directors as a group (11 persons) 528,633 87.75%
_______________
* Less than one percent.
(1) 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. The
Company entered into a repurchase agreement on January 21, 2004 with
the KWB Trust to define the purchase price and establish the
conditions for the repurchase of stock owned by the Kenneth W. Brill,
estate. The agreement outlines the repurchase of 49,110 shares of
stock by the Company or through third parties, at an anticipated value
of approximately $3.7 million over the next five years, and provides
for payments in twenty quarterly installments on the majority of the
shares to be repurchased. The repurchase of shares is subject to
certain restrictions in the Company's credit agreements. On June 30,
2004, the Company's remaining repurchase obligation under the
Agreement is approximately $2.9 million. Upon adoption of SFAS No.
150, as described in Note 2, $1.4 million of the obligation was
reclassified as a liability and the remaining $1.5 million is included
in stockholders' equity as third parties have agreed to purchase such
amount.
(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.
63
The following table sets forth certain information regarding (i) the share
ownership of the Company by each person known to the Company to be the
beneficial owner of more than 5% of the outstanding shares of Class A Stock,
(ii) the share ownership of the Company's Class A Stock by each Director, (iii)
the share ownership of the Company's Class A Stock by certain executive officers
and (iv) the share ownership of the Company's Class A Stock by all directors and
executive officers as a group, in each case as of September 23, 2004. 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.
Beneficial Ownership
Class A Stock
----------------------
Shares Percent
---------- ----------
W. Gaston Caperton, III 2,080 4.50%
Joseph E. Casabona (2) 3,529 7.64%
C. Clark Clement, Jr. (2) 450 *
Peter H. Coors 2,750 5.95%
L.B. Curtis 1,720 3.72%
John J. Dorgan 2,480 5.37%
Michael S. Fletcher (2) 4,105 8.89%
J. Michael Forbes (2) 750 1.62%
F.H. McCullough, III 1,246 2.70%
John Mork (1) 5,377 11.64%
Julie Mork (1) 5,377 11.64%
Arthur C. Nielsen, Jr. 3,240 7.01%
George V. O'Malley (2) 420 *
K. Ralph Ranson, II (2) 987 2.14%
Donald C. Supcoe (2) 3,685 7.98%
---------- ----------
32,819 71.04%
All officers and directors as a group (15 persons) 32,819 71.04%
_______________
* Less than one percent.
(1) Includes 1,116 shares held by John and Julie Mork as joint tenants and
1,822 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.
(2) Includes shares of Restricted Class A stock.
64
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
--------------------------------------------------------
Certain officers and Directors of the Company and members of their families
("participants") 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):
2004 2003 2002
---------- --------- ---------
(3)
Gaston Caperton, III $ 100.01 $ 58.05 $ 77.58
Joseph E. Casabona 225.06 29.02 38.77
C. Clark Clement 30.00 23.22 -
Peter Coors 30.00 78.36 77.58
L.B. Curtis 100.01 78.36 83.36
John J. Dorgan 30.00 17.40 19.39
Michael S. Fletcher 49.50 29.03 38.77
J. Michael Forbes 25.00 14.51 19.39
F.H. McCullough, III 50.00 29.03 -
John Mork (1) 825.00 783.65 833.60
Alison Mork Trust (2) 49.50 29.03 38.77
Kyle Mork Trust (2) 49.50 29.03 38.77
Arthur C. Nielsen, Jr. 50.00 29.03 38.77
George O'Malley 33.00 15.67 -
K. Ralph Ranson, II 25.00 14.51 -
Donald C. Supcoe 25.00 14.51 19.39
---------- --------- ---------
$1,696.58 $1,272.41 $1,324.14
========== ========= =========
(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 2004 Drilling
Program, the actual amount of investment may vary based on the number of
wells drilled and the related costs.
65
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 certain of 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, 2004 June 30, 2004
-------------- --------------
Joseph E. Casabona $ 94 $ 14
Michael S. Fletcher 94 14
J. Michael Forbes 96 96
K. Ralph Ranson, II 28 4
Donald C. Supcoe 152 104
-------------- --------------
Total $ 464 $ 232
============== ==============
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, 2004:
Payment Volumes
(in thousands) Mmcf
--------------- -------
Joseph E. Casabona $ 50 66.7
L.B. Curtis 75 100.0
John J. Dorgan 50 66.7
F.H. McCullough, III 150 200.0
--------------- -------
$ 325 433.4
=============== =======
The Company rents office space in Charleston, West Virginia from Energy
Centre, Inc. a corporation owned 54.54% by John Mork, 27.26% by Joseph E.
Casabona and 9.10% 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 2004. The Company believes that such rental terms are
no less favorable than could have been obtained from an unaffiliated party.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
AUDIT FEES
The aggregate fees, including expenses, Deloitte & Touche LLP, the
Company's principal accounting firm, billed the Company for each of the last two
fiscal years for professional services rendered in connection with the audits of
the Company's annual financial statements and review of the Company quarterly
interim financial statements were $326,182 for the year ended June 30, 2004 and
$416,318 for the year ended June 30, 2003.
66
AUDIT-RELATED FEES
Deloitte & Touche LLP did not bill the Company any additional fees in the
last two fiscal years for assurance and related services that are reasonably
related to the performance of the audit or review of the Company's Financial
Statements.
TAX FEES
The aggregate fees, including expenses, Deloitte & Touche LLP billed the
Company for each of the last two fiscal years for tax services related to
compliance, advice, or planning was $458,241 for the year ended June 30, 2004
and $678,365 for the year ended June 30, 2003.
ALL OTHER FEES
Deloitte & Touche LLP did not bill the Company any additional fees in the
last two fiscal years for products and services provided by Deloitte & Touche
LLP, other than the services reported above.
PRE-APPROVAL POLICIES
The Company does not have an audit committee or body performing a similar
function. Pre-approval of all services performed by Deloitte & Touche LLP and
approval of the related fees is granted by a member or representative of the
Board of Directors of the Company.
67
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
The Financial Statements are filed as a part of this annual report at Item 8.
3 Exhibits
The following is a complete list of Exhibits filed as part of, or incorporated by
reference to this report:
* 3.1 Articles of Incorporation of Energy Corporation of America.
* 3.2 Amended Articles of Incorporation of Energy Corporation of America.
* 3.3 Amended Bylaws of Energy Corporation of America.
* 4.1 Intentionally omitted.
* 4.2 Intentionally omitted.
* 4.3 Indenture, dated as of May 23, 1997, between Energy Corporation of America
and The Bank of New York, as Trustee, with respect to the 9 1/2% Senior
Subordinated Notes Due 2007 (including form of 9 1/2% Senior Subordinated
Note Due 2007.
* 4.4 Form of 9 1/2% Senior Subordinated Note due 2007, Series A.
* 4.5 Registration Rights Agreement, dated as of May 20, 1997, among Energy
Corporation of America, as issuer, and Chase Securities Inc. and Prudential
Securities Inc.
* 10.1 Eastern American Energy Corporation Profit/Incentive Stock Plan dated
as of June 4, 1997.
* 10.2 Buy-Sell Stock Option Agreement dated as of May 19, 1997 among Energy
Corporation of America, F.H. McCullough, III and Kathy L. McCullough.
* 10.3 Buy-Sell Stock Option Agreement dated as of July 8, 1996 between Energy
Corporation of America and Kenneth W. Brill.
* 10.4 Gas Purchase Contract dated as of January 1, 1993 between Eastern
American Energy Corporation and Eastern Marketing Corporation.
* 10.5 Intentionally omitted.
* 10.6 Intentionally omitted.
* 10.7 Intentionally omitted.
68
* 10.8 Intentionally omitted.
* 10.9 Intentionally omitted.
* 10.10 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.
* 10.20 Incentive Stock Purchase Agreement dated December 16, 1998 by and
between Energy Corporation of America and Donald C. Supcoe.
* 10.21 Incentive Stock Purchase Agreement dated March 19, 1999 by and
between Energy Corporation of America and W. Gaston Caperton III.
* 10.22 Incentive Stock Purchase Agreement dated March 19, 1999 by and
between Energy Corporation of America and Peter H. Coors.
* 10.23 Incentive Stock Purchase Agreement dated March 19, 1999 by and
between Energy Corporation of America and L.B. Curtis.
* 10.24 Incentive Stock Purchase Agreement dated March 19, 1999 by and
between Energy Corporation of America and J. J. Dorgan.
* 10.25 Incentive Stock Purchase Agreement dated March 19, 1999 by and
between Energy Corporation of America and A. C. Nielsen, Jr.
* 10.26 Stock Purchase Agreement dated February 17, 1999 by and among Westech
Energy Corporation, Westech Energy New Zealand Limited and Edward
J. Davies.
* 10.27 Intentionally omitted.
* 10.28 Intentionally omitted.
* 10.29 Intentionally omitted.
* 10.30 Intentionally omitted.
* 10.31 Gas Sale and Purchase Agreement dated December 20, 1999 between Energy
Corporation of America and Allegheny Energy Service Corporation.
* 10.32 Participation Agreement dated December 20, 1999 between Energy
Corporation of America and Allegheny Energy, Inc.
69
* 10.33 Intentionally omitted.
* 10.34 Intentionally omitted.
* 10.35 Employment Agreement effective as of August 18, 2000 by and between
Energy Corporation of America and Michael S. Fletcher.
* 10.36 Employment Agreement effective as of August 18, 2000 by and between
Energy Corporation of America and Donald C. Supcoe.
* 10.37 Purchase and Sale Agreement dated June 28, 2001 between Tavener E&P Ltd
and Westech Energy Corporation.
* 10.38 Credit Agreement dated July 10, 2002 between Energy Corporation of America
and Foothill Capital Corporation, as the Arranger and Administrative Agent
for the Lenders.
* 10.39 Purchase and Sale Agreement dated August 2, 2002 between East Resources,
Inc. and Energy Corporation of America, without exhibits thereto.
* 10.40 Amendment, effective as of June 29, 1997, to Buy-Sell Stock Option
Agreement between Energy Corporation of America and Kenneth W. Brill.
* 10.41 Agreement dated December 28, 1998 between Energy Corporation of
America and Kenneth W. Brill.
21.1 Subsidiaries of Energy Corporation of America.
24.1 Power of Attorney set forth on the signature page contained in Part V.
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.
* 99.4 Unpublished opinion of the United States Court of Appeals for the
Fourth Circuit decided December 15, 2003 in appeal styled Energy Corporation
of America v. MacKay Shields LLC, et al.
* 99.5 Stipulation and Final Judgement dated December 3, 2002 in the case styled
Energy Corporation of America v. MacKay Shields LLC, et al.
* 99.6 Order of the United States District for the Southern District of West Virginia
entered December 4, 2003 in the above styled case.
* 99.7 January 9, 2004, order of the United States Court of Appeals for the Fourth
Circuit in appeal styled Energy Corporation of America v. MacKay Shield
LLC, et al.
70
* 99.8 Notice of Default from Wells Fargo Foothill, Inc. received January 23, 2004
* 99.9 Forbearance Agreement entered into January 23, 2004 between the Company
and Wells Fargo Foothill, Inc.
* 99.10 Intentionally omitted.
* 99.11 Settlement Agreement among the Company and Noteholders.
* 99.12 Energy Corporation of America commences asset sale offer to purchase up to
$4,000,000 aggregate principal amount of its 9 1/2% Senior Subordinated
Notes due 2007.
* 99.13 Energy Corporation of America commences asset sale offer to purchase up to
$34,000,000 aggregate principal amount of its 9 1/2% Senior Subordinated
Notes due 2007.
* Previously filed
b) Reports on Form 8-K:
The Company filed a report on Form 8-K, Item 5, dated June 15, 2004,
reporting that the Company and Wells Fargo Foothill, Inc., have entered into an
amended and restated credit agreement dated June 10, 2004.
The Company filed a report on Form 8-K, Item 5, dated June 30, 2004,
announcing the commencement of an asset sale offer for the purchase of up to $34
million aggregate principal amount of its 9 1/2 % Senior Subordinated Notes.
* * * * * *
71
PART V
-------
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto, duly authorized, on the 27th day of
September 2004.
ENERGY CORPORATION OF AMERICA
By: /s/ John Mork
--------------------------------------
John Mork
President and Chief Executive Officer
72
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 27th day of September 2004, by the following persons in
the capacities indicated.
73
Signature Title
- -------------------------- ------------------------------------------------
/s/ John Mork
- --------------------------
John Mork President, Chief Executive Officer and Director
(Principal executive officer)
/s/ Joseph E. Casabona
- --------------------------
Joseph E. Casabona Executive Vice President and Director
/s/ Michael S. Fletcher
- --------------------------
Michael S. Fletcher Chief Financial Officer
(Principal accounting and financial officer)
/s/ F. H. McCullough III
- --------------------------
F. H. McCullough III Director
/s/ Gaston Caperton
- --------------------------
Gaston Caperton Director
/s/ Peter H. Coors
- --------------------------
Peter H. Coors Director
/s/ L. B. Curtis
- --------------------------
L. B. Curtis Director
/s/ John J. Dorgan
- --------------------------
John J. Dorgan Director
/s/ Julie Mork
- --------------------------
Julie Mork Director
/s/ Arthur C. Nielsen, Jr.
- --------------------------
Arthur C. Nielsen, Jr. Director
/s/ Jay S. Pifer
- --------------------------
Jay S. Pifer Director
74