UNITED STATES OF AMERICA
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED DECEMBER 31, 2003.
or
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM _______ TO _______.
Commission file number: 333-29001-01
ENERGY CORPORATION OF AMERICA
(Exact name of registrant as specified in its charter)
WEST VIRGINIA 84-1235822
(State or other jurisdiction of incorporation or organization)
(IRS Employer Identification No.)
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)
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 whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act).
Yes No X
--- ---
The number of shares of the Registrant's common stock, par value $1.00 per
share, outstanding at February 12, 2004 was 615,893 shares.
ENERGY CORPORATION OF AMERICA
TABLE OF CONTENTS
PAGES
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Unaudited Consolidated Balance Sheets
December 31, 2003 and June 30, 2003 . . . . . . . . . . . . . . . . . . . . 3
Unaudited Consolidated Statements of Operations
For the three and six months ended December 31, 2003 and 2002 . . . . . . . 5
Unaudited Consolidated Statements of Cash Flows
For the six months ended December 31, 2003 and 2002 . . . . . . . . . . . . 6
Unaudited Consolidated Statements of Comprehensive Income
For the three and six months ended December 31, 2003 and 2002 . . . . . . . 7
Notes to Unaudited Consolidated Financial Statements . . . . . . . . . . . . 8
Item 2. Management's Discussion and Analysis of Results of Operations and
Financial Condition . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Item 3. Quantitative and Qualitative Disclosures About Market Risk . . . . . 21
Item 4. Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . 23
PART II OTHER INFORMATION
Item 1. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Item 2. Changes in Securities . . . . . . . . . . . . . . . . . . . . . . . . 24
Item 3. Defaults Upon Senior Securities . . . . . . . . . . . . . . . . . . . 24
Item 4. Submission of Matters to a Vote of Security Holders . . . . . . . . . 24
Item 5. Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Item 6. Exhibits and Reports on Form 8-K . . . . . . . . . . . . . . . . . . 24
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
-2-
PART I FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ENERGY CORPORATION OF AMERICA
CONSOLIDATED BALANCE SHEETS
(UNAUDITED - AMOUNTS IN THOUSANDS)
- -----------------------------------------------------------------------------------
DECEMBER 31, JUNE 30,
2003 2003
-------------- ----------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 3,732 $ 4,831
Accounts receivable:
Oil and gas sales 7,396 10,380
Gas aggregation and pipeline 8,592 9,458
Other 4,469 4,616
-------------- ----------
Accounts receivable 20,457 24,454
Less allowance for doubtful accounts (1,280) (1,616)
-------------- ----------
Accounts receivable net of allowance 19,177 22,838
Deferred income tax asset 1,026 828
Notes receivable, related party 1,609 1,609
Prepaid and other current assets 2,448 1,410
-------------- ----------
Total current assets 27,992 31,516
Property, plant and equipment, net of accumulated
depreciation and depletion of $136,943 and $128,765 250,821 253,270
OTHER ASSETS
Deferred financing costs, net of accumulated
amortization of $5,245 and $4,728 2,561 3,098
Notes receivable, related party 129 146
Other 6,071 7,804
-------------- ----------
Total other assets 8,761 11,048
-------------- ----------
TOTAL $ 287,574 $ 295,834
============== ==========
The accompanying notes are an integral part of the consolidated financial
statements.
-3-
ENERGY CORPORATION OF AMERICA
CONSOLIDATED BALANCE SHEETS
(UNAUDITED - AMOUNTS IN THOUSANDS EXCEPT SHARE DATA)
- ---------------------------------------------------------------------------------------
DECEMBER 31, JUNE 30,
2003 2003
-------------- ----------
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued expenses $ 8,039 $ 13,734
Current portion of long-term debt 21,139 133
Funds held for future distribution 13,606 17,217
Income taxes payable 173 1,484
Accrued taxes other than income 9,071 9,643
Derivatives 930 810
Other current liabilities 1,469 1,421
-------------- ----------
Total current liabilities 54,427 44,442
LONG-TERM OBLIGATIONS
Long-term debt 153,052 173,197
Gas delivery obligation and deferred revenue 2,710 2,917
Deferred income tax liability 21,860 20,376
Derivatives 1,674 1,319
Other 7,891 8,311
-------------- ----------
Total liabilities 241,614 250,562
COMMITMENTS AND CONTINGENCIES
Minority Interest 1,583 1,594
STOCKHOLDERS' EQUITY
Common stock, par value $1.00; 2,000,000 shares
authorized; 730,039 shares issued 730 730
Class A stock, no par value; 100,000 shares authorized;
68,438 shares issued 8,056 5,092
Additional paid in capital 5,503 5,503
Retained earnings 44,758 45,150
Treasury stock and notes receivable arising from the
issuance of common stock (12,316) (11,824)
Unearned compensation on restricted stock (2,121) -
Accumulated other comprehensive loss (233) (973)
-------------- ----------
Total stockholders' equity 44,377 43,678
-------------- ----------
TOTAL $ 287,574 $ 295,834
============== ==========
The accompanying notes are an integral part of the consolidated financial statements.
-4-
ENERGY CORPORATION OF AMERICA
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED - AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
- -----------------------------------------------------------------------------------------------------------
THREE MONTHS ENDED SIX MONTHS ENDED
DECEMBER 31 DECEMBER 31
------------------------ ----------------------
2003 2002 2003 2002
----------- ----------- --------- -----------
REVENUES
Oil and gas sales $ 14,379 $ 10,841 $ 28,520 $ 20,005
Gas aggregation and pipeline sales 14,567 14,203 30,076 26,124
Well operations and service revenues 1,277 1,339 2,669 2,806
Other 48 - 48 36
----------- ----------- --------- -----------
Total revenues 30,271 26,383 61,313 48,971
----------- ----------- --------- -----------
COST AND EXPENSES
Field operating expenses 2,993 2,477 5,710 4,962
Gas aggregation and pipeline cost 13,750 12,967 27,996 23,723
General and administrative 3,757 3,773 7,489 7,332
Taxes, other than income 895 633 1,834 1,264
Depletion and depreciation, oil and gas related 3,439 3,038 6,917 6,090
Depreciation of pipelines and equipment 1,023 1,091 2,049 2,128
Exploration and impairment 1,624 4,275 2,621 4,848
----------- ----------- --------- -----------
Total costs and expenses 27,481 28,254 54,616 50,347
----------- ----------- --------- -----------
Income (loss) from operations 2,790 (1,871) 6,697 (1,376)
OTHER (INCOME) EXPENSE
Interest expense 3,781 4,110 7,588 8,810
(Gain) loss on sale of assets (103) 15 (108) 244
Interest income and other (270) (18,778) (1,075) (20,764)
----------- ----------- --------- -----------
Income (loss) before income taxes and minority interest (618) 12,782 292 10,334
Income tax expense (benefit) (229) 4,512 158 3,688
----------- ----------- --------- -----------
Income (loss) before minority interest (389) 8,270 134 6,646
Minority interest 41 50 105 112
----------- ----------- --------- -----------
NET INCOME (LOSS) $ (348) $ 8,320 $ 239 $ 6,758
=========== =========== ========= ===========
Basic and diluted earnings (loss) per common share:
Basic $ (0.53) $ 12.77 $ 0.37 $ 10.34
=========== =========== ========= ===========
Diluted (see Note 4) $ (0.53) $ 12.49 $ 0.36 $ 10.12
=========== =========== ========= ===========
The accompanying notes are an integral part of the consolidated financial statements.
-5-
ENERGY CORPORATION OF AMERICA
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED - AMOUNTS IN THOUSANDS)
- -------------------------------------------------------------------------------
SIX MONTHS ENDED
DECEMBER 31
----------------------
2003 2002
--------- -----------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 239 $ 6,758
Adjustments to reconcile net income to
net cash provided (used) by operating activities:
Depletion, depreciation and amortization 8,967 8,217
(Gain) loss on sale of assets (108) 244
Gain on purchase of senior bonds (546) (22,693)
Exploration and impairment 2,578 4,714
Other, net 548 2,091
Changes in assets and liabilities:
Accounts receivable 3,810 (1,197)
Income taxes 172 5,482
Prepaid and other assets (949) (1,800)
Accounts payable (6,275) (4,093)
Funds held for future distribution (3,610) 1,462
Other 647 2,581
--------- -----------
Net cash provided by operating activities 5,473 1,766
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment (7,745) (11,677)
Proceeds from sale of assets 620 3,084
Notes receivable and other (6) (284)
--------- -----------
Net cash used by investing activities (7,131) (8,877)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt 21,026 42,923
Principal payments on long-term debt (19,598) (44,308)
Purchase of treasury stock (531) (825)
Proceeds from issuance of stock 257 -
Dividends paid (595) (525)
--------- -----------
Net cash provided (used) by financing activities 559 (2,735)
--------- -----------
Net decrease in cash and cash equivalents (1,099) (9,846)
Cash and cash equivalents, beginning of period 4,831 17,775
--------- -----------
Cash and cash equivalents, end of period $ 3,732 $ 7,929
========= ===========
The accompanying notes are an integral part of the consolidated financial
statements.
-6-
ENERGY CORPORATION OF AMERICA
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED - AMOUNTS IN THOUSANDS)
- --------------------------------------------------------------------------------------------------
THREE MONTHS ENDED SIX MONTHS ENDED
DECEMBER 31 DECEMBER 31
------------------------ ----------------------
2003 2002 2003 2002
---------- ------------ --------- -----------
Net income (loss) $ (348) $ 8,320 $ 239 $ 6,758
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustment:
Current period change 750 500 893 177
Marketable securities:
Current period change - 1 - (5)
Reclassification to earnings - (9) - (25)
Oil and gas derivatives:
Current period change in fair value (1,054) (386) (324) (813)
Reclassification to earnings 144 95 171 169
---------- ------------ --------- -----------
Other comprehensive income (loss), net of tax (160) 201 740 (497)
---------- ------------ --------- -----------
Comprehensive income (loss) $ (508) $ 8,521 $ 979 $ 6,261
========== ============ ========= ===========
The accompanying notes are an integral part of the consolidated financial statements.
-7-
ENERGY CORPORATION OF AMERICA
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2003
1. Nature of Organization
Energy Corporation of America (the "Company") is a privately held energy
company engaged in the exploration, development, production, gathering and
marketing of natural gas and oil, primarily in the Appalachian Basin and
Gulf Coast region. The Company conducts business primarily through its
principal wholly owned subsidiaries, Eastern American Energy Corporation
("Eastern"), Westech Energy Corporation ("Westech"), and Westech Energy New
Zealand ("WENZ"). Eastern is one of the largest oil and gas operators in
the Appalachian Basin, including exploration, development and production,
and is engaged in the gathering and marketing of natural gas. Westech is
involved in oil and gas exploration and development in the California and
Gulf Coast regions of the United States. WENZ is involved in oil and gas
exploration and development in New Zealand. As used herein the "Company"
refers to the Company alone or together with one or more of its
subsidiaries.
2. Accounting Policies
Reference is hereby made to the Company's Annual Report on Form 10-K for
the fiscal year ended June 30, 2003, which contains a summary of major
accounting policies followed in preparation of its consolidated financial
statements. These policies were also followed in preparing the quarterly
financial statements included herein.
Management of the Company believes that all adjustments, consisting of only
normal recurring accruals, necessary for a fair presentation of the results
of such interim periods have been made. The results of operations for the
periods ended December 31, 2003 are not necessarily indicative of the
results to be expected for the full year.
Certain amounts in the financial statements of prior periods have been
reclassified to conform to the current period presentation.
3. Note Repurchases
The Company purchased $2.04 million of its 9 1/2% Senior Subordinated Notes
("Notes") during the six months ended December 31, 2003 in privately
negotiated transactions.
-8-
4. Earnings per Share
A reconciliation of the components of basic and diluted net income (loss)
per common share is as follows for the net income (loss) available to
common stockholders:
NET INCOME (LOSS)
(IN THOUSANDS) SHARES PER SHARE
------------------ ------- -----------
Three months ended December 31, 2003
Basic $ (348) 651,102 $ (0.53)
Diluted (a) $ (348) 651,102 $ (0.53)
Six months ended December 31, 2003
Basic $ 239 648,475 $ 0.37
Diluted $ 239 662,741 $ 0.36
Three months ended December 31, 2002
Basic $ 8,320 651,787 $ 12.77
Diluted $ 8,320 666,053 $ 12.49
Six months ended December 31, 2002
Basic $ 6,758 653,718 $ 10.34
Diluted $ 6,758 667,984 $ 10.12
(a) The effect of outstanding stock options, on a total of 14,266 shares,
was not included in the computation of diluted earnings per share for
the three months ended December 31, 2003 because to do so would have
been antidilutive.
-9-
5. 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 gas aggregation and pipeline
segment arise from the marketing of both Company and third party produced
natural gas volumes and revenues derived from gathering and pipeline
services (functions) provided for Company and third party natural gas. The
Company utilizes earnings before interest, taxes, depreciation, depletion,
amortization and exploration and impairment costs ("EBITDAX") to evaluate
the operations of each segment. Reconciliation of non-GAAP financial
measure is as follows (in thousands):
Six Months Ended
December 31, December 31,
2003 2002
------------- -------------
Net income $ 239 $ 6,758
Add:
Interest expense 7,588 8,810
Depletion, depreciation, amortization-o&g 6,917 6,090
Depletion, depreciation, amortization-other 2,049 2,128
Impairment & exploratory costs 2,621 4,848
Income tax expense 158 3,688
------------- -------------
EBITDAX $ 19,572 $ 32,322
============= =============
-10-
Summarized financial information for the Company's reportable segments for
operations is as follows (in thousands):
Exploration & Gas Aggregation
Production & Pipeline Other Consolidated
--------------- ----------------- -------- --------------
For the six months ended December 31, 2003
------------------------------------------
Revenue from unaffiliated customers $ 31,188 $ 30,076 $ 49 $ 61,313
Depreciation, depletion, amortization 7,577 319 1,070 8,966
Exploration and impairment costs 2,605 16 - 2,621
Income (loss) from operations 6,673 789 (765) 6,697
Interest expense, net 11,325 (3,597) (276) 7,452
EBITDAX 19,395 1,055 (878) 19,572
Total assets 179,105 89,842 18,627 287,574
Capital expenditures 7,598 10 137 7,745
---------------------------------------------------------------------------------------------------------
For the six months ended December 31, 2002
------------------------------------------
Revenue from unaffiliated customers $ 22,811 $ 26,124 $ 36 $ 48,971
Depreciation, depletion, amortization 6,692 406 1,120 8,218
Exploration and impairment costs 4,848 - - 4,848
Income (loss) from operations (1,373) 950 (953) (1,376)
Interest expense, net 10,670 (3,033) 836 8,473
EBITDAX 11,107 1,284 19,931 32,322
Total assets 182,720 79,547 26,209 288,476
Capital expenditures 11,095 174 408 11,677
---------------------------------------------------------------------------------------------------------
Income (loss) from operations 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 corporate-related items, including corporate debt and
non-reportable segments. Included in the total assets of the exploration
and production segment are net long-lived assets located in New Zealand of
$6.9 million and $4.1 million as of December 31, 2003 and 2002.
6. Derivative Instruments
The Company periodically hedges a portion of its gas production through
futures and swap agreements. The purpose of the hedges is to provide a
measure of stability in the volatile environment of oil and gas prices and
to manage its exposure to commodity price risk under existing sales
commitments. All of the Company's price swap agreements in place are
designated as cash flow hedges. At December 31, 2003, the Company had
recorded a $1.5 million other comprehensive loss, $1.0 million short-term
deferred tax asset, $0.1 short-term derivative asset, $0.9 million
short-term derivative liability, $1.7 million long-term derivative
liability, and $0.04 million in recognized expense due to ineffectiveness.
The estimated net amount of the existing losses within other comprehensive
income that are expected to be reclassified into earnings within the next
twelve months is approximately $0.1 million. The Company has partially
hedged its exposure to the variability in future cash flows through June
2005.
-11-
7. Contingencies
The Company has been in litigation with certain holders of its $200 million
9 1/2% Senior Subordinate Notes due 2007 (the "Noteholders"). The dispute
involved the calculation of Net Proceeds of an Asset Sale as defined in the
Indenture. See Note 8 below.
The Company and Prudential Securities Incorporated ("Prudential") have been
in a long-standing dispute related to certain fees. The Company has denied
Prudential's allegations, and is of the opinion that the matter is not
material regardless of the outcome.
The Company is involved in various other legal actions and claims arising
in the ordinary course of business. While the outcome of the 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.
8. Subsequent Events
The Company has been negotiating with the Noteholders to resolve the
dispute described in Note 7. The Company and the Noteholders have reached
an agreement in principle as to the material economic terms of a settlement
of the dispute, although the terms have yet to be memorialized in
definitive documentation. In settlement of the dispute the Company has
agreed to repurchase $38 million in Notes at par. The repurchase will be
effected by the Company making three Asset Sale Offers (as defined in the
Indenture) totaling $38 million. The Company will make an initial Asset
Sale Offer of $4 million shortly after the definitive settlement
documentation is finalized. The Company will consummate another Asset Sale
Offer of $17 million one hundred eighty (180) days thereafter and a third
Asset Sale Offer three hundred sixty (360) days after finalizing the
definitive settlement documentation. Upon consummation of the initial Asset
Sale Offer of $4 million, the Noteholders shall withdraw and waive the
Notice of Default issued to the Company on December 27, 2001. The
Noteholders and the Company shall also submit to the District Court for the
Southern District of West Virginia an agreed Dismissal Order dismissing
with prejudice the litigation. If the Company fails to consummate any of
the Asset Sale Offers, the amount of Notes to be repurchased shall be $43
million and such failure shall constitute an Event of Default, giving the
Noteholders the immediate right to accelerate all outstanding principal and
interest due under the Indenture. Also, in such event, the December 27,
2001 Notice of Default previously issued by the Noteholders will be
reinstated. The agreement in principle was disclosed to the United States
District Court for the Southern District of West Virginia in a hearing held
on Friday, February 13, 2004. In recognition of the agreement in principle,
the Company has classified $21 million if Notes as current liabilities as
of December 31, 2003, representing the Note repurchases that must occur in
calendar year 2004.
On January 23, 2004, prior to reaching the agreement in principle with the
Noteholders, the Company received a Notice of Default from Wells Fargo
Foothill, Inc. ("Foothill"). Wells Fargo Foothill, Inc. was formerly known
as Foothill Capital Corporation. Also, on January 23, 2004, the Company and
Foothill entered into a Forbearance Agreement whereby Foothill agreed to
continue to fund advances under the secured $50 million revolver until
March 15, 2004, unless earlier terminated as provided therein, subject to
certain terms and conditions set forth therein.
Company management believed that cash generated from continuing oil and gas
operations, together with the liquidity provided by existing cash balances,
permitted borrowings, and new or additional lines of credit, to the extent
permitted, and the cash proceeds resulting from the sale of certain assets,
will be sufficient for the Company to remain in compliance with the
requirements of its Notes. However, since the 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.
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 Kenneth W. Brill. The agreement outlines the repurchase of 49,110
shares of stock 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.
-12-
ITEM 2. 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-Q, contain forward-looking
statements that are based on management's beliefs, assumptions, current
expectations, estimates, intentions and projections about the oil and gas
industry, the economy and about the Company itself. Words such as
"anticipates," "believes," "estimates," "expects," "forecasts," "intends," "is
likely," "plans," "predicts," "projects," variations of such words and similar
expressions are intended to identify such forward-looking statements under the
Private Securities Litigation Reform Act of 1995. The Company cautions that
these statements are not guarantees of future performance and involve certain
risks, uncertainties and assumptions that are difficult to predict with regard
to timing, extent, likelihood and degree of occurrence. Therefore, actual
results and outcomes may materially differ from what may be expressed or
forecasted in such forward-looking statements. Furthermore, the Company
undertakes no obligation to update, amend or clarify forward-looking statements,
whether as a result of new information, future events or otherwise.
Important factors that could cause actual results to differ materially from
the forward-looking statements include, but are not limited to, weather
conditions, changes in production volumes, worldwide demand and commodity prices
for petroleum natural resources, the timing and extent of the Company's success
in discovering, acquiring, developing and producing oil and natural gas
reserves, risks incident to the drilling and operation of oil and natural gas
wells, future production and development costs, foreign currency exchange rates,
the effect of existing and future laws, governmental regulations and the
political and economic climate of the United States and New Zealand, the effect
of hedging activities, and conditions in the capital markets.
The following should be read in conjunction with the Company's Financial
Statements and Notes (including the segment information) at Part I, Item 1.
COMPARISON OF RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED DECEMBER 31, 2003
- --------------------------------------------------------------------------------
AND 2002
- ---------
The Company recorded a net loss of $0.4 million for the quarter ended
December 31, 2003 compared to net income of $8.3 million for the quarter ended
December 31, 2002. The decrease in net income of $8.7 million is primarily
attributable to the net of a $3.9 million increase in revenues, $0.8 million
decrease in costs and expenses, $0.3 million decrease in interest expense, $18.5
million decrease in interest income and other, $0.1 million increase in gain on
sale of assets, and a $4.7 million decrease in income tax expense.
-13-
Production, gas aggregation and pipeline volumes, revenue and average sales
prices for the quarters ended December 31 and their related variances are as
follows:
THREE MONTHS ENDED
DECEMBER 31 VARIANCE
---------------------- -----------------
2003 2002 AMOUNT PERCENT
---------- ---------- ------- --------
Natural Gas
Production (Mmcf) 2,781 2,455 326 13.3%
Average sales price received ($/Mcf) 4.77 4.21 0.56 13.3%
---------- ---------- ------- --------
Sales ($in thousands) 13,266 10,327 2,939 28.5%
Oil
Production (Mbbl) 30 23 7 30.4%
Average sales price received ($/Bbl) 27.80 23.83 3.97 16.7%
---------- ---------- ------- --------
Sales ($in thousands) 834 548 286 52.2%
Hedging 308 (132) 440 333.3%
Other (29) 98 (127) -129.6%
---------- ---------- ------- --------
Total oil and gas sales ($in thousands) 14,379 10,841 3,538 32.6%
========== ========== ======= ========
Aggregation Revenue
Volume (Million Mmbtu) 2,147 2,482 (335) -13.5%
Average sales price received ($/Mmbtu) 5.17 4.45 0.72 16.2%
---------- ---------- ------- --------
Sales ($in thousands) 11,090 11,044 46 0.4%
Pipeline Revenue
Volume (Million Mmbtu) 1,404 1,459 (55) -3.8%
Average sales price received ($/Mmbtu) 2.48 2.17 0.31 14.3%
---------- ---------- ------- --------
Sales ($in thousands) 3,477 3,159 318 10.1%
---------- ---------- ------- --------
Total aggregation and pipeline sales ($in thousands) 14,567 14,203 364 2.6%
========== ========== ======= ========
Aggregation Gas Cost
Volume (Million Mmbtu) 2,147 2,482 (335) -13.5%
Average price paid ($/Mmbtu) 5.10 4.20 0.90 21.4%
---------- ---------- ------- --------
Cost ($in thousands) 10,956 10,429 527 5.1%
Pipeline Gas Cost
Volume (Million Mmbtu) 1,166 1,182 (16) -1.4%
Average price paid ($/Mmbtu) 2.40 2.15 0.25 11.6%
---------- ---------- ------- --------
Cost ($in thousands) 2,794 2,538 256 10.1%
---------- ---------- ------- --------
Total aggregation and pipeline cost ($in thousands) 13,750 12,967 783 6.0%
========== ========== ======= ========
REVENUES. Total revenues increased $3.9 million or 14.7% between the
--------
periods. The increase was due to a $3.5 million increase in oil and gas sales
and a $0.4 million increase in gas aggregation and pipeline sales. Well
operations and service revenues remained relatively constant.
-14-
Revenues from oil and gas sales increased a net of $3.5 million from $10.8
million for the quarter ended December 31, 2002 to $14.3 million for the quarter
ended December 31, 2003. Natural gas sales increased $2.9 million and oil sales
increased $0.3 million. The net increase in gas production revenue is
attributable to the increase in gas prices and an increase in gas production.
The price increase is a result of the rise in the related natural gas indexes
and the increase in production is primarily due to wells drilled in the Gulf
Coast region. Sales were increased by recognized gains on related hedging
transactions and other revenue, which totaled a gain of $0.3 million for the
quarter ended December 31, 2003 compared to a loss of $0.03 million for the
quarter ended December 31, 2002.
Revenues from gas aggregation and pipeline sales increased $0.4 million
from $14.2 million during the period ended December 31, 2002 to $14.6 million in
the period ended December 31, 2003. Gas aggregation revenue increased $0.05
million primarily as a result of an increase in the average sales price that
corresponds to the rise in the related natural gas price indexes for this period
compared to the prior period. Offsetting this increase in average sales price
was a decrease in gas volumes aggregated for sale. Pipeline revenue, which has
a sales and gathering component, increased $0.3 million primarily as a result of
an increase in the average sales price that corresponds to the rise in the
related natural gas price indexes for this period compared to the prior period.
Pipeline volumes declined compared to the prior period primarily due to natural
production declines on the system.
COSTS AND EXPENSES. The Company's costs and expenses decreased $0.8
--------------------
million between the periods primarily as a net result of a $0.8 million increase
in gas aggregation and pipeline costs, $0.3 million increase in depreciation,
depletion, and amortization costs, $2.7 million decrease in exploration and
impairment costs, $0.3 million increase in taxes other than income, and a $0.5
million increase in field and lease operating expense.
Gas aggregation and pipeline costs increased $0.8 million. Gas aggregation
costs increased $0.5 million and pipeline costs increased $0.3 million. The
increase in costs is primarily attributable to the increase in average price of
gas that corresponds to the rise in the related natural gas indexes offset by a
decrease in volume for this period compared to the prior period.
Depletion, depreciation, and amortization expenses increased $0.3 million
primarily due to an increase in production for this period compared to the prior
period.
Exploration and impairment costs decreased $2.7 million primarily due to a
decrease in dry hole expense related to exploratory wells drilled in the current
period as compared to the related exploratory dry hole expenses in the prior
period.
Taxes other than income increased $0.3 million due to the increase in oil
and gas sales for the current year as compared to the same period in the prior
year. Wellhead oil and gas sales revenue, on which production taxes are based,
was higher for the current year.
Field and lease operating expenses increased $0.5 million primarily as a
result of increased expenses for compressor and road repairs, costs related to
properties acquired in the East, and an increase in the number of producing
wells in the Gulf Coast region.
INTEREST EXPENSE. Interest expense decreased $0.3 million when comparing
------------------
the periods primarily due to the purchase of $4.7 million face value of the
Company's senior notes since December 31, 2002 and a decrease in the average
interest rate paid on outstanding debt.
-15-
INTEREST INCOME AND OTHER. Interest income and other income decreased
----------------------------
$18.5 million when comparing the periods. This decrease between the periods is
mainly attributable to a decrease in recognized gains on the purchase of senior
bonds.
COMPARISON OF RESULTS OF OPERATIONS FOR THE SIX MONTHS ENDED DECEMBER 31, 2003
- --------------------------------------------------------------------------------
AND 2002
- ---------
The Company recorded net income of $0.2 million for the six months ended
December 31, 2003 compared to net income of $6.7 million for the six months
ended December 31, 2002. The decrease in net income of $6.5 million is
primarily attributable to the net of a $12.3 million increase in revenues, $4.3
million increase in costs and expenses, $1.2 million decrease in interest
expense, $19.7 million decrease in interest income and other, $0.4 million
increase in gain on sale of assets, and a $3.5 million decrease in income tax
expense.
-16-
Production, gas aggregation and pipeline volumes, revenue and average sales
prices for the six months ended December 31 and their related variances are as
follows:
THREE MONTHS ENDED
DECEMBER 31 VARIANCE
---------------------- -----------------
2003 2002 AMOUNT PERCENT
---------- ---------- ------- --------
Natural Gas
Production (Mmcf) 5,549 4,986 563 11.3%
Average sales price received ($/Mcf) 4.89 3.76 1.13 30.1%
---------- ---------- ------- --------
Sales ($in thousands) 27,139 18,763 8,376 44.6%
Oil
Production (Mbbl) 63 53 10 18.9%
Average sales price received ($/Bbl) 27.79 23.43 4.36 18.6%
---------- ---------- ------- --------
Sales ($in thousands) 1,751 1,242 509 41.0%
Hedging (437) (194) (243) -125.3%
Other 67 194 (127) -65.5%
---------- ---------- ------- --------
Total oil and gas sales ($in thousands) 28,520 20,005 8,515 42.6%
========== ========== ======= ========
Aggregation Revenue
Volume (Million Mmbtu) 4,494 4,914 (420) -8.5%
Average sales price received ($/Mmbtu) 5.07 4.08 0.99 24.3%
---------- ---------- ------- --------
Sales ($in thousands) 22,769 20,045 2,724 13.6%
Pipeline Revenue
Volume (Million Mmbtu) 2,815 2,938 (123) -4.2%
Average sales price received ($/Mmbtu) 2.60 2.07 0.53 25.6%
---------- ---------- ------- --------
Sales ($in thousands) 7,307 6,079 1,228 20.2%
---------- ---------- ------- --------
Total aggregation and pipeline sales ($in thousands) 30,076 26,124 3,952 15.1%
========== ========== ======= ========
Aggregation Gas Cost
Volume (Million Mmbtu) 4,494 4,914 (420) -8.5%
Average price paid ($/Mmbtu) 4.93 3.84 1.09 28.4%
---------- ---------- ------- --------
Cost ($in thousands) 22,174 18,846 3,328 17.7%
Pipeline Gas Cost
Volume (Million Mmbtu) 2,281 2,366 (85) -3.6%
Average price paid ($/Mmbtu) 2.55 2.06 0.49 23.8%
---------- ---------- ------- --------
Cost ($in thousands) 5,822 4,877 945 19.4%
---------- ---------- ------- --------
Total aggregation and pipeline cost ($in thousands) 27,996 23,723 4,273 18.0%
========== ========== ======= ========
-17-
REVENUES. Total revenues increased $12.3 million or 25.2% between the
--------
periods. The increase was due primarily to an $8.5 million increase in oil and
gas sales and a $4.0 million increase in gas aggregation and pipeline sales,
offset by a $0.2 decline in well operations and service revenues.
Revenues from oil and gas sales increased a net of $8.5 million from $20.0
million for the six months ended December 31, 2002 to $28.5 million for the six
months ended December 31, 2003. Natural gas sales increased $8.4 million and
oil sales increased $0.5 million. The net increase in gas production revenue is
attributable to the increase in gas prices and an increase in gas production.
The price increase is a result of the rise in the related natural gas indexes
and the increase in production is primarily due to wells drilled in the Gulf
Coast region. Sales were decreased by recognized losses on related hedging
transactions and other revenue, which totaled a loss of $0.4 million for the six
months ended December 31, 2003 compared to no material gain or loss for the six
months ended December 31, 2002.
Revenues from gas aggregation and pipeline sales increased $4.0 million
from $26.1 million for the six months ended December 31, 2002 to $30.1 million
for the six months ended December 31, 2003. Gas aggregation revenue increased
$2.7 million primarily as a result of an increase in the average sales price
that corresponds to the rise in the related natural gas price indexes for this
period compared to the prior period. Offsetting this increase in average sales
price was a decrease in gas volumes aggregated for sale. Pipeline revenue,
which has a sales and gathering component, increased $1.2 million primarily as a
result of an increase in the average sales price that corresponds to the rise in
the related natural gas price indexes for this period compared to the prior
period. Pipeline volumes declined compared to the prior period primarily due to
natural production declines on the system.
COSTS AND EXPENSES. The Company's costs and expenses increased $4.3
--------------------
million between the periods primarily as a net result of a $4.3 million increase
in gas aggregation and pipeline costs, $0.7 million increase in depreciation,
depletion, and amortization costs, $2.2 million decrease in exploration and
impairment costs, $0.6 million increase in taxes other than income, and a $0.7
million increase in field and lease operating expense.
Gas aggregation and pipeline costs increased $4.3 million. Gas aggregation
costs increased $3.3 million and pipeline costs increased $1.0 million. The
increase in costs is primarily attributable to the increase in average price of
gas that corresponds to the rise in the related natural gas indexes offset by a
decrease in volume for this period compared to the prior period.
Depletion, depreciation, and amortization expenses increased $0.7 million
primarily due to an increase in production.
Exploration and impairment costs decreased $2.2 million primarily due to a
decrease in dry hole expense related to exploratory wells drilled in the current
period as compared to the related exploratory dry hole expenses in the prior
period.
Taxes other than income increased $0.6 million due to the increase in oil
and gas sales for the current year as compared to the same period in the prior
year. Wellhead oil and gas sales revenue, on which production taxes are based,
was higher for the current year.
Field and lease operating expenses increased $0.7 million primarily as a
result of increased expenses for compressor and road repairs, costs related to
properties acquired in the East, and an increase in the number of producing
wells in the Gulf Coast region.
-18-
INTEREST EXPENSE. Interest expense decreased $1.2 million when comparing
------------------
the periods primarily due to the purchase of $4.7 million face value of the
Company's senior notes since December 31, 2002 and a decrease in the average
interest rate paid on outstanding debt.
INTEREST INCOME AND OTHER. Other income decreased $19.7 million when
----------------------------
comparing the periods. This decrease between the periods is mainly attributable
to a decrease in recognized gains on the purchase of senior bonds.
LIQUIDITY AND CAPITAL RESOURCES
- ----------------------------------
The Company's financial condition has declined since September 30, 2003.
Stockholders' equity has decreased from $45.1 million at September 30, 2003 to
$44.4 million at December 31, 2003, the Company's working capital of a negative
$12.9 million at September 30, 2003 decreased to a negative $26.4 million at
December 31, 2003. The Company's cash increased from $2.6 million at September
30, 2003 to $3.7 million at December 31, 2003. The Company's cash at February
12, 2004 was $0.9 million. The change in cash during the quarter of
approximately $1.1 million resulted from various operating, investing and
financing activities of the Company. The activities were primarily comprised
of: the borrowing of approximately $2.6 million under the Company's $50 million
revolving Credit Agreement (the "Agreement"); the investment of approximately
$3.7 million in property, plant and equipment; payments of approximately $0.5
million for the acquisition of treasury stock and dividends; receipt of
approximately $0.3 million of cash in connection with the Company's restricted
Class A stock purchase plan for employees; receipt of approximately $0.6 million
of cash proceeds from the sale of assets; and approximately $1.8 million of cash
provided by operations during the quarter.
At December 31, 2003, the Company's principal source of liquidity consisted
of $3.7 million of cash, $0.9 million available under an unsecured credit
facility currently in place, plus amounts available under the $50 million
Foothill Capital Corporation Agreement. Foothill Capital Corporation is now
known as Wells Fargo Foothill, Inc. ("Foothill"). At December 31, 2003, $1.1
million was outstanding or committed under the short-term credit facility and
$42.2 million was outstanding under the Agreement.
On July 10, 2002, the Company entered into the Agreement with Foothill.
Depending on its level of borrowing under the Agreement, the applicable interest
rates are based on Wells Fargo's prime rate plus 0.50% to 2.50%. The Agreement
expires on July 10, 2005. The Agreement is secured by certain of the existing
proved producing oil and gas assets of the Company. The Agreement, among other
things, restricts the ability of the Company and its subsidiaries to incur new
debt, grant additional security interests in its collateral, engage in certain
merger or reorganization activities, or dispose of certain assets. Upon the
occurrence of an event of default, the lenders may terminate the Agreement and
declare all obligations thereunder immediately due and payable (see discussion
of an event of default notice below). As of February 12, 2003, there are $37.0
million in outstanding borrowings under the Agreement. Under the Indenture for
the Company's Notes, the Company is restricted from incurring additional debt in
excess of the $50 million available under the Agreement unless the Company's
fixed charge coverage ratio, as defined in the Indenture, is at least 2.5 to 1
and the Company is not in default under the Indenture. Currently, the Company's
fixed charge coverage ratio is estimated to be greater than 2.5 to 1. Under the
terms of the Company's agreement in principle with the Noteholders described
below, until the Company satisfies its obligations under the agreement in
principle with the Noteholders, any additional borrowings beyond that available
under the Company's existing credit facilities must be applied to repurchase the
Notes.
As previously reported, the Company has 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.
-19-
The Company has been negotiating with the Noteholders to resolve the
dispute. The Company and the Noteholders have reached an agreement in principle
as to the material economic terms of a settlement of the dispute, although the
terms have yet to be memorialized in definitive documentation. In settlement of
the dispute the Company has agreed to repurchase $38 million in Notes. The
repurchase will be effected by the Company making three Asset Sale Offers (as
defined in the Indenture) totaling $38 million. The Company will make an initial
Asset Sale Offer of $4 million shortly after the definitive settlement
documentation is finalized. The Company will consummate another Asset Sale Offer
of $17 million one hundred eighty (180) days thereafter and a third Asset Sale
Offer three hundred sixty (360) days after finalizing the definitive settlement
documentation. Upon consummation of the initial Asset Sale Offer of $4 million,
the Noteholders shall withdraw and waive the Notice of Default issued to the
Company on December 27, 2001. The Noteholders and the Company shall also submit
to the District Court for the Southern District of West Virginia an agreed
Dismissal Order dismissing with prejudice the litigation. If the Company fails
to consummate any of the Asset Sale Offers, the amount of Notes to be
repurchased shall be $43 million and such failure shall constitute an Event of
Default, giving the Noteholders the immediate right to accelerate all
outstanding principal and interest due under the Indenture. Also, in such event,
the December 27, 2001 Notice of Default previously issued by the Noteholders
will be reinstated. The agreement in principle was disclosed to the United
States District Court for the Southern District of West Virginia in a hearing
held on Friday, February 13, 2004.
On January 23, 2004, prior to reaching the agreement in principle with the
Noteholders, the Company received a Notice of Default from Foothill. Also, on
January 23, 2004, the Company and Foothill entered into a Forbearance Agreement
whereby Foothill agreed to continue to fund advances under the secured $50
million revolver until March 15, 2004, unless earlier terminated as provided
therein, subject to certain terms and conditions set forth therein.
The Company's net cash requirements will fluctuate based on timing and the
extent of the interplay of capital expenditures, cash generated by continuing
operations, cash generated by the sale of assets and interest expense. EBITDAX,
before inclusion of the gain on the purchase of the Company's Notes, for fiscal
year 2003 was $37.2 million. EBITDAX for fiscal years 2002 and 2001 was $19.7
million and $33.7 million, respectively. Management anticipates that EBITDAX
from oil and gas operations for fiscal year 2004 will approximate $40 million.
The Company's ability to achieve EBITDAX of $40 million from oil and gas
operations for fiscal year 2004 is highly dependant on product price and
continued drilling success and the sale of certain non-strategic assets. There
can be no assurance given that the Company will be able to achieve these goals.
Although cash provided from oil and gas operations may not be sufficient to
fully fund the Company's fiscal year 2004 projected interest charges of over $15
million, capital expenditures program of $17 million, and other uses, management
believes that cash generated from continuing oil and gas operations, together
with the liquidity provided by existing cash balances, permitted borrowings, and
new or additional lines of credit, to the extent permitted, and the cash
proceeds resulting from the sale of certain assets, will be sufficient to
satisfy commitments for capital expenditures, debt service obligations, working
capital needs and other cash requirements for the remainder of fiscal year
2004.
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 the resolution to the dispute with the
Noteholders, together with its existing capital resources and its expected
fiscal year 2004 results of operations and cash flows from operating activities
will be sufficient for the Company to remain in compliance with the requirements
of its Notes. However, since future results of operations, cash flow from
operating activities, debt service capability, levels and availability of
capital resources and continuing liquidity are dependent on future
-20-
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.
ITEM 3. 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 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 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.
Ineffectiveness is recorded in current earnings. The Company does not hold or
issue derivative instruments for trading purposes. The Company currently has
elected to enter into derivative hedge transactions and fixed price physical
delivery contracts on its estimated production covering approximately 65% to 75%
for the fiscal year ending June 30, 2004 and 40% to 50% for the fiscal year
ending June 30, 2005. As of December 31, 2003, the Company's open gas
derivative instruments and fixed price delivery contracts were as follows:
-21-
Total Average
Market Volumes Contract Unrealized
Time period Index (MMBtu) Price (Gains) Losses
- --------------------------------- ------ ---------- --------- ----------------
Derivatives
Natural Gas Swaps
January 2004 NYMEX 150,000 $ 5.52 $ 87,429
January 2004 - June 2004 NYMEX 546,000 4.05 854,825
February 2004 NYMEX 150,000 6.07 18,454
February 2004 - March 2004 NYMEX 60,000 6.23 (8,017)
March 2004 NYMEX 100,000 5.76 23,515
July 2004 - March 2005 NYMEX 1,080,000 5.57 (255,283)
July 2004 - June 2005 NYMEX 3,240,000 4.54 1,878,868
---------- ----------------
Unrealized Losses 5,326,000 $ 2,599,791
---------- ================
Physical Contracts
Fixed Price Delivery Contracts
January 2004 - June 2004 2,653,500 $ 4.52
July 2004 - October 2004 338,250 4.85
----------
Total Hedged Production 8,317,750
==========
Notwithstanding the above, the Company's future cash flows from gas and oil
production are exposed to significant volatility as commodity prices change.
Assuming total oil and gas production, pricing, and the percentage of gas
production hedged under physical delivery contracts and derivative instruments
remain at December 2003 levels, a 10% change in the average unhedged prices
realized would change the Company's gas and oil revenues by approximately $0.2
million on a quarterly basis.
INTEREST RATE RISK
- --------------------
Interest rate risk is attributable to the Company's debt. The Company
utilizes United States dollar denominated borrowings to fund working capital and
investment needs. There is inherent rollover risk for borrowings as they mature
and are renewed at current market rates, and there is ongoing interest rate risk
for variable rate borrowings. 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 December
31, 2003 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.
-22-
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.
ITEM 4. 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
quarterly 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 II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
As previously disclosed, the Company has been in litigation with certain
holders of its $200 million 9 1/2% Senior Subordinate Notes due 2007 (the
"Noteholders"). The dispute involved the calculation of Net Proceeds of an Asset
Sale as defined in the Indenture.
The Company has been negotiating with the Noteholders to resolve the
dispute. The Company and the Noteholders have reached an agreement in principle
as to the material economic terms of a settlement of the dispute, although the
terms have yet to be memorialized in definitive documentation. In settlement of
the dispute the Company has agreed to repurchase $38 million in Notes. The
repurchase will be effected by the Company making three Asset Sale Offers (as
defined in the Indenture) totaling $38 million. The Company will make an initial
Asset Sale Offer of $4 million shortly after the definitive settlement
documentation is finalized. The Company will consummate another Asset Sale Offer
of $17 million one hundred eighty (180) days thereafter and a third Asset Sale
Offer three hundred sixty (360) days after finalizing the definitive settlement
documentation. Upon consummation of the initial Asset Sale Offer of $4 million,
the Noteholders shall withdraw and waive the Notice of Default issued to the
Company on December 27, 2001. The Noteholders and the Company shall also submit
to the District Court for the Southern District of West Virginia an agreed
Dismissal Order dismissing with prejudice the litigation. If the Company fails
to consummate any of the Asset Sale Offers, the amount of Notes to be
repurchased shall be $43 million and such failure shall constitute an Event of
Default, giving the Noteholders the immediate right to accelerate all
outstanding principal and interest due under the Indenture. Also, in such event,
the December 27, 2001 Notice of Default previously issued by the Noteholders
will be reinstated. The agreement in principle was disclosed
-23-
to the United States District Court for the Southern District of West Virginia
in a hearing held on Friday, February 13, 2004.
The Company and Prudential Securities Incorporated ("Prudential") have been
in a long-standing dispute related to certain fees. The Company has denied
Prudential's allegations, and is of the opinion that the matter is not material
regardless of the outcome.
The Company is involved in various other legal actions and claims arising
in the ordinary course of business. While the outcome of these other lawsuits
against the Company cannot be predicted with certainty, management does not
expect these matters to have a material adverse effect on the Company's
operations or financial position.
ITEM 2. CHANGES IN SECURITIES
None
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
ITEM 5. OTHER INFORMATION
None
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a) Exhibits:
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
b) Reports on Form 8-K:
The Company filed a report on Form 8-K, Item 5, dated December 23,
2003, furnishing the United States Court of Appeals for the Fourth
Circuit unpublished opinion in the appeal styled Energy Corporation of
America v. MacKay Shields LLC, et al on December 15, 2003.
The Company filed a report on Form 8-K, Item 5, dated January 27,
2004, reporting that on January 23, 2004, the Company received a
Notice of Default from Wells Fargo Foothill, Inc. and that the Company
and Wells Fargo Foothill, Inc., entered into a Forbearance Agreement.
-24-
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the under
signed thereunto, duly authorized, in the City of Denver, State of Colorado, on
the 17th day of February 2004.
ENERGY CORPORATION OF AMERICA
By: /s/ John Mork
---------------------------------------
John Mork
Chief Executive Officer and Director
By: /s/ Michael S. Fletcher
---------------------------------------
Michael S. Fletcher
Chief Financial Officer
-25-