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 clas