<PAGE> 1
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 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, 1997.
PURSUANT TO SECTION 15D-2, THIS REPORT CONTAINS ONLY FINANCIAL STATEMENTS.
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)
(I.R.S. 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)
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
---------- ----------
* The Registrant became subject to the reporting requirements of Section 13 of
the Securities Exchange Act of 1934 on
August 13, 1997.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of each of the Registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of the Form 10-K or any
amendment to this Form 10-K. X
Aggregate market value of the voting stock held by non-affiliates of the
Registrant: N/A
The number of shares of the Registrant's common stock, par value $1.00 per
share, outstanding at June 30, 1997 was 665,882 shares.
Documents incorporated by reference: None
<PAGE> 2
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS
FOR THE FISCAL YEAR ENDED JUNE 30, 1997
- -------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Page
FINANCIAL STATEMENTS:
<S> <C>
Independent Auditors' Report 1
Consolidated Balance Sheets 2
Consolidated Statements of Operations 4
Consolidated Statements of Stockholders' Equity 5
Consolidated Statements of Cash Flows 6
Notes to Consolidated Financial Statements 7
FINANCIAL STATEMENT SCHEDULES:
Schedule I - Condensed Financial Information of Registrant 32
Schedule II - Valuation and Qualifying Accounts 36
</TABLE>
<PAGE> 3
INDEPENDENT AUDITORS' REPORT
To the Stockholders and Board of Directors of
Energy Corporation of America:
We have audited the accompanying consolidated balance sheets of Energy
Corporation of America and Subsidiaries as of June 30, 1997 and 1996, and the
related consolidated statements of operations, stockholders' equity, and cash
flows for each of the three years in the period ended June 30, 1997. Our audits
also included the financial statement schedules listed in the accompanying
Index. These financial statements and financial statement schedules are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements and financial statement schedules based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Energy Corporation of America and
Subsidiaries as of June 30, 1997 and 1996, and the results of their operations
and their cash flows for each of the three years in the period ended June 30,
1997 in conformity with generally accepted accounting principles. Also, in our
opinion, such financial statement schedules, when considered in relation to the
basic consolidated financial statements taken as a whole, present fairly in all
material respects the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
September 15, 1997
-1-
<PAGE> 4
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
JUNE 30, 1997 AND 1996
(Amounts in Thousands)
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
ASSETS 1997 1996
<S> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents $ 20,814 $ 14,197
--------- ---------
Accounts receivable:
Utility gas and transportation 19,168 23,317
Gas marketing and pipeline 5,705 8,931
Oil and gas sales 7,507 6,875
Other 7,203 6,423
--------- ---------
39,583 45,546
Less allowance for doubtful accounts (1,660) (1,744)
--------- ---------
37,923 43,802
Gas in storage, at average cost 12,810 12,457
Income taxes receivable 1,392 3,242
Deferred income taxes 3,307 6,337
Prepaid and other current assets 3,947 3,860
--------- ---------
Total current assets 80,193 83,895
--------- ---------
NET PROPERTY, PLANT AND EQUIPMENT 313,971 339,793
--------- ---------
OTHER ASSETS:
Deferred financing costs, less accumulated amortization of
$452 and $1,144, respectively 9,956 8,198
Notes receivable 5,875 4,219
Notes receivable - related party 1,428 1,528
Deferred utility charges 18,259 16,302
Deferred income taxes 1,357
Other 5,075 6,212
--------- ---------
Total other assets 40,593 37,816
--------- ---------
TOTAL $ 434,757 $ 461,504
========= =========
</TABLE>
See notes to consolidated financial statements. (Continued)
-2-
<PAGE> 5
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
JUNE 30, 1997 AND 1996
(Amounts in Thousands)
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
LIABILITIES AND STOCKHOLDERS' EQUITY 1997 1996
<S> <C> <C>
CURRENT LIABILITIES:
Accounts payable and accrued expenses $ 31,046 $ 39,798
Current portion of long-term debt 55 10,051
Short-term debt 15,724 8,392
Funds held for future distribution 6,014 5,191
Accrued taxes, other than income 7,774 3,743
Overrecovered gas costs 9,650 11,778
Other current liabilities 9,400 12,948
--------- ---------
Total current liabilities 79,663 91,901
LONG-TERM OBLIGATIONS, LESS CURRENT PORTION:
Long-term debt 260,089 254,647
Gas delivery obligation and deferred trust revenue 18,580 21,473
Deferred income taxes 32,018 37,694
Other long-term obligations 14,000 15,521
--------- ---------
Total liabilities 404,350 421,236
--------- ---------
COMMITMENTS AND CONTINGENCIES
MINORITY INTEREST 1,809 2,718
--------- ---------
STOCKHOLDERS' EQUITY:
Common stock, par value $1.00; 2,000 shares authorized;
714 and 711 shares issued in 1997 and 1996, respectively 714 711
Additional paid-in capital 4,221 4,086
Retained earnings 27,249 34,099
Treasury stock and notes receivable arising from issuance
of common stock (3,435) (1,371)
Cumulative foreign currency translation adjustment (151) 25
--------- ---------
Stockholders' equity - net 28,598 37,550
--------- ---------
TOTAL $ 434,757 $ 461,504
========= =========
</TABLE>
See notes to consolidated financial statements. (Concluded)
-3-
<PAGE> 6
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE YEARS ENDED JUNE 30, 1997, 1996
AND 1995 (Amounts in Thousands, Except Per Share Data)
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
1997 1996 1995
<S> <C> <C>
REVENUES:
Utility gas sales and transportation $ 173,463 $ 182,929
Gas marketing and pipeline sales 152,720 146,398 $ 103,015
Oil and gas sales 33,253 31,940 29,277
Well operations and service revenues 14,198 14,003 3,955
Contract settlement and other 306 524 9,247
--------- --------- ---------
373,940 375,794 145,494
--------- --------- ---------
COSTS AND EXPENSES:
Utility gas purchased 100,774 95,157
Gas marketing and pipeline cost of sales 144,006 138,067 100,251
Field operating expenses 20,874 21,796 11,510
Utility operations and maintenance 21,320 23,841
General and administrative 22,644 23,967 6,689
Taxes, other than income 16,094 16,165 1,560
Depletion, depreciation and amortization of oil and gas properties 8,325 9,204 9,763
Depreciation of pipelines, other property and equipment 10,719 9,613 2,278
Exploration and impairment 10,121 6,756 281
--------- --------- ---------
354,877 344,566 132,332
--------- --------- ---------
Income from operations 19,063 31,228 13,162
--------- --------- ---------
OTHER (INCOME) AND EXPENSE:
Interest 23,817 23,782 9,244
Gain on sale of assets (8,304) (3,934) (279)
Other (586) 93 (133)
--------- --------- ---------
14,927 19,941 8,832
--------- --------- ---------
INCOME BEFORE INCOME TAXES, MINORITY INTEREST AND
EXTRAORDINARY LOSS 4,136 11,287 4,330
PROVISION FOR INCOME TAXES 1,966 3,274 2,710
--------- --------- ---------
INCOME BEFORE MINORITY INTEREST AND EXTRAORDINARY LOSS 2,170 8,013 1,620
MINORITY INTEREST 152 193 435
--------- --------- ---------
INCOME BEFORE EXTRAORDINARY LOSS 2,018 7,820 1,185
EXTRAORDINARY LOSS ON EARLY EXTINGUISHMENT OF DEBT
(NET OF INCOME TAX BENEFIT OF $4,233) 7,861
--------- --------- ---------
NET INCOME (LOSS) $ (5,843) $ 7,820 $ 1,185
========= ========= =========
NET INCOME (LOSS) PER COMMON SHARE:
Income before extraordinary item $ 2.99 $ 11.02 $ 1.67
Extraordinary loss (11.66)
--------- --------- ---------
Net income (loss) $ (8.67) $ 11.02 $ 1.67
========= ========= =========
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT
SHARES OUTSTANDING 674 710 710
========= ========= =========
</TABLE>
See notes to consolidated financial statements.
-4-
<PAGE> 7
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY FOR THE YEARS ENDED JUNE 30,
1997, 1996 AND 1995 (Amounts in Thousands, Except Per Share Data)
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
NOTES
RECEIVED CUMULATIVE
ADDITIONAL FROM FOREIGN
COMMON PAID-IN RETAINED TREASURY ISSUANCE OF CURRENCY STOCKHOLDERS'
STOCK CAPITAL EARNINGS STOCK COMMON STOCK TRANSLATION EQUITY, NET
<S> <C> <C> <C> <C> <C> <C> <C>
Balance, June 30, 1994 $ 704 $ 3,805 $ 27,008 $ (7) $ (269) $ 31,241
Net income 1,185 1,185
Cash dividends ($0.645 per share) (457) (457)
Exercise of employee stock
options for notes receivable 4 156 (160)
Purchase of treasury stock (482) 32 (450)
Reduction of notes receivable 94 94
----- ------- -------- -------- ------ ------ --------
Balance, June 30, 1995 708 3,961 27,736 (489) (303) 31,613
Net income 7,820 7,820
Cash dividends ($2.10 per share) (1,457) (1,457)
Exercise of employee stock options 3 125 128
Purchase of treasury stock (632) (632)
Reduction of notes receivable 53 53
Adjustment for foreign currency
translation $ 25 25
----- ------- -------- -------- ------ ------ --------
Balance, June 30, 1996 711 4,086 34,099 (1,121) (250) 25 37,550
Net loss (5,843) (5,843)
Cash dividends ($1.50 per share) (1,007) (1,007)
Exercise of employee stock options
for notes receivable 3 125 (128)
Issuance of common stock 10 (8) 2
Purchase of treasury stock (2,054) (2,054)
Reduction of notes receivable 126 126
Adjustment for foreign currency
translation (176) (176)
----- ------- -------- -------- ------ ------ --------
Balance, June 30, 1997 $ 714 $ 4,221 $ 27,249 $ (3,175) $ (260) $ (151) $ 28,598
===== ======= ======== ======== ====== ====== ========
</TABLE>
See notes to consolidated financial statements.
-5-
<PAGE> 8
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED JUNE 30, 1997, 1996 AND 1995
(Amounts in Thousands)
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
1997 1996 1995
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ (5,843) $ 7,820 $ 1,185
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
Minority interest 152 193 435
Depletion, depreciation and amortization 19,955 19,471 12,584
Write-off of deferred financing costs 4,363
Gain on sale of assets (8,304) (3,934) (279)
Deferred income taxes (2,534) 1,518 3,437
Exploration and impairment 10,121 6,756 281
Provision for losses on accounts receivable 2,102 1,800
Other, net (2,319) (2,447) (3,049)
--------- --------- ---------
17,693 31,177 14,594
CHANGES IN ASSETS AND LIABILITIES:
Accounts receivable 1,407 (17,288) (3,118)
Gas in storage (353) 3,154 654
Income taxes receivable 1,850 1,723 1,920
Prepaid and other assets (3,014) 6,155 (1,021)
Accounts payable and other current liabilities (5,905) 4,081 1,061
Funds held for future distribution 823 (1,946) 1,185
Overrecovered gas costs (2,128) (8,741)
Other (849) (1,221) (1,255)
--------- --------- ---------
Net cash provided by operating activities 9,524 17,094 14,020
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment (26,376) (39,445) (20,036)
Acquisition of A&W, net of cash acquired (73,190)
Proceeds from sale of oil and gas properties 1,114 17,426 413
Proceeds from sale of limited partnership interest 11,250
Notes receivable (1,556) (804) 373
--------- --------- ---------
Net cash used in investing activities (15,568) (22,823) (92,440)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt 271,000 250,998 254,386
Principal payments on long-term debt (255,854) (218,352) (157,568)
Short-term borrowings, net 7,332 (27,203)
Purchase of treasury stock (common stock) (2,054) (632) (450)
Dividends (1,007) (1,199) (618)
Other equity transactions 299 109 (166)
Deferred financing costs (7,055) (3,919) (4,953)
--------- --------- ---------
Net cash provided by (used in) financing activities 12,661 (198) 90,631
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents 6,617 (5,927) 12,211
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR 14,197 20,124 7,913
--------- --------- ---------
CASH AND CASH EQUIVALENTS, END OF YEAR $ 20,814 $ 14,197 $ 20,124
========= ========= =========
</TABLE>
See notes to consolidated financial statements.
-6-
<PAGE> 9
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED JUNE 30, 1997, 1996 AND 1995
- --------------------------------------------------------------------------------
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"). The Company is an independent
integrated energy company that, through its subsidiaries, is primarily
engaged in operating a natural gas distribution system in West Virginia
and oil and gas operations in West Virginia and Pennsylvania. The Company
also is engaged in the exploration and production of oil and natural gas
in other parts of the United States, primarily in the Rocky Mountains, and
New Zealand. All references to the "Company" include Energy Corporation of
America and its consolidated subsidiaries.
Natural Gas Distribution System - The Company operates, through its
wholly-owned subsidiary Mountaineer Gas Company ("Mountaineer"), a natural
gas distribution system in West Virginia. Mountaineer provides natural gas
sales, transportation and distribution service to residential, commercial,
industrial and wholesale customers. As a public utility, Mountaineer is
subject to regulation by the West Virginia Public Service Commission
("WVPSC").
Oil and Gas Exploration, Development, Production and Marketing - The
Company, primarily through its subsidiary Eastern, is engaged in
exploration, development and production, transportation and marketing of
natural gas primarily within the Appalachian Basin in West Virginia,
Pennsylvania and Ohio. The Company owns all of the voting common shares of
Eastern, while certain officers and stockholders of the Company ("minority
interest") own non-voting common shares representing less than five
percent of all Eastern common shares.
The Company, through its wholly-owned subsidiaries Westech Energy
Corporation ("Westech"), Westech Energy New Zealand Limited ("WENZL") and
Westside Acquisition Corporation ("Westside"), is also engaged in the
exploration for and production of oil and natural gas primarily in the
Rocky Mountains and New Zealand.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The following is a summary of the significant accounting policies followed
by the Company.
Principles of Consolidation- The consolidated financial statements include
the accounts of the Company; Eastern and its subsidiaries; Eastern Systems
Corporation ("ESC") and its wholly-owned subsidiary, Mountaineer and its
subsidiary; Westech, and WENZL and its investment in certain New Zealand
oil and gas exploration joint ventures. 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 except gas sales between Eastern and
Mountaineer, a regulated utility.
-7-
<PAGE> 10
The Company's wholly-owned subsidiary, Westside, owned an 80% interest in
a limited partnership Westside Operating Partnership LP ("WOPLP") until
the end of March 1997 (see Note 3). This investment had been consolidated
prior to March 31, 1997 (see Note 11).
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 included in operations.
The provision for depreciation of Mountaineer's utility plant is based on
a composite straight-line method. The average composite depreciation rate
was 3.77% and 3.71% for 1997 and 1996, respectively. Mountaineer's
property, plant and equipment includes capitalized overhead for payroll
related costs and administrative and general expenses, as well as an
allowance for funds used during construction ("AFUDC") of approximately
$61,500 and $49,600 for the years ended June 30, 1997 and 1996. AFUDC is
an accounting procedure that capitalizes the cost of funds used to finance
utility construction projects as part of utility plant on the balance
sheet and credits the cost as a non-cash item on the income statement.
During the years ended June 30, 1997 and 1996 this amount related only to
debt financing in accordance with WVPSC policies.
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 30 years.
Repairs and maintenance costs are charged against income as incurred;
significant renewals and betterments are capitalized. Gains or losses
related to retirement of utility property, net of any salvage and cost of
removal are credited or charged to accumulated depreciation. Gains and
losses on dispositions of other property, equipment, pipelines and
buildings are included in operations.
At June 30, 1997 and 1996 property, plant and equipment consisted of the
following (in thousands):
<TABLE>
<CAPTION>
1997 1996
<S> <C> <C>
Oil and gas properties $ 200,449 219,518
Utility plant 160,756 151,699
Other property and equipment 25,188 26,516
Pipelines 17,069 16,670
--------- ---------
403,462 414,403
Less accumulated depletion, depreciation and amortization (89,491) (74,610)
--------- ---------
Net property, plant and equipment $ 313,971 339,793
========= =========
</TABLE>
-8-
<PAGE> 11
Long-Lived Assets - In March 1995, Statement of Financial Accounting
Standards ("SFAS") No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of," was issued. The
standard requires all companies to assess long-lived assets and assets to
be disposed of for impairment and requires rate-regulated companies to
write-off regulatory assets to earnings whenever those assets no longer
meet the criteria for recognition of a regulatory asset as defined by SFAS
No. 7l, "Accounting for the Effects of Certain Types of Regulation."
During 1997, the Company adopted this statement and determined that no
impairment loss needed to be recognized for applicable assets.
Gas in Storage - Gas in storage is stated at the lower of average cost or
market value.
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 balance sheet accounts using
current exchange rates in effect at the balance sheet date and for revenue
and expense accounts using an average exchange rate during the period. The
cumulative translation adjustment is included in stockholder's equity.
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."
Gas Delivery Obligation - Gas delivery obligation represents deferred
revenues on gas sales where the Company has received an advance payment.
The Company recognizes the actual gas sales revenue in the period the gas
delivery takes place.
Revenues and Purchased Gas Costs - Utility gas sales and transportation
revenues included in income are based on amounts billed to customers on a
cycle basis and estimated amounts for gas delivered but unbilled at the
end of each accounting period.
Prior to November 1, 1995, Mountaineer recognized utility gas purchased
based on the amount billed to customers through a purchased gas adjustment
clause ("PGA"). The difference between amounts billed and actual gas costs
incurred were recognized as over/underrecovered gas costs. Effective
November 1, 1995, the PGA was temporarily suspended through October 31,
1998 in accordance with a Joint Stipulation and Agreement for Settlement
(the "Agreement") between Mountaineer and WVPSC. Accordingly, beginning
November 1, 1995, gas costs are expensed as incurred and the rates charged
to customers are not adjusted to reflect changes in the cost of gas. In
accordance with the Agreement, the estimated overrecovered balance at
October 31, 1995 of $12,000,000 is to be amortized over a three-year
period beginning November 1, 1995. For the years ended June 30, 1997 and
1996, the Company amortized to cost of gas $4,000,000 and $2,667,000,
respectively. At October 31, 1995, the actual overrecovered gas cost
balance was determined to be $12,682,000. The amount in excess of
$12,000,000 and certain transportation revenues, storage balancing fees
and standby charges are being deferred as authorized by the WVPSC and will
be addressed in Mountaineer's next general rate case proceeding (see Note
17).
Oil and gas sales are recognized as income when the oil or gas is produced
and sold.
-9-
<PAGE> 12
STOCK COMPENSATION _ In October 1995, SFAS No. 123, "Accounting for
Stock-Based Compensation," was issued. As permitted under SFAS No. 123,
the Company has elected to continue to measure compensation costs for
stock-based employee compensation plans as prescribed by Accounting
Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees." Stock compensation expense calculated under Accounting
Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees"
is not materially different than that calculated under SFAS No. 123,
"Accounting for Stock-Based Compensation."
HEDGING ACTIVITIES - The Company periodically hedges a portion of its oil
and gas production through swap agreements. The purpose of the hedges is
to provide a measure of stability in the volatile environment of oil and
gas prices. The Company recognizes gains and losses in the swap agreements
at the time the hedged volumes are sold.
The Company enters into interest rate swap agreements to manage exposure to
changes in interest rates. The transactions generally involve the exchange
of fixed and floating interest payment obligations without the exchange of
underlying principal amounts. The net effect of interest rate swap
activity is reflected as an increase or decrease in interest expense. Any
gains on termination of interest rate swap agreements that were marked to
market are included in other income. In addition to the financial risk
that will vary during the life of these swap agreements in relation to the
maturity of the underlying debt and market interest rates, the Company is
subject to credit risk exposure from nonperformance of the counterparties
to the swap agreements.
EARNINGS PER SHARE OF COMMON STOCK - Earnings per share of common stock is
computed by dividing net income attributable to the shares of common stock
by the weighted average number of common shares and common share
equivalents outstanding during the reporting period. The number of
equivalent shares was computed using the treasury stock method which
assumes that the increase in the number of shares is reduced by the number
of shares which could have been repurchased by the Company with proceeds
from the exercise of options (which were assumed to have been made at the
average market price of the common shares during the reporting period).
Fully diluted earnings per share and earnings per share as computed under
the provisions of the newly issued accounting statement (SFAS No. 128,
"Earnings per Share") regarding earnings per share are no different than
primary earnings per share because of minimal company stock equivalents.
USE OF ESTIMATES - The preparation of financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date
of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from
those estimates.
The Company's financial statements are based on a number of significant
estimates including oil and gas reserve quantities which are the basis for
the calculation of depletion, depreciation, amortization and impairment of
oil and gas properties. Management emphasizes that reserve estimates are
inherently imprecise. In addition, utilization of tax credit
carryforwards, in part, is based on estimates of future taxable income.
The Company records certain utility assets and liabilities in accordance
with SFAS No. 71. If the Company were required, for any reason, to
terminate application of SFAS No. 71 for its regulated operations, all
regulatory assets and liabilities would be recognized in the income
statement at that time. Such amounts are primarily related to future
amounts recoverable for income taxes (see Note 6).
-10-
<PAGE> 13
CONCENTRATION OF CREDIT RISK - The Company maintains its cash accounts
primarily with a single bank and invests cash in money market accounts,
which the Company believes to have minimal risk. As operator of jointly
owned oil and gas properties, the Company sells oil and gas production to
numerous U.S. oil and gas purchasers, and pays vendors on behalf of joint
owners for oil and gas services. Both purchasers and joint owners are
located primarily in the northeastern United States. The risk of
nonpayment by the purchasers or joint owners is considered minimal. The
Company as owner of a utility, has receivables from both residential and
commercial customers who are located in West Virginia. The risk of
significant nonpayment by the utility customers is considered minimal.
ENVIRONMENTAL CONCERNS - The Company is continually taking actions it
believes necessary in its operations to ensure conformity with applicable
federal, state and local environmental regulations. As of June 30, 1997,
the Company has not been fined or cited for any environmental violations,
which would have a material adverse effect upon capital expenditures,
earnings or the competitive position of the Company.
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION - Supplemental cash flow
information for the years ended June 30, 1997, 1996 and 1995 is as follows
(in thousands):
<TABLE>
<CAPTION>
1997 1996 1995
<S> <C> <C> <C>
Cash paid for:
Interest (net of capitalized interest of $323,
$630 and $642 in 1997, 1996 and 1995, respectively) $ 19,921 $ 15,207 $ 7,861
Income taxes, net of amounts refunded (1,142) 2,440 275
</TABLE>
3. ACQUISITIONS AND DISPOSITIONS
ALLEGHENY & WESTERN ENERGY CORPORATION - On June 23, 1995, the Company
acquired 100% of the common stock of Allegheny & Western Energy Corporation
("A&W") and its wholly-owned subsidiary Mountaineer in a business
combination accounted for as a purchase effective June 30, 1995 with all
operations consolidated on a prospective basis. The business of A&W
consisted of Mountaineer, a regulated public gas utility, ownership
interests in oil and gas wells, undeveloped acreage, pipeline and gathering
systems, well operating rights, marketing company assets and certain other
assets. The total purchase price for this acquisition was approximately
$95.3 million, which was allocated based on estimates of relative fair
value as follows (in thousands):
<TABLE>
<S> <C>
Working capital $ 13,139
Property, plant, and equipment 160,921
Other noncurrent assets 19,147
Noncurrent liabilities assumed (97,862)
---------
Purchase of A&W 95,345
Less:
Accrual of acquisition costs (5,361)
Cash acquired (16,794)
---------
Net cash used to acquire A&W $ 73,190
=========
</TABLE>
-11-
<PAGE> 14
In connection with the acquisition, the Company recorded liabilities of
approximately $2.1 million primarily related to estimated payments
associated with disposing of certain nonessential assets held for sale as
well as severance payments. Approximately $209,000 and $1.6 million was
charged against these liabilities in the years ended June 30, 1997 and
1996, respectively.
EASTERN PRODUCING LIMITED PARTNERSHIP - In November 1995, the Company sold
interests in certain producing natural gas properties for total cash
consideration of $17,360,000 realizing a gain on sale of $3,269,000. The
Company contributed its remaining interest in these properties in exchange
for a general partner interest in the partnership that acquired the
properties, representing a 1% interest until "payout" (as defined), at
which time the Company's interest increases to 49%.
WESTSIDE OPERATING PARTNERSHIPS LP - In March 1997, the Company exchanged
warrants held representing a 30% ownership interest of a third party for a
30% interest in a newly formed oil and gas limited liability company
("LLC"), the successor to WOPLP. The LLC redeemed the Company's previous
interest and purchased certain oil and gas properties, paying the Company
$11,250,000 plus a $1,500,000 variable rate note with certain conversion
options and distributing certain WOPLP oil and gas properties and real
estate to the Company. The Company recognized a gain of $7,800,000 on the
transaction and its remaining interest in LLC, $296,048, is included in
other assets at June 30, 1997.
4. RISK MANAGEMENT
NATURAL GAS HEDGES - The Company is a party to oil and natural gas swaps in
the normal course of business to reduce its exposure to fluctuations in the
price of oil and natural gas. These instruments involve, to varying
degrees, elements of market and credit risk in excess of the amount
recognized in the consolidated balance sheets.
As of June 30, 1997, the Company had natural gas swap agreements totaling a
notional quantity of approximately 16.7 MMBTU per day through October 31,
1997 and 2.7 Mmbtu per day through October 31, 1998. At June 30, 1997, the
market value of these swaps is estimated to be a loss of $46,000, the net
amount the Company would have to pay to terminate the swap agreements.
For the years ended June 30, 1997, 1996 and 1995 the Company recognized a
net gain (loss) on its oil and natural gas hedging activities of $265,000,
($388,000), and $694,000, respectively.
Mountaineer is party to certain fixed price call options for the purchase
of gas to mitigate Mountaineer's exposure to fluctuations in gas prices.
At June 30, 1997, the face amount of fixed price call options is $9,405,000
and they have a fair value of $9,660,000. Mountaineer accounts for the
cost of the call options as prepaid gas expense, $1,342,000 at June 30,
1997, that will be charged to cost of gas when the call option is exercised
and the gas is delivered or the option expires.
INTEREST RATE HEDGES - Effective September 30, 1996, the Company entered
into an interest rate cap agreement and an interest rate collar agreement,
for purposes other than trading, to reduce the potential impact of changes
in interest rates on its floating rate long-term debt. Realized gains and
losses on the agreements are recognized in interest expense as settlement
occurs. Amortization of the cap premium is recognized in interest expense
on a straight line basis over the life of the cap. The interest rate cap
and collar agreements have a combined notional principal amount of $60
million and an estimated market value, the payment the Company would
receive to terminate these agreements, of approximately $1,000 as of June
30, 1997. There were no payments made or received under these agreements
for the years ended June 30, 1997.
-12-
<PAGE> 15
5. DEBT
LONG-TERM DEBT - At June 30, 1997 and 1996 long-term debt consisted of the
following (in thousands):
<TABLE>
<CAPTION>
1997 1996
<S> <C> <C>
ECA senior subordinated notes, interest at 9.5% payable
semi-annually, due May 15, 2007 $ 200,000
Eastern revolving credit facility $ 150,000
Westside revolving facility 19,500
ESC senior secured note, interest at 10.75% payable
quarterly, due October 1, 2005 35,000
Mountaineer unsecured senior notes, interest at 7.59% payable
semi-annually, due October 1, 2010 60,000 60,000
Installment notes payable, collateralized by deeds of trust,
at interest rates ranging from 7% to 8%, respectively 144 198
--------- ---------
260,144 264,698
Less current portion (55) (10,051)
--------- ---------
$ 260,089 $ 254,647
========= =========
</TABLE>
The Company's various debt agreements contain certain restrictions and
conditions among which are limitations on indebtedness, funding of certain
subsidiaries, dividends and investments, and certain tangible net worth and
debt and interest coverage ratio requirements. The agreements require the
Company to maintain certain financial conditions, including a minimum net
worth, restriction on funded debt and restrictions on the amount of
dividends which can be declared. As of June 30, 1997, Mountaineer has
approximately $16.1 million available for declaration of dividends under
the debt covenants.
The scheduled maturities of the Company's long-term debt at June 30, 1997
for each of the next five years and thereafter are as follows (in
thousands):
<TABLE>
<S> <C>
JUNE 30,
1998 $ 55
1999 47
2000 42
2001 --
2002 3,333
Thereafter 256,667
----------
$ 260,144
==========
</TABLE>
EXTINGUISHMENT OF DEBT - In May 1997, the Company issued $200 million
senior subordinated notes using the proceeds therefrom to repay the debt at
ESC and Eastern of $35 million and $136 million, respectively. As a
result, the Company recorded an extraordinary loss of $7.86 million, net of
a tax benefit of $4.23 million.
-13-
<PAGE> 16
SHORT-TERM DEBT - Mountaineer had unsecured bank lines of credit totaling
$71 million and $70 million as of June 30, 1997 and 1996, respectively.
During the years ended June 30, 1997 and 1996, the maximum outstanding
balance was $45,064,000 and $58,064,900, respectively, and the average
daily balance was $28,499,798 and $18,176,445, respectively. The weighted
average interest rate was 6.0% and 6.3% on the balance outstanding during
the years ended June 30, 1997 and 1996, respectively.
OTHER CREDIT FACILITIES - The Company has a $50 million revolving credit
facility secured by certain properties, interest and contracts. The
interest rate is variable based on Eurodollars or other defined basis. The
annual commitment fee is .25%. As of June 30, 1997, there are no
borrowings under this facility. Eastern has outstanding a $9 million
letter of credit issued by a bank in support of Eastern's obligations under
a gas purchase contract with the royalty trust (see Note 14). The letter
of credit reduces by $3 million on June 30 of each year until its
expiration on June 30, 2000. As of June 30, 1997, no amounts have been
drawn under the letter of credit. The letter of credit agreement between
Eastern and the bank requires Eastern to maintain certain financial
covenants, including a minimum net worth and interest coverage ratio.
Eastern also has an unsecured revolving line of credit totaling $2 million.
As of June 30, 1997, no amounts were outstanding under the line of credit.
6. INCOME TAXES
The following table summarizes components of the Company's provision
(benefit) for income taxes for the years ended June 30, 1997, 1996 and 1995
(in thousands):
<TABLE>
<CAPTION>
1997 1996 1995
<S> <C> <C> <C>
Current:
Federal $ 491 $ 1,278 $ (727)
State (224) 478
------- ------- -------
Total current 267 1,756 (727)
------- ------- -------
Deferred:
Federal (4,141) (159) 3,111
State 1,607 1,677 326
------- ------- -------
Total deferred (2,534) 1,518 3,437
------- ------- -------
Total provision (benefit) for income taxes $(2,267) $ 3,274 $ 2,710
======= ======= =======
</TABLE>
-14-
<PAGE> 17
A reconciliation of the provision for income taxes computed at the
statutory rate to the provision for income taxes as shown in the
consolidated statements of operations for the years ended June 30, 1997,
1996 and 1995 is summarized below (in thousands):
<TABLE>
<CAPTION>
1997 1996 1995
<S> <C> <C> <C>
Tax expense at the federal statutory rate $(2,707) $ 4,448 $ 2,288
State taxes, net of federal tax effects (541) 806 421
Percentage depletion (228)
Section 29 tax credits (1,866) (1,129)
Increase (decrease) in valuation allowance on federal,
foreign and state deferred tax assets, net of federal benefit 2,440 1,161
Change in estimate (1,178)
Other, net 407 (834) 229
------- ------- -------
Provision (benefit) for income taxes $(2,267) $ 3,274 $ 2,710
======= ======= =======
</TABLE>
In 1995, the Company estimated that it would carry back its 1995 tax loss
and realize the tax benefit based on the alternative minimum tax rate.
During 1996, management decided to carry forward this loss, at regular tax
rates, which generated a $1.2 million tax benefit in 1996.
-15-
<PAGE> 18
Components of the Company's federal and state deferred tax assets and
liabilities, as of June 30, 1997 and 1996 are as follows (in thousands):
<TABLE>
<CAPTION>
1997 1996
FEDERAL STATE TOTAL FEDERAL STATE TOTAL
------------------------------------ -----------------------------------
<S> <C> <C> <C> <C> <C> <C>
Deferred tax assets:
Overrecovered gas costs $ 3,281 $ 869 $ 4,005 $ 707
Bad debt allowance 597 158 660 118
Deferred compensation and profit sharing 1,939 513 1,491 267
Other postretirement benefit and pension
obligation 2,785 737 2,773 489
Tax credits and carryforwards, federal 16,804 12,899
Tax credit and carryforwards, state 12,623 15,238
Other long-term obligations 1,412 374 1,272 234
Other 5,727 136 1,720 416
-------- -------- -------- --------
Total deferred tax assets 32,545 15,410 24,820 17,469
-------- -------- -------- --------
Deferred tax liabilities:
Property, plant and equipment (51,739) (13,043) (51,905) (9,789)
Federal income tax on state tax credits (4,292) (5,384)
Other liabilities (1,885) (500) (434) (345)
-------- -------- -------- --------
Total deferred tax liabilities (57,916) (13,543) (57,723) (10,134)
-------- -------- -------- --------
Valuation allowance (635) (4,572) (4,432)
-------- -------- -------- --------
Net deferred income tax asset (liability) (26,006) (2,705) (32,903) 2,903
-------- -------- -------- --------
Less current deferred tax asset 2,615 692 $ 3,307 4,791 1,546 $ 6,337
-------- -------- ======== -------- -------- ========
Long-term deferred tax asset (liability) $(28,621) $ (3,397) $(32,018) $(37,694) $ 1,357 $(36,337)
======== ======== ======== ======== ======== ========
</TABLE>
-16-
<PAGE> 19
At June 30, 1997, the Company has the following federal and state tax
credits and carryforwards (in thousands):
<TABLE>
<CAPTION>
YEAR OF
TAX CREDITS OR CARRYFORWARDS AMOUNT EXPIRATION
<S> <C> <C>
AMT tax credits $ 10,036 None
Investment tax credits 4,122 None
Net operating loss carryforwards 2,646 2017
---------
Total federal credits $ 16,804
=========
West Virginia tax credits $11,762
West Virginia net operating loss carryforwards 861
---------
Total state credits and carryforwards $ 12,623
=========
</TABLE>
The Company is eligible for relocation incentives taken in the form of tax
credits from West Virginia. The incentive amounts are based upon
investments made and jobs created in that state. Tax credits generated by
the Company are used primarily to offset the payment of severance, property
and state income taxes. Based on existing future taxable temporary
differences and projections of future West Virginia severance, property and
state income taxes, management has provided a valuation allowance for that
portion of the credits not expected to be utilized.
Included in other long-term assets as of June 30, 1997 and 1996 is a net
regulatory asset recorded by Mountaineer in accordance with state utility
ratemaking practices related to future amounts recoverable for income taxes
of $11.6 million and $10.6 million, respectively.
7. EMPLOYEE BENEFIT PLANS
The Company and certain operating subsidiaries, have a Profit
Sharing/Incentive Stock Plan (the "Plan") for the stated purpose of
expanding and improving profits and prosperity and to assist the Company in
attracting and retaining key personnel. The Plan is noncontributory, and
its continuance from year to year is at the discretion of the Board of
Directors. The annual profit sharing pool is based on calculations set
forth in the Plan. One-half of the pool is generally paid to eligible
employees within 120 days of the end of the fiscal year and one-half is
deferred to the following year. Generally, to be eligible to participate,
an employee must have been continuously employed for two or more years;
however employees with less than two years of employment may participate
under certain circumstances. Additionally, Eastern participants may elect
to receive their profit sharing award in the form of nonvoting and
nontransferable common stock of Eastern, subject to the applicable terms
and conditions of the Plan document. The Company recognized $1.1 million
and $3.1 million of employee benefit expense during the years ended June
30, 1997 and 1996, respectively. No expense was recognized in the year
ended June 30, 1995.
For certain subsidiaries, the Company sponsors a Section 401(k) plan
covering all full-time employees who wish to participate. The Company's
contributions, which are principally based on a percentage of the employee
contributions, and charged against income as incurred, totaled $140,300,
$145,000 and $150,000 for the years ended June 30, 1997, 1996 and 1995,
respectively.
-17-
<PAGE> 20
8. PENSION PLAN
Mountaineer sponsors a Retirement Income Plan (the "Pension Plan") which
covers substantially all qualified Mountaineer employees 21 years of age
and over. Employees become fully vested upon completion of five years of
credited service, as defined. Retirement income is based on credited years
of service and the employees' level of compensation, as defined. The
Pension Plan is subject to the provisions of the Employee Retirement Income
Security Act of 1974 ("ERISA"). The determination of contributions is made
in consultation with the Pension Plan's actuary and is based upon
anticipated earnings of the Pension Plan, mortality and turnover
experience, the funded status of the Pension Plan and anticipated future
compensation levels. Mountaineer's funding policy is to be in compliance
with ERISA guidelines and to make annual contributions to the Pension Plan
to assure that all employees' benefits will be fully provided for by the
time they retire.
The following table sets forth the Pension Plan's funded status and amounts
recognized in the consolidated balance sheets at the dates shown, as
determined by an independent actuary (in thousands):
<TABLE>
<CAPTION>
1997 1996
<S> <C> <C>
Actuarial present value of benefit obligations:
Accumulated benefit obligation, including vested benefits of
$25,587 and $25,198 at June 30, 1997 and 1996, respectively $(27,456) $(27,120)
======== ========
Projected benefit obligations for service rendered to date $(29,777) $(30,507)
Pension Plan assets at fair value 24,954 23,152
-------- --------
Projected benefit obligation in excess of plan assets (4,823) (7,355)
Unrecognized net loss from past experience (77) 2,444
-------- --------
Accrued pension cost (included in other long-term obligations) $ (4,900) $ (4,911)
======== ========
</TABLE>
Net pension cost for the years ended June 30, 1997 and 1996 as determined
by an independent actuary, included the following components (in
thousands):
<TABLE>
<CAPTION>
1997 1996
<S> <C> <C>
Service cost $ 589 $ 638
Interest cost 2,205 2,083
Actual return on plan assets (3,241) (2,147)
Net amortization and deferral 1,453 366
------- -------
Net periodic pension cost 1,006 940
Amount capitalized as construction cost (176) (173)
------- -------
Amount charged to expense $ 830 $ 767
======= =======
</TABLE>
The expected long-term rate of return used in the calculation was 8% and
8.25% for the years ended June 30, 1997 and 1996. The weighted average
discount rate used in the calculations was 7.75% for both
-18-
<PAGE> 21
fiscal years 1997 and 1996. The expected average increase in future
compensation levels was 4.0% and 4.5% for the years ended June 30, 1997 and
1996, respectively.
9. POSTRETIREMENT MEDICAL AND LIFE INSURANCE BENEFITS
Mountaineer provides certain medical and life insurance benefits for
retired employees. Substantially all of Mountaineer's employees may become
eligible for these benefits if they choose to retire after reaching age 55
while working for Mountaineer and are provided until age 65. Life
insurance benefits of approximately two times annual salary are provided
while an employee is active and working at Mountaineer. On the date of an
employee's retirement and on the date the employee reaches age 70, life
insurance benefits decrease to approximately 80% and 40% of annual salary,
respectively. These benefits are provided to retirees who meet the service
requirements of 10 continuous years of service prior to retirement at age
55 or 5 continuous years of service prior to retirement at age 65. The
plan is unfunded.
The following table sets forth the postretirement medical and life
insurance plans' funded status and amounts recognized in the consolidated
balance sheets, as determined by an independent actuary (in thousands):
<TABLE>
<CAPTION>
1997 1996
<S> <C> <C>
Accumulated postretirement benefit obligation:
Retirees $3,788 $3,198
Fully eligible active participants 1,571 1,952
Other active employees 1,634 1,640
------ ------
Total accumulated postretirement benefit obligation 6,993 6,790
Unrecognized actuarial gain 243 274
------ ------
Accrued postretirement benefit liability (included in other
long-term liabilities) $7,236 $7,064
====== ======
</TABLE>
Net periodic postretirement benefit cost for years then ended June 30, 1997
and 1996, as determined by an independent actuary, included the following
components (in thousands):
<TABLE>
<CAPTION>
1997 1996
<S> <C> <C>
Service cost-benefits attributable to service during the period $ 376 $ 362
Interest cost on the accumulated postretirement benefit obligation 499 514
----- -----
Net periodic postretirement benefit cost 875 876
Amount capitalized as construction cost (203) (220)
----- -----
Amount charged to expense $ 672 $ 656
===== =====
</TABLE>
The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation was 9.5% and 10.0% in the years ended
June 30, 1997 and 1996, declining gradually to 5.5% in 2005 and remaining
at that level thereafter. The health care cost trend rate assumption has a
significant effect on the amounts reported. A one percentage point
increase in the assumed health care
-19-
<PAGE> 22
cost trend rate would increase the aggregate service and interest cost by
$52,500 for the year ended June 30, 1997 and accumulated postretirement
benefit obligation as of June 30, 1997 by $279,000. The weighted average
discount rate used in determining the accumulated postretirement benefit
obligation was 7.75% for the years ended June 30, 1997 and 1996. The
average assumed annual rate of salary increase for the life insurance
benefit plan was 4.0% in 1997 and 5.0% in 1996.
As part of a WVPSC rate order dated October 29, 1993, the WVPSC ruled that
the permitted rate recovery mechanism for other post retirement benefits
would be a modified accrual method. The modified accrual method allows for
the recovery of current service costs on an accrual basis and recovery of
the transition obligation on a cash basis.
10. COMMON STOCK
VOTING COMMON STOCK - In May 1995, the Company was reincorporated in the
State of West Virginia. As part of this reincorporation, each outstanding
share of then existing no-par value common stock was converted to one share
of $1 par value common stock.
The Company has an agreement with a stockholder covering the sale or
disposition of stock that provides the stockholder cannot sell stock
without first offering such shares to the Company. Under certain
circumstances, the Company would be required to purchase the related stock
if not previously tendered to the Company or otherwise sold or disposed of
in accordance with the provisions of the agreement.
TREASURY STOCK - The Company has 47,668 and 20,438 shares of treasury
stock, which are carried at cost, at June 30, 1997 and 1996, respectively.
The Company purchased 27,230 and 11,975 shares of common stock in the years
ended June 30, 1997 and 1996, respectively.
STOCK OPTIONS - In 1994, the Company created an incentive stock option plan
(the "Stock Option Plan"). Under the Stock Option Plan, options vest
annually in 25% increments from January 1, 1994 to December 31, 1997, and
are exercisable at $40 per share. However, if any of the optionees'
employment with the Company is terminated within four years, the optionee
must resell any exercised options back to the Company at $40 per share.
A summary of the Company's Option Plan as of June 30, 1997, 1996 and 1995,
and the changes during the years then ended is presented below:
<TABLE>
<CAPTION>
1997 1996 1995
------------------ ------------------ -----------------
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning of year 6,400 $40.00 9,600 $40.00 12,800 $40.00
Exercised 3,200 40.00 3,200 40.00 3,200 40.00
------- ------ ------- ------ ------ ------
Outstanding at end of year 3,200 $40.00 6,400 $40.00 9,600 $40.00
======= ====== ======= ====== ====== ======
Options exercisable at year end 3,200 3,200 3,200
======= ======= ======
</TABLE>
The option exercises above were paid for in the form of notes, which have
been charged against equity until collected.
-20-
<PAGE> 23
11. UNCONSOLIDATED AFFILIATE
The Company's investment in the LLC at June 30, 1997 is accounted for under
the equity method (see Note 3). Summarized financial information for the
LLC at June 30, 1997 is as follows (in thousands):
<TABLE>
<S> <C>
Current assets $ 2,088
Oil and gas properties 30,485
Other assets 1,554
-------
Total assets $34,127
=======
Current liabilities $ 2,372
Long-term debt 30,500
Other liabilities 135
Equity 1,120
-------
Total liabilities and equity $34,127
=======
</TABLE>
The LLC began operations on March 30, 1997. Results of operations were
immaterial for the three months ended June 30, 1997.
12. OPERATING LEASES
The Company has noncancelable operating lease agreements for the rental of
office space, computer and other equipment. Certain of these leases
contain purchase options or renewal clauses. Rental expense for operating
leases was approximately $1.3, $1.2 and $1.4 million for the years ended
June 30, 1997, 1996 and 1995, respectively.
At June 30, 1997 future minimum lease payments for each of the next five
years and thereafter are as follows (in thousands):
<TABLE>
<S> <C>
1998 $1,173
1999 966
2000 951
2001 926
2002 710
Thereafter 1,144
------
$5,870
======
</TABLE>
13. RELATED PARTY TRANSACTIONS
Eastern has entered into a rental arrangement for the building used as its
headquarters from a partnership in which certain officers are partners.
Rent payments totaled approximately $336,000, $300,000 and $415,000 for the
years ended June 30, 1997, 1996 and 1995, respectively.
Mountaineer purchases a portion of its gas supply requirements from a
subsidiary and from Eastern. The price paid for such purchases has been
approved by the WVPSC. During 1997 and 1996, Mountaineer purchased
approximately $5,297,000 and $5,342,000, respectively, from its subsidiary
and $23,225,000 and $15,258,000, respectively from Eastern. The related
revenues and expenses between Mountaineer and its subsidiary and Eastern
have not been eliminated in these financial statements due to the regulated
nature of Mountaineer. At June 30, 1997, Mountaineer has $29,359,120 of
outstanding gas purchase commitments with Eastern.
-21-
<PAGE> 24
The Company advanced funds to certain officers in 1991 and 1994, which bear
interest at 8% and are secured by non-voting common shares of Eastern.
Balances totaled $497,822 and $570,000, respectively, at June 30, 1997 and
1996 and are due in 2001.
The Company also advanced funds in 1988 to certain officers and directors
which bear interest at 8%, are secured by interests in oil and gas
properties and are payable out of net proceeds from the oil and gas
production on these properties. Balances outstanding at June 30, 1997 and
1996 totaled $960,404 and $1,012,000, respectively.
14. COMMITMENTS AND CONTINGENCIES
In 1992, Eastern entered into a 15-year gas sale and purchase agreement
with an independent power project whereby Eastern will deliver
approximately 12,000 Mcf per day to the project at a fixed price per Mcf.
The terms of the agreement provide for annual price escalations.
In 1993, the Company sold working interests in certain Appalachian gas
properties in connection with the formation of a royalty trust (the
"Trust"). A portion of the proceeds from the sale of these interests,
representing a term net profits interest, was accounted for as a production
payment. As a result, at June 30, 1997 and 1996, such proceeds totaling
$15,122,000 and $17,244,000, respectively, have been classified as deferred
trust revenue.
Certain gas production attributable to the Trust is purchased by a
wholly-owned subsidiary of the Company pursuant to a gas purchase contract,
which expires in 2013. The purchase price under the contract is based on
escalating fixed price and spot market components. To hedge the Company's
position on this contract, the Company dedicated the fixed price sales
contract with the independent power project discussed above, which has
similar prices and volumes as the fixed price component of the contract,
and purchased a floor price futures contract to cover the variable
component. The fixed price component expires on January 1, 2000. The
obligation of the subsidiary to make payments under the contract is
partially supported by a standby letter of credit with a face amount of $9
million. The letter of credit is subject to annual reductions of $3
million beginning June 30, 1996, and fully expires on June 30, 2000.
The Company has entered into an agreement whereby it funded a specified
monthly amount, through December 31, 1996, to assist in the development of
oil and gas projects by a third party. No remaining commitment exists as
of June 30, 1997. Amounts funded are accounted for as an advance and all
outstanding amounts are due on January 1, 1999. As of June 30, 1997 and
1996, the Company has $2.5 million and $2.4 million, respectively, in
long-term notes receivable relating to this agreement. In addition to the
commitment, the Company has certain other rights and options regarding the
acquisition, exploration and development of the oil and gas projects that
may be acquired as a result of this agreement.
In connection with an existing gas delivery obligation agreement, whereby
Eastern received an advance payment, a subsidiary of Eastern entered into a
credit line deed of trust which has an available balance of $9.5 and $11
million as of June 30, 1997 and 1996, respectively, to collateralize its
performance under the gas delivery obligation. This credit line deed of
trust declines at a rate of 7.5% per year.
In 1992, The Federal Energy Regulatory Commission ("FERC") issued order No.
636 et. Seq., (the "636 Orders"). The 636 Orders required substantial
restructuring of the service obligations of interstate pipelines, including
Mountaineer's pipeline suppliers. The majority of the service and
transition cost
-22-
<PAGE> 25
issues involved in the restructuring proceedings have been resolved through
settlements, which substantially reduced the originally filed impact of
restructuring. Certain other issues, including matters raised by
Mountaineer, are pending on appellate review.
On February 1, 1996, Mountaineer's largest pipeline supplier, Columbia
Transmission Corporation ("Columbia Transmission") placed increased rates
into effect pending hearing and decision by FERC. A settlement was
approved by FERC on April 17, 1997, which provided for reduced rates and
refunds. The settlement resolved all issues except for approximately $18
million annually in environmental remediation costs which Columbia
Transmission proposes to recover from its customers, including Mountaineer.
The issue has been set for hearing. In accordance with the provisions of
the settlement, Mountaineer received refunds totaling $6,142,000 on June
10, 1997. These refunds were credited against cost of gas.
On May 1, 1997, Columbia Gulf Transmission Company placed increased rates
into effect pending hearing and decision by FERC. The full amount of the
increase proposed would raise the rates paid by Mountaineer for
transmission service by approximately $0.5 million annually. Columbia
Gulf's customers, including Mountaineer, and FERC Staff have challenged all
major aspects of the proposed increase. The case is scheduled for hearing
in January 1998.
The Company is involved in various legal actions and claims arising in the
ordinary course of business. Management does not expect these matters to
have a material adverse effect on the Company's financial position.
15. FINANCIAL INSTRUMENTS
The estimated fair values of the Company's financial instruments have been
determined using appropriate market information and valuation
methodologies. Considerable judgment is required to develop the estimates
of fair value; thus, the estimates provided below are not necessarily
indicative of the amount that the Company could realize upon the sale or
refinancing of such financial instruments (in thousands):
<TABLE>
<CAPTION>
JUNE 30, 1997 JUNE 30, 1996
CARRYING FAIR CARRYING FAIR
VALUE VALUE VALUE VALUE
<S> <C> <C> <C> <C>
Assets:
Cash and cash equivalents $20,814 $20,814 $14,197 $14,197
Accounts receivable 37,923 37,923 43,802 43,802
Notes receivable 7,563 7,227 5,803 4,012
Liabilities:
Accounts payable and
accrued expenses 31,046 31,046 39,798 39,798
Current portion of long-term debt 55 55 10,051 10,051
Short-term debt 15,724 15,724 8,392 8,392
Funds held for future distribution 6,014 6,014 5,191 5,191
Long-term debt 260,089 260,850 254,647 261,196
Other long-term obligations 14,000 14,000 14,849 14,849
Interest rate hedge contracts 1 13
Oil and gas hedge contracts 46 455
</TABLE>
-23-
<PAGE> 26
The following methods and assumptions were used by the Company in
estimating the fair value of its financial instruments:
CASH AND CASH EQUIVALENTS, ACCOUNTS RECEIVABLE, ACCOUNTS PAYABLE AND FUNDS
HELD FOR FUTURE DISTRIBUTION - Due to the short-term nature of these
instruments, carrying value is estimated to approximate fair value.
NOTES RECEIVABLE - The notes receivable accrue interest at a fixed rate.
Fair value was estimated using discounted cash flows based on current
interest rates for notes with similar credit characteristics and
maturities.
SHORT-TERM DEBT AND LINE OF CREDIT - The short-term debt is borrowed on a
revolving basis at a variable interest rate, approximately market; as a
result, the carrying value approximates fair value of the outstanding debt.
Due to the short-term nature of the line of credit, carrying value
approximates fair value of the outstanding debt.
LONG-TERM DEBT - A portion of long-term debt was borrowed under a revolving
credit facility, which accrues interest at variable rates; as a result,
carrying value approximates fair value. The remaining portion of the
Company's long-term debt is comprised of fixed rate facilities; for this
portion, fair value was estimated using discounted cash flows based upon
the Company's current borrowing rates for debt with similar maturities.
OTHER LONG-TERM OBLIGATIONS - The other long-term obligations were borrowed
under agreements, which accrue interest at variable rates, approximately
market; as a result, carrying value approximates fair value.
HEDGING CONTRACTS - Hedging contract fair values were estimated based on
quoted prices for similar contracts at June 30, 1997.
16. CONTRACT SETTLEMENT
In 1991, Columbia Transmission and Columbia Gas Systems, Inc. ("Columbia")
filed for protection under Chapter 11 of the Bankruptcy Code. The
settlement relates to damages paid by Columbia Gas as a result of its
rejection in bankruptcy of certain gas purchase contracts. As part of
Columbia's amended plan of reorganization, the Company recorded contract
settlement revenue of $8.8 million in 1995.
17. RATE MATTERS
In June 1995, Mountaineer agreed to a Joint Stipulation and Agreement for
Settlement (the "Agreement") with various parties, including the staff of
WVPSC and the Consumer Advocate Division, regarding a January 1995 base
rate filing, as well as Mountaineer's upcoming PGA filing and a tariff
filing concerning primarily telemetering requirements for transportation
customers. The Agreement allowed for a $4 million increase in base rates,
with the portion of the increase allocable to sales customers to be offset
by the amortization of the overrecovered cost of gas balance existing as of
October 31, 1995 over a three-year moratorium period beginning November 1,
1995. A final order was issued on January 10, 1996.
The Agreement stipulates that during the three-year moratorium,
Mountaineer's annual PGA filing with the WVPSC will be temporarily
suspended and the deferred accounting for purchased gas costs will not be
in effect. Consequently, Mountaineer has assumed the risk of any changes
in interstate pipeline rates
-24-
<PAGE> 27
and charges during the moratorium period. It is the intent of the
Agreement that Mountaineer be permitted to keep the benefit of, and absorb
the costs of, its decisions during the moratorium period without the
traditional review of its actions.
In June 1997, Mountaineer filed a base rate case with the WVPSC. The
filing requests additional revenues primarily to cover increasing costs.
The rate case is currently under review. A final order is expected prior
to the end of the current moratorium period and is expected to become
effective November 1, 1998.
18. INDUSTRY SEGMENTS
The following table sets forth the Company's principal industry segments
and their contribution to its revenues, operating profits, capital
expenditures and depletion, depreciation and amortization for the periods.
Also shown are the identifiable assets associated with each segment as of
the end of each year indicated (in thousands):
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30, 1997
-------------------------------------------------------
REGULATED ADJUSTMENTS
OIL AND GAS UTILITY AND
OPERATIONS OPERATIONS ELIMINATIONS CONSOLIDATED
<S> <C> <C> <C> <C>
Sales to unaffiliated customers $ 171,955 $ 173,463 $ 345,418
Intersegment 28,522 28,522
--------- --------- --------- ---------
Total revenue 200,477 173,463 -- 373,940
--------- --------- --------- ---------
Operating profit 1,963 17,100 19,063
Other income (expense) (9,344) (5,583) (14,927)
--------- --------- --------- ---------
Income (loss) before income taxes $ (7,381) $ 11,517 -- $ 4,136
========= ========= ========= =========
Depletion, depreciation and
amortization (including reduction
in the carrying amount of oil and
gas properties) $ 12,657 $ 6,387 $ 19,044
========= ========= =========
Capital expenditures $ 16,376 $ 10,023 $ 26,399
========= ========= ========= =========
Identifiable assets $ 206,715 $ 201,431 $ 408,146
========= =========
Corporate assets 26,611
---------
Total assets $ 434,757
=========
</TABLE>
-25-
<PAGE> 28
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30, 1996
---------------------------------------------------------
REGULATED ADJUSTMENTS
OIL AND GAS UTILITY AND
OPERATIONS OPERATIONS ELIMINATIONS CONSOLIDATED
<S> <C> <C> <C> <C>
Sales to unaffiliated customers $172,265 $182,929 $355,194
Intersegment 20,600 20,600
-------- -------- --------- --------
Total revenue 192,865 182,929 - 375,794
-------- -------- --------- --------
Operating profit 4,805 26,423 31,228
Other income (expense) (8,957) (10,987) (19,941)
-------- -------- --------- --------
Income (loss) before income taxes $ (4,152) $ 15,439 - $ 11,287
======== ======== ========= ========
Depletion, depreciation and
amortization (including reduction
in the carrying amount of oil and
gas properties) $ 12,053 $ 6,764 $ 18,817
======== ======== ========
Capital expenditures $ 25,968 $ 13,477 $ 39,445
======== ======== ========= ========
Identifiable assets $254,328 $198,032 $452,360
======== ========
Corporate assets 9,144
--------
Total assets $461,504
========
</TABLE>
The Company operates in two industry segments, oil and gas operations
including exploration and development, production, aggregation and
marketing of third party and Company owned oil and gas. In addition, the
Company operates a regulated local gas distribution company. Operating
profit represents revenues less costs which are directly associated with
such operations. Revenues are priced and accounted for consistently for
both unaffiliated and intersegment sales. Intersegment sales have not been
eliminated in consolidation because of the regulated nature of the gas
distribution segment.
Identifiable assets by industry segment are those assets that are used in
the Company's operations in each segment. Corporate assets are primarily
cash, cash equivalents and deferred charges.
-26-
<PAGE> 29
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
COSTS - The following tables set forth capitalized costs at June 30, 1997
and 1996, and costs incurred, including capitalized overhead, for oil and
gas producing activities for the years ended June 30, 1997, 1996, and 1995
(in thousands):
<TABLE>
<CAPTION>
1997 1996 1995
<S> <C> <C> <C>
Capitalized costs:
Proved properties $ 193,051 $ 211,309
Unproved properties 7,398 8,209
--------- ---------
Total 200,449 219,518
Less accumulated depletion, depreciation
and amortization (57,001) (52,186)
--------- ---------
Net capitalized costs $ 143,448 $ 167,332
========= =========
Company's share of equity method investee's net
capitalized costs $ 8,877
=========
Costs incurred:
Acquisition of proved properties $ 143 $ 4,318 $ 14,190
Development costs 11,649 13,470 14,345
Exploration costs 3,728 6,141 2,240
--------- --------- ---------
Total costs incurred $ 15,520 $ 23,929 $ 30,775
========= ========= =========
Company's share of equity method investee's total
costs incurred $ 115
=========
</TABLE>
RESULTS OF OPERATIONS - The results of operations for oil and gas producing
activities, excluding corporate overhead and interest costs for the years
ended June 30, 1997, 1996 and 1995 are as follows (in thousands):
<TABLE>
<CAPTION>
1997 1996 1995
<S> <C> <C> <C>
Revenues from sale of oil and gas $33,253 $31,940 $29,277
Production costs 7,337 7,793 7,555
Production taxes 1,966 1,407 1,560
Exploration and impairment 10,121 6,756 281
Depletion, depreciation and amortization 8,325 9,204 9,763
Other 612 193 435
Income tax expense 1,712 1,647 2,421
------- ------- -------
Income from oil and gas operations $ 3,180 $ 4,940 $ 7,262
======= ======= =======
Company's share of equity method investee's
income from oil and gas operations $ 311
=======
</TABLE>
-27-
<PAGE> 30
Production costs include those costs incurred to operate and maintain
productive wells and related equipment and include costs such as labor,
repairs and maintenance, materials, supplies, fuel consumed, insurance and
production taxes. In addition, production costs are net of well tending
fees, which are included in well operations revenues in the accompanying
consolidated statement of operations.
Exploration and impairment expenses include the costs of geological and
geophysical activity, unsuccessful exploratory wells and leasehold
impairment allowances.
Depletion, depreciation and amortization include costs associated with
capitalized acquisition, exploration, and development costs.
The provision for income taxes is computed at the statutory federal income
tax rate and is reduced to the extent of permanent differences which have
been recognized in the Company's tax provision, such as investment tax
credits, and the utilization of Federal tax credits permitted for fuel
produced from a non-conventional source.
RESERVE QUANTITY INFORMATION - Reserve estimates are subject to numerous
uncertainties inherent in the estimation of quantities of proved reserves
and in the projection of future rates of production and timing of
development expenditures. The accuracy of such estimates is a function of
the quality of available data and of engineering and geological
interpretation and judgment. Results of subsequent drilling, testing and
production may cause either upward or downward revisions of previous
estimates. Further, the volumes considered to be commercially recoverable
fluctuate with changes in prices and operating costs. Reserve estimates,
by their nature, are generally less precise than other financial statement
disclosures.
-28-
<PAGE> 31
The following table sets forth information for the years ended June 30, 1997,
1996 and 1995 with respect to changes in the Company's proved reserves, all of
which are in the United States.
<TABLE>
<CAPTION>
NATURAL CRUDE
GAS OIL
(MMCF) (MBBLS)
<S> <C> <C>
Proved reserves:
June 30, 1994 170,311 7,003
Revisions of previous estimates (23,726) (429)
Extensions and discoveries 4,908 974
Purchases of reserves in place 29,309 7
Production (8,984) (535)
-------- --------
June 30, 1995 171,818 7,020
Revisions of previous estimates 3,693 170
Purchases of reserves in place 7,500
Extensions and discoveries 5,950
Sales of reserves in place (19,700)
Production (9,812) (522)
-------- --------
June 30, 1996 159,449 6,668
Revision of previous estimates 331 (197)
Extensions and discoveries 13,331 545
Sales of reserves in place (1) (3,674) (5,336)
Production (9,106) (447)
-------- --------
June 30, 1997 160,331 1,233
======== ========
Proved developed reserves:
June 30, 1995 167,428 6,886
======== ========
June 30, 1996 153,232 6,668
======== ========
June 30, 1997 141,116 748
======== ========
Company's share of equity method investee's proved reserves
at June 30, 1997 3,452 4,402
======== ========
</TABLE>
(1) Includes 1,084 Mmcf of proved gas reserves and 1,554 Mbbls of proved
crude oil reserves effectively retained as a result of the Company's
30% equity investment in the LLC.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS - Estimated
discounted future net cash flows and changes therein were determined in
accordance with SFAS No. 69, "Disclosures About Oil and Gas Producing
Activities." Certain information concerning the assumptions used in
computing the valuation of proved reserves and their inherent limitations
are discussed below. The Company believes such information is essential
for a proper understanding and assessment of the data presented.
-29-
<PAGE> 32
Future cash inflows are computed by applying period-end prices of oil and
gas relating to the Company's proved reserves to the period-end quantities
of those reserves. Future price changes are considered only to the extent
provided by contractual arrangements, including futures contracts, in
existence at period-end.
The assumptions used to compute estimated future net revenues do not
necessarily reflect the Company's expectations of actual revenues or costs,
nor their present worth. In addition, variations from the expected
production rates also could result directly or indirectly from factors
outside of the Company's control, such as unintentional delays in
development, changes in prices or regulatory controls. The reserve
valuation further assumes that all reserves will be disposed of by
production. However, if reserves are sold in place, this could affect the
amount of cash eventually realized.
Future development and production costs are computed by estimating the
expenditures to be incurred in developing and producing the proved oil and
gas reserves at the end of the year, based on period-end costs and assuming
continuation of existing economic conditions.
Future income tax expenses are computed by applying the appropriate
year-end statutory tax rates and existing tax credits, with consideration
of future tax rates already legislated, to the future pretax net cash flows
relating to the Company's proved oil and gas reserves.
An annual discount rate of 10% was used to reflect the timing of the future
net cash flows relating to proved oil and gas reserves.
Information with respect to the Company's estimated discounted future net
cash flows related to its proved oil and gas reserves as of June 30, 1997,
1996 and 1995 is as follows (in thousands):
<TABLE>
<CAPTION>
1997 1996 1995
<S> <C> <C> <C>
Future cash in flows $ 473,464 $ 500,839 $ 474,249
Future production costs and development costs (172,219) (196,602) (199,598)
Future income tax expense (50,607) (48,860) (37,054)
--------- --------- ---------
Future net cash flows before discount 250,638 255,377 237,597
10% discount to present value (143,791) (145,436) (126,858)
--------- --------- ---------
Standardized measure of discounted future
net cash flows related to proved oil and gas
Reserves $ 106,847 $ 109,941 $ 110,739
========= ========= =========
Company's share of equity method investee's
standardized measure of discounted future net
cash flows $ 27,201
=========
</TABLE>
-30-
<PAGE> 33
Principal changes in the standardized measure of discounted future net cash
flows for the years ended June 30, 1997, 1996 and 1995 are as follows (in
thousands):
<TABLE>
<CAPTION>
1997 1996 1995
<S> <C> <C> <C>
Standardized measure of discounted future
net cash flows at beginning of period $ 109,941 $ 110,739 $ 126,247
Sales of oil and gas produced, net of
production costs (17,854) (16,528) (16,242)
Net changes in prices and production costs 17,395 21,717 (36,142)
Changes in production rates and other 50 (11,057) (12,515)
Extensions, discoveries and other additions,
net of future production and development
costs 12,185 3,944 6,466
Changes in estimated future development costs (7,609) (13,685) (10,453)
Development costs incurred 11,649 13,470 14,345
Revisions of previous quantity estimates (1,022) 3,120 (15,689)
Purchase of reserves in place 4,918 18,653
Sales of reserves in place (25,075) (12,919) 0
Accretion of discount 10,994 11,074 12,625
Net change in income taxes (3,807) (4,852) 23,444
--------- --------- ---------
Standardized measure of discounted
future net cash flows at end of period $ 106,847 $ 109,941 $ 110,739
========= ========= =========
</TABLE>
* * * * *
-31-
<PAGE> 34
ENERGY CORPORATION OF AMERICA SCHEDULE I
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED BALANCE SHEET INFORMATION
JUNE 30, 1997 AND 1996
(Dollars in Thousands)
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
ASSETS 1997 1996
<S> <C> <C>
CURRENT ASSETS:
Cash $ 16,192 $ 3,454
Accounts receivable, other 158 313
Accounts receivable, affiliates 18,529 8,709
Other current assets 108 207
-------- --------
Total current assets 34,987 12,683
PROPERTY, PLANT AND EQUIPMENT - Net 288 99
INVESTMENT IN SUBSIDIARIES 192,649 30,849
OTHER ASSETS 8,447
-------- --------
TOTAL $236,371 $ 43,631
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued expenses $ 2,500 $ 601
Income taxes 5,122 2,198
-------- --------
Total current liabilities 7,622 2,799
LONG-TERM LIABILITIES 200,000 3,307
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY 28,749 37,525
-------- --------
TOTAL $236,371 $ 43,631
======== ========
</TABLE>
See notes to condensed financial information.
-32-
<PAGE> 35
ENERGY CORPORATION OF AMERICA SCHEDULE I
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF OPERATIONS INFORMATION
FOR THE YEARS ENDED JUNE 30, 1997, 1996 AND 1995
(Dollars in Thousands)
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
1997 1996 1995
<S> <C> <C> <C>
COSTS AND EXPENSES:
General and administrative $ 1,913 $ 2,352 $ 1,278
Depreciation of property, plant and equipment 40 24 107
-------- -------- --------
LOSS FROM OPERATIONS (1,953) (2,376) (1,385)
INTEREST EXPENSE 2,152
OTHER (INCOME) EXPENSE (551) 1,931 (794)
-------- -------- --------
LOSS BEFORE INCOME TAXES AND EQUITY
IN EARNINGS OF SUBSIDIARIES (3,554) (4,307) (591)
BENEFIT FROM INCOME TAXES (2,565) (1,142) (356)
-------- -------- --------
LOSS BEFORE EQUITY IN EARNINGS OF
SUBSIDIARIES (989) (3,165) (235)
EQUITY IN EARNINGS (LOSSES) OF SUBSIDIARIES (4,854) 10,985 1,420
-------- -------- --------
NET INCOME (LOSS) $ (5,843) $ 7,820 $ 1,185
======== ======== ========
</TABLE>
See notes to condensed financial information.
-33-
<PAGE> 36
ENERGY CORPORATION OF AMERICA SCHEDULE I
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF CASH FLOWS INFORMATION
FOR THE YEARS ENDED JUNE 30, 1997, 1996 AND 1995
(Dollars in Thousands)
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
1997 1996 1995
<S> <C> <C> <C>
CASH FLOWS FROM OPERATIONS:
Net income (loss) $ (5,843) $ 7,820 $ 1,185
Adjustments to reconcile net income to cash
provided by (used in) operating activities:
Equity in undistributed (earnings) losses of subsidiaries 16,578 (3,429) 1,558
Depreciation and amortization 104 24 107
Changes in operating assets and liabilities 5,077 (5,824) 1,539
Other (4,634) 801 1,918
--------- --------- ---------
Net cash provided by (used in) operating activities 11,282 (608) 6,307
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Advances to subsidiaries (9,821)
Expenditures for property (229) (113) (65)
--------- --------- ---------
Net cash used in investing activities (10,050) (113) (65)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends paid (1,007) (1,457) (457)
Proceeds from issuance of debt 200,000
Contributions to capital of subsidiaries (178,378)
Deferred financing costs (7,055)
Repurchase of common stock (2,054) (632) (450)
Other 128
--------- --------- ---------
Net cash provided by (used in) financing activities 11,506 (1,961) (907)
--------- --------- ---------
INCREASE (DECREASE) IN CASH 12,738 (2,682) 5,335
CASH AT BEGINNING OF YEAR 3,454 6,136 801
--------- --------- ---------
CASH AT END OF YEAR $ 16,192 $ 3,454 $ 6,136
========= ========= =========
</TABLE>
See notes to condensed financial information.
-34-
<PAGE> 37
ENERGY CORPORATION OF AMERICA SCHEDULE I
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
NOTES TO CONDENSED FINANCIAL INFORMATION
FOR THE YEARS ENDED JUNE 30, 1997, 1996 AND 1995
- --------------------------------------------------------------------------------
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Investments in Subsidiaries - The financial statements of Energy
Corporation of America (the "Company") reflect investments in Eastern
American Energy Corporation, Eastern Systems Corporation, Westech Energy
Corporation, Westech Energy New Zealand Limited, and Westside Acquisition
Corporation ("the subsidiaries"), majority or wholly-owned subsidiaries,
using the equity method.
Income Taxes - The benefit for income taxes is based on losses recognized
for financial statement purposes determined on a separate company basis.
Deferred income taxes are recognized for the tax effects of temporary
differences between such losses and those recognized for income tax
purposes. The Company files a consolidated U.S. income tax return with its
subsidiaries.
2. CONSOLIDATED FINANCIAL STATEMENTS
Reference is made to the Consolidated Financial Statements and related
Notes of Energy Corporation of America and Subsidiaries for additional
information.
3. LONG-TERM DEBT
Information concerning debt of the Company on a consolidated basis is
disclosed in Note 5 of the Notes to Consolidated Financial Statements of
Energy Corporation of America and Subsidiaries included elsewhere herein.
The Company's $200,000,000 million in 9-1/2% senior subordinated notes are
due in 2007.
4. DIVIDENDS RECEIVED
The Company received cash dividends from its subsidiaries of $10.44, $7.56
and $2.98 million for the years ended June 30, 1997, 1996 and 1995,
respectively.
*****
-35-
<PAGE> 38
SCHEDULE II
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED JUNE 30, 1997, 1996 AND 1995
(Amounts in Thousands)
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
FOR THE YEARS
ENDED JUNE 30,
1997 1996 1995
<S> <C> <C> <C>
Balance at beginning of period $ 1,744 $ 1,141 $ 297
Charged to costs and expenses 2,102 1,800
Charged to other accounts(1) 291 844 (2)
Deductions(3) (2,477) (1,197)
------- ------- -------
Balance at end of period $ 1,660 $ 1,744 $ 1,141
======= ======= =======
</TABLE>
(1) Recoveries of accounts previously written off.
(2) Includes the beginning balance ($756) of the allowance for doubtful
accounts of Mountaineer Gas Company which was acquired by ECA at June 30,
1995.
(3) Accounts written off.
-36-
<PAGE> 39
SIGNATURES
Pursuant to the requirements of Section 13 or 15 (d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned thereunto, duly authorized, on the_______ day
of November, 1997.
ENERGY CORPORATION OF AMERICA
By: /s/ John Mork
-------------------------------------
John Mork
President and Chief Executive Officer
Pursuant to the requirements of the Securities Act of 1934, this
report has been signed below, on the _____ day of November, 1997, by the
following persons on behalf of the Registrant and in the capacities indicated.
<TABLE>
<CAPTION>
Signature Title
--------- -----
<S> <C>
/s/ Kenneth W. Brill Chairman of the Board of Directors
- ------------------------------------------
Kenneth W. Brill
/s/ John Mork President, Chief Executive Officer and Director
- ------------------------------------------ (principal executive officer)
John Mork
/s/ Joseph E. Casabona Executive Vice President and Director
- ------------------------------------------ (principal accounting officer)
Joseph E. Casabona
/s/ J. Michael Forbes Vice President and Treasurer
- ------------------------------------------ (principal financial officer)
J. Michael Forbes
/s/ Richard E. Heffelfinger Director
- ------------------------------------------
Richard E. Heffelfinger
/s/ F. H. McCullough, III Director
- ------------------------------------------
F. H. McCullough, III
/s/ Julie Mork Director
- ------------------------------------------
Julie Mork
</TABLE>
-37-
<PAGE> 40
EXHIBIT INDEX
Exhibit Description
- ------- -----------
27 Financial Data Schedule
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM
CONSOLIDATED BALANCE SHEETS AND STATEMENTS OF OPERATIONS ON PAGES 2 TO 8 OF THE
COMPANY'S JUNE 30, 1997 AUDITORS REPORT TO THE BOARD OF DIRECTORS AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> JUN-30-1997
<PERIOD-START> JUL-01-1996
<PERIOD-END> JUN-30-1997
<CASH> 20,814
<SECURITIES> 0
<RECEIVABLES> 46,886
<ALLOWANCES> (1,660)
<INVENTORY> 12,810
<CURRENT-ASSETS> 80,193
<PP&E> 403,462
<DEPRECIATION> (89,491)
<TOTAL-ASSETS> 434,757
<CURRENT-LIABILITIES> 79,663
<BONDS> 260,089
0
0
<COMMON> 714
<OTHER-SE> 27,884
<TOTAL-LIABILITY-AND-EQUITY> 434,757
<SALES> 373,940
<TOTAL-REVENUES> 382,830
<CGS> 244,780
<TOTAL-COSTS> 354,877
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 23,817
<INCOME-PRETAX> 4,136
<INCOME-TAX> 1,966
<INCOME-CONTINUING> 2,170
<DISCONTINUED> 0
<EXTRAORDINARY> (7,861)
<CHANGES> 0
<NET-INCOME> (5,843)
<EPS-PRIMARY> (8.67)
<EPS-DILUTED> 0
</TABLE>
