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 SEPTEMBER 30, 1999.
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 ___
-----
The number of shares of the Registrant's common stock, par value $1.00 per
share, outstanding at September 30, 1999 was 645,964 shares.
<PAGE>
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ENERGY CORPORATION OF AMERICA
TABLE OF CONTENTS
<S> <C>
PAGES
PART I FINANCIAL INFORMATION
Item 1. Financial Statements
Condensed Consolidated Balance Sheets
September 30, 1999 (unaudited) and June 30, 1999 . . . . . . . . . . 3
Unaudited Condensed Consolidated Statements of Operations
For the three months ended September 30, 1999 and 1998 . . . . . . . 5
Unaudited Condensed Consolidated Statements of Cash Flows
For the three months ended September 30, 1999 and 1998 . . . . . . . 6
Notes to Unaudited Condensed Consolidated Financial Statements. . . . . 7
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operation. . . . . . . . . . . . . . . . . . . . . . . . . . 12
PART II OTHER INFORMATION
Item 1. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . 18
Item 2. Changes in Securities . . . . . . . . . . . . . . . . . . . . . 18
Item 3. Defaults Upon Senior Securities . . . . . . . . . . . . . . . . 18
Item 4. Submission of Matters to a Vote of Security Holders . . . . . . 18
Item 5. Other Information . . . . . . . . . . . . . . . . . . . . . . . 18
Item 6. Exhibits and Reports on Form 8-K. . . . . . . . . . . . . . . . 18
Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
</TABLE>
<PAGE>
PART I FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
<TABLE>
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ENERGY CORPORATION OF AMERICA
CONDENSED CONSOLIDATED BALANCE SHEETS
(AMOUNTS IN THOUSANDS)
- ---------------------------------------------------------------------------------
<S> <C> <C>
SEPTEMBER 30 JUNE 30
1999 1999
(UNAUDITED) *
ASSETS
CURRENT ASSETS
Cash and cash equivalents . . . . . . . . . . . . . . . $ 10,359 $ 13,557
Accounts receivable, net of allowance for doubtful
accounts of $1,062 and $1,622. . . . . . . . . . . . 29,910 32,854
Gas in storage, at average cost . . . . . . . . . . . . 349 357
Income tax receivable . . . . . . . . . . . . . . . . . 3,180 3,580
Prepaid winter gas service. . . . . . . . . . . . . . . 38,139 18,474
Prepaid and other current assets. . . . . . . . . . . . 7,048 7,146
---------- --------
Total current assets . . . . . . . . . . . . . . . . 88,985 75,968
---------- --------
Property, plant and equipment, net of accumulated
depreciation and depletion of $120,595 and $116,893 . . 328,037 315,316
---------- --------
OTHER ASSETS
Deferred financing costs, net of accumulated
amortization of $2,738 and $2,485. . . . . . . . . . 8,319 8,523
Notes receivable, less allowance for doubtful accounts
of $440. . . . . . . . . . . . . . . . . . . . . . . 3,596 3,544
Deferred utility charges. . . . . . . . . . . . . . . . 18,148 18,785
Other . . . . . . . . . . . . . . . . . . . . . . . . . 14,813 14,806
---------- --------
Total other assets . . . . . . . . . . . . . . . . . 44,876 45,658
---------- --------
TOTAL. . . . . . . . . . . . . . . . . . . . . . . . . . . $ 461,898 $436,942
========== ========
<FN>
* Condensed from audited consolidated financial statements.
</TABLE>
The accompanying notes are an integral part of these condensed consolidated
financial statements.
<PAGE>
<TABLE>
<CAPTION>
ENERGY CORPORATION OF AMERICA
CONDENSED CONSOLIDATED BALANCE SHEETS
(AMOUNTS IN THOUSANDS)
- ------------------------------------------------------------------------------------
<S> <C> <C>
SEPTEMBER 30 JUNE 30
1999 1999
(UNAUDITED) *
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable . . . . . . . . . . . . . . . . . . . . $ 41,111 $ 40,049
Current portion of long-term debt. . . . . . . . . . . . 3,590 6,634
Short-term debt. . . . . . . . . . . . . . . . . . . . . 10,465 16,799
Funds held for future distribution . . . . . . . . . . . 6,436 5,378
Accrued taxes, other than income . . . . . . . . . . . . 6,066 7,635
Overrecovered gas costs. . . . . . . . . . . . . . . . . 2,816 3,927
Other current liabilities. . . . . . . . . . . . . . . . 8,121 8,465
----------- ---------
Total current liabilities . . . . . . . . . . . . . . 78,605 88,887
LONG-TERM OBLIGATIONS
Long-term debt . . . . . . . . . . . . . . . . . . . . . 319,787 280,021
Gas delivery obligation and deferred trust revenue . . . 13,268 13,839
Deferred income tax liability. . . . . . . . . . . . . . 27,731 27,868
Other long-term obligation . . . . . . . . . . . . . . . 11,921 11,850
----------- ---------
Total liabilities . . . . . . . . . . . . . . . . . . 451,312 422,465
----------- ---------
STOCKHOLDERS' EQUITY
Common stock, par value $1.00; 2,000,000 shares
authorized; 721,000 shares issued . . . . . . . . . . 721 721
Class A stock, no par value; 100,000 shares authorized;
26,000 shares issued. . . . . . . . . . . . . . . . . 2,940 2,940
Additional paid in capital . . . . . . . . . . . . . . . 4,656 4,656
Retained earnings. . . . . . . . . . . . . . . . . . . . 9,293 13,598
Treasury stock and notes receivable arising from the
issuance of common stock. . . . . . . . . . . . . . . (7,259) (7,261)
Accumulated comprehensive income (loss). . . . . . . . . 235 (177)
----------- ---------
Total Stockholders' equity. . . . . . . . . . . . . . 10,586 14,477
----------- ---------
TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 461,898 $436,942
=========== =========
<FN>
* Condensed from audited consolidated financial statements.
</TABLE>
The accompanying notes are an integral part of these condensed consolidated
financial statements.
<PAGE>
<TABLE>
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ENERGY CORPORATION OF AMERICA
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED - AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
- ----------------------------------------------------------------------------------
<S> <C> <C>
FOR THE THREE MONTHS ENDED
SEPTEMBER 30
1999 1998
REVENUES:
Utility gas sales and transportation. . . . . . $ 16,907 $ 13,863
Gas marketing and pipeline sales. . . . . . . . 21,906 31,044
Oil and gas sales . . . . . . . . . . . . . . . 6,971 5,855
Well operations and service revenues. . . . . . 1,582 1,780
Other revenue . . . . . . . . . . . . . . . . . 169 358
-------------- ---------
47,535 52,900
-------------- ---------
COST AND EXPENSES:
Utility gas purchased . . . . . . . . . . . . . 4,451 7,418
Gas marketing and pipeline cost . . . . . . . . 21,368 30,104
Field operating expenses. . . . . . . . . . . . 2,343 2,440
Utility operations and maintenance. . . . . . . 5,584 5,584
General and administrative. . . . . . . . . . . 5,165 5,111
Taxes, other than income. . . . . . . . . . . . 2,291 2,163
Depletion and depreciation, oil and gas related 2,171 2,175
Depreciation of pipelines and equipment . . . . 1,989 1,948
Exploration and impairment. . . . . . . . . . . 1,201 2,085
-------------- ---------
46,563 59,028
-------------- ---------
Income (loss) from operations . . . . . . . . . 972 (6,128)
-------------- ---------
OTHER (INCOME) EXPENSE
Interest. . . . . . . . . . . . . . . . . . . . 7,102 6,604
Gain on sale of assets. . . . . . . . . . . . . (2) (727)
Other . . . . . . . . . . . . . . . . . . . . . (256) (432)
-------------- ---------
Loss before income taxes and
minority interest . . . . . . . . . . . . . . . (5,872) (11,573)
Benefit from income taxes. . . . . . . . . . . . . (1,567) (3,750)
-------------- ---------
Loss before minority interest. . . . . . . . . . . (4,305) (7,823)
Minority interest. . . . . . . . . . . . . . . . . - 7
-------------- ---------
NET LOSS . . . . . . . . . . . . . . . . . . . . . $ (4,305) $ (7,830)
============== =========
Net loss per common share,
Basic . . . . . . . . . . . . . . . . . . . . . $ (6.45) $ (11.85)
Assuming dilution . . . . . . . . . . . . . . . $ (6.45) $ (11.85)
</TABLE>
The accompanying notes are an integral part of these condensed consolidated
financial statements.
<PAGE>
<TABLE>
<CAPTION>
ENERGY CORPORATION OF AMERICA
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED - AMOUNTS IN THOUSANDS)
- ---------------------------------------------------------------------------------------------
<S> <C> <C>
FOR THE THREE MONTHS ENDED
SEPTEMBER 30
1999 1998
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss. . . . . . . . . . . . . . . . . . . . . . . . . $ (4,305) $ (7,830)
Adjustment to reconcile net loss to net cash used
by operating activities:
Minority interest. . . . . . . . . . . . . . . . . . . 7
Depletion, depreciation and amortization . . . . . . . 4,360 4,323
Gain on sale of assets . . . . . . . . . . . . . . . . (2) (727)
Exploration and impairment . . . . . . . . . . . . . . 960 1,969
Other, net . . . . . . . . . . . . . . . . . . . . . . (882) (1,291)
-------------- ---------
131 (3,549)
Changes in assets and liabilities
Accounts receivable. . . . . . . . . . . . . . . . . . 5,529 8,647
Gas in storage . . . . . . . . . . . . . . . . . . . . 8 (13,082)
Prepaid and other assets . . . . . . . . . . . . . . . (19,145) (1,993)
Accounts payable . . . . . . . . . . . . . . . . . . . 906 (1,955)
Funds held for future distributions. . . . . . . . . . 1,058 (898)
Overrecovered gas costs. . . . . . . . . . . . . . . . (1,111) (860)
Other. . . . . . . . . . . . . . . . . . . . . . . . . (571) (2,797)
-------------- ---------
Net cash used by operating activities . . . . . . . (13,195) (16,487)
-------------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment. . . . . . (19,087) (9,355)
Proceeds from sale of assets. . . . . . . . . . . . . . . 34 1,282
Notes receivable and other. . . . . . . . . . . . . . . . (1,341) 13
-------------- ---------
Net cash used by investing activities . . . . . . . (20,394) (8,060)
-------------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Principal payment on long-term debt . . . . . . . . . . . (3,278) (145)
Short-term borrowings, net. . . . . . . . . . . . . . . . 33,667 19,233
Purchase of treasury stock and other financing activities 2 (389)
Dividends . . . . . . . . . . . . . . . . . . . . . . . . (322)
-------------- --------
Net cash provided by financing activities . . . . . 30,391 18,377
-------------- ---------
Net decrease in cash and cash equivalents . . . . . (3,198) (6,170)
Cash and cash equivalents, beginning of period. . . 13,557 21,547
-------------- ---------
Cash and cash equivalents, end of period . . . . . . . . . . $ 10,359 $ 15,377
============== =========
</TABLE>
The accompanying notes are an integral part of these condensed consolidated
financial statements.
<PAGE>
ENERGY CORPORATION OF AMERICA
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 1999
1. Nature of Organization
Energy Corporation of America (the "Company") was formed in June 1993 through an
exchange of shares with the common stockholders of Eastern American Energy
Corporation ("Eastern American"). The Company is an independent integrated
energy company. 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
Public Service Commission of West Virginia.
Oil and Gas Exploration, Development, Production and Marketing - The Company,
- -----------------------------------------------------------------
primarily through Eastern American, is engaged in exploration, development and
production, transportation and marketing of natural gas primarily within the
Appalachian Basin states of West Virginia, Pennsylvania and Ohio.
The Company, through its wholly owned subsidiaries Westech Energy Corporation
and Westech Energy New Zealand, is also engaged in the exploration for and
production of oil and natural gas primarily in the Rocky Mountains and New
Zealand.
2. Accounting Policies
Reference is hereby made to the Company's Annual Report on Form 10-K for 1999,
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 report 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, included herein, have been made. The results of
operations for the three months ended September 30, l999 are not necessarily
indicative of the results to be expected for the full year.
3. Recently Issued Accounting Pronouncements
The Company adopted Statement of Financial Accounting Standards ("SFAS") No.
130, "Reporting Comprehensive Income", effective July 1, 1998. The standard
establishes rules for the reporting of comprehensive income and its components.
The Company's comprehensive income (loss) consists of foreign currency
translation adjustments.
<PAGE>
In June 1998, SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities" was issued, which is effective for all fiscal quarters of all fiscal
years beginning after June 15, 2000. SFAS No. 133 establishes accounting and
reporting standards for derivative instruments, including certain derivative
instruments embedded in other contracts, and hedging activities. It requires
the recognition of all derivative instruments as assets or liabilities in the
Company's balance sheet and measurement of those instruments at fair value. The
accounting treatment of changes in fair value is dependent upon whether or not a
derivative instrument is designated as a hedge and if so, the type of hedge.
The Company has not fully analyzed what impact the provisions of SFAS No. 133
will have on the Company's financial statements.
4. Earnings per Share
A reconciliation of the components of basic and diluted net loss per common
share for the three months ended September 30, for the years indicated, is as
follows:
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Per-Share
Loss Shares Amount
------------ ------- --------
1999
- ----
Basic and Diluted Earnings per Share
Loss available to common shareholders $(4,305,000) 666,968 $ (6.45)
1998
- ----
Basic and Diluted Earnings per Share
Loss available to common shareholders $(7,830,000) 660,623 $(11.85)
</TABLE>
The effect of outstanding stock options during the current period was not
included in the computation of diluted earnings per share because to do so would
have been antidilutive. There were no stock options exercisable during the
prior period.
5. The Company adopted SFAS No. 131, "Disclosures About Segments of an
Enterprise and Related Information," in fiscal 1999. 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. The
regulated utility segment generates revenue from the transportation and sale of
natural gas at retail. Revenues for the marketing and pipeline segment arise
from the marketing of both Company and third party produced natural gas volumes
and the related transportation. The Company utilizes earnings before interest,
taxes, depreciation, depletion, amortization and exploratory costs ("EBITDAX")
to evaluate each segment's operations.
Summarized financial information for the Company's reportable segments is shown
in the following table (in thousands):
<PAGE>
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C>
Exploration Marketing
and Regulated and
Production Utility Pipeline Other Consolidated
------------- ----------- ---------- -------- --------------
For the three months ended September 30, 1999
Sales to unaffiliated customers . . . . . . . $ 7,530 $ 16,907 $ 21,421 $ 169 $ 46,027
Intersegment revenues . . . . . . . . . . . . 1,105 - 485 (82) 1,508
Depreciation, depletion, amortization . . . . 2,560 924 311 365 4,160
Exploratory costs . . . . . . . . . . . . . . 1,201 1,201
Operating profit (loss) . . . . . . . . . . . 952 945 (584) (341) 972
Interest expense. . . . . . . . . . . . . . . 14 1,802 5,286 7,102
EBITDAX . . . . . . . . . . . . . . . . . . . 4,867 1,909 (338) 154 6,592
Total assets. . . . . . . . . . . . . . . . . 88,290 220,654 65,267 87,687 461,898
Capital expenditures. . . . . . . . . . . . . 3,291 15,683 97 16 19,087
- ---------------------------------------------- ------------- ----------- ---------- -------- --------------
For the three months ended September 30, 1998
- ----------------------------------------------
Sales to unaffiliated customers . . . . . . . 6,729 13,863 24,693 358 45,643
Intersegment revenues . . . . . . . . . . . . 1,009 6,351 (103) 7,257
Depreciation, depletion, amortization . . . . 2,612 802 331 378 4,123
Exploratory costs . . . . . . . . . . . . . . 2,130 (45) 2,085
Operating profit (loss) . . . . . . . . . . . (926) (4,935) 31 (298) (6,128)
Interest expense. . . . . . . . . . . . . . . 34 1,606 4,964 6,604
EBITDAX . . . . . . . . . . . . . . . . . . . 4,813 (3,984) 313 91 1,233
Total assets. . . . . . . . . . . . . . . . . 98,241 200,111 71,462 74,231 444,045
Capital expenditures. . . . . . . . . . . . . 6,423 2,671 201 60 9,355
- ---------------------------------------------- ------------- ----------- ---------- -------- --------------
</TABLE>
Operating profit (loss) 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
between the exploration and production and the utility segments have not been
eliminated in consolidation because of the regulated nature of the gas
distribution segment. The 'Other' column includes items related to
non-reportable segments, corporate and elimination items. Included in the
regulated utility segment's capital expenditures for the three months ended
September 30, 1999 is $12.6 million related to the acquisition cost of
substantially all of the West Virginia assets of Shenandoah Gas Company
("Shenandoah"). Included in the exploration and production segment's total
assets are net long-lived assets located in New Zealand of $3.0 and $2.0
million, as of September 30, 1999 and 1998, respectively.
<PAGE>
6. Debt
A rollforward of the debt from June 30, 1999 to September 30, 1999, is as
follows (in thousands):
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C>
Current
Short Term Portion Long Long Term Total Long
Debt Term Debt Debt Term Debt
------------ -------------- ---------- -----------
Balance at June 30, 1999. . . . . $ 16,799 $ 6,634 $ 280,021 $ 286,655
Short term borrowings, net. . . 33,666
Issue long term debt, effective 40,000 40,000
November 1, 1999
Effectively pay down short
term debt. . . . . . . . . . (40,000)
Long term debt payment. . . . . (3,278) (3,278)
Reclassify long term debt to
current portion. . . . . . . 234 (234)
------------ --------------
Balance at September 30, 1999 . . $ 10,465 $ 3,590 $ 319,787 $ 323,377
============ ============== ========== ===========
</TABLE>
The Company's scheduled maturities of long term debt for each of the periods
indicated is as follows (in thousands):
<TABLE>
<CAPTION>
For the Quarter Ending:
<S> <C>
December 31, 1999 . . . . $ 909
March 31, 2000. . . . . . 910
June 30, 2000 . . . . . . 905
September 30, 2000. . . . 866
--------
Total current . . . . . . 3,590
December 31, 2000 . . . . 32
March 31, 2001. . . . . . 32
June 30, 2001 . . . . . . 29
For the Fiscal Year Ending:
June 30, 2002 . . . . . . 22,462
June 30, 2003 . . . . . . 3,461
June 30, 2004 . . . . . . 3,461
June 30, 2005 . . . . . . 3,461
Thereafter. . . . . . . . 286,849
--------
Total. . . . . . . . . $323,377
========
</TABLE>
On November 1, 1999, Mountaineer completed new financing arrangement with
several private lenders to provide $40.0 million in additional unsecured
long-term financing. This commitment consisted of $10.0 million in 7.83%
unsecured notes due 2009 and $30.0 million in 8.09% unsecured notes due 2019,
with no required prepayments. The funds were used to reduce outstanding
borrowings under Mountaineer's short-term lines of credit.
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 that can
be declared. Additionally, under its debt covenants, Mountaineer is restricted
in the payment of dividends to the Company. As of September 30, 1999,
Mountaineer had approximately $5.3 million available for the declaration of
dividends.
7. Contingencies
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.
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF
------- --------------------------------------------------
OPERATIONS AND FINANCIAL CONDITION
----------------------------------
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 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. 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, 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.
COMPARISON OF RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED SEPTEMBER 30,
- --------------------------------------------------------------------------------
1999 AND 1998
- ---------------
The Company recorded a net loss of $4.3 million for the three months ended
September 30, 1999 compared to a net loss of $7.8 million for the same period in
1998. The increase in income of $3.5 million is attributed to the net of a $5.4
million decrease in revenue, an $11.6 million decrease in operating expenses, a
$0.9 million decrease in impairment and exploratory costs, a $0.9 million
decrease in other non-operating income, a $0.5 million increase in interest
expense and a $2.2 million decrease in income tax benefits.
REVENUES. Total revenues decreased $5.4 million or 10.1% between the periods.
- --------
The decrease was due to a 29.4% decrease in gas marketing and pipeline sales,
which was offset by a 22.0% increase in utility gas sales and transportation and
a 19.1% increase in oil and gas sales. Well and service operating revenue and
other operating revenue remained relatively constant between the periods.
Revenues from gas marketing and pipeline sales decreased $9.1 million from
$31.0 million during the period ended September 30, 1998 to $21.9 million during
the period ended September 30, 1999. The decrease in revenue is primarily
attributable to a 45% decline in marketed gas volumes from 12.7 million Mmbtu to
7.0 million Mmbtu, partially offset by a 22% increase in the average sales price
per Mmbtu from $2.22 for the quarter ended September 30, 1998 to $2.71 for the
quarter ended September 30, 1999. The decline in volumes for the quarter ended
September 30, 1999 was partially attributable to the expiration of contracts,
which accounted for $7.6 million in sales and 3.7 Bcfe. Also contributing to
the decreased revenue is the reduction of trading activity volumes as a result
of the marketing focus change. At the end of the last fiscal year, it was
decided that the Company would no longer enter into contracts to purchase and
resell independent producers gas as this business was becoming more competitive
and less economical to maintain. Instead, the Company will focus on marketing
its production.
<PAGE>
Revenues from oil and gas sales increased $1.1 million from $5.9 million
for the period ended September 30, 1998 to $7.0 million for the period ended
September 30, 1999. The increase in revenue is primarily attributable to a 37%
increase in the average per barrel oil price from $12.53 to $17.17 and a 22%
increase in the average per Mcf gas price from $2.21 to $2.70 between September
30, 1998 and 1999. Mcfe production volumes were comparable between periods.
Utility gas sales and transportation revenues increased approximately $3.0
million during the three months ended September 30, 1999 compared to the prior
year. Of this amount, approximately $2.6 million was the result of increased
tariff sales and $0.4 million resulting from additional transportation revenues.
The increase in tariff sales resulted primarily from more favorable weather
conditions during the current period as system-wide average heating degree days
were 104 compared to 51 in the prior year and additional customers acquired from
Shenandoah. Tariff sales volumes increased approximately 29%, from 1.4 Bcf to
1.8 Bcf during the current period. Transportation revenues increased despite a
decrease in related volumes from 8.1 Bcf to 7.7 Bcf during the current period.
The decline in volumes was primarily the result of reduced throughput for one
particular customer; however, this reduction did not have a significant effect
on revenues due to the related contract price. The increase in transportation
revenues resulted from an increase in Mountaineer's transportation tariff rates
effective November 1, 1998.
COSTS AND EXPENSES. The Company's costs and expenses decreased $11.6
--------------------
million or 19.0% during this period primarily as the result of a 40.0% decline
in the cost of utility gas purchased and a 29.0% decrease in gas marketing and
pipeline costs. Field and lease operating expenses, utility operations and
maintenance costs, general and administrative expenses, taxes other than income
and depreciation, depletion and amortization costs remained relatively constant
between the periods.
Utility gas purchase costs decreased approximately $3.0 million during the three
months ended September 30, 1999 compared to the same period in 1998. This
decrease was partially due to a $2.1 million refund from the Company's primary
transmission service provider, which was approved by the Federal Energy
Regulatory Commission in September 1999. Also contributing to the decrease was
the effect of the Company's gas supply management agreement (the "Supply
Agreement"), as discussed in the Company's Form 10-K filed with the Securities
and Exchange Commission on September 28, 1999, which went into effect on
November 1, 1998. This agreement results in the demand costs associated with
transmission services provided to the Company being included in a fixed price
per dekatherm delivered either to its city gate or for winter service rather
than as a fixed monthly charge. The following table presents a comparison of
the costs of utility gas purchased for the periods indicated, dollar amounts in
thousands, except cost per unit sold:
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C>
September 30, 1999 September 30, 1998
------------------ ------------------
Cost Per Cost Per
Cost Unit Sold Cost Unit Sold
---------- ----------- -------- -----------
Demand costs . $ 178 $ 5,935
Refund . . . . (2,100)
---------- --------
Total demand . (1,922) $ (1.04) 5,935 $ 4.20
Commodity. . . 6,849 3.71 2,489 1.76
Other. . . . . (476) (0.26) (1,006) (0.71)
---------- ----------- -------- -----------
Total gas cost $ 4,451 $ 2.41 $ 7,418 $ 5.25
========== =========== ======== ===========
Mcf sold . . . 1,847 1,414
</TABLE>
<PAGE>
Prepaid winter gas service, related to the Supply Agreement, totaled 11,716,997
dth, 6,083,402 dth and 11,704,667 dth (previously classified as gas in storage)
and account balances of $38.1 million ($3.26 per dth), $18.5 million ($3.04 per
dth) and $25.9 million ($2.21 per dth) at September 30, 1999, June 30, 1999 and
September 30, 1998, respectively.
Assuming volumes delivered to the city gate reach a specified level for a
twelve month period, total costs for transmission services included in the fixed
price will approximate the amount previously incurred as a fixed monthly amount.
To the extent volumes delivered are below the specified level, the Company will
experience a reduction in such costs. For the three months ended September 30,
1998, the Company incurred approximately $5.9 million in fixed monthly demand
charges. During the same period of 1999, the Company recorded approximately
$1.6 million through purchased gas expense for transmission related costs under
the Supply Agreement. These decreases were partially offset by:
a. Increased volumes purchased resulting from higher sales volumes due to
favorable weather conditions and the additional customers acquired from
Shenandoah, which resulted in gas costs of approximately $1.6 million.
b. An increase in commodity prices (or, in the case of the Supply Agreement,
fixed price less the transmission cost component) which increased gas costs by
approximately $1.1 million.
c. Reduced amortization of previously overrecovered gas costs of approximately
$.5 million as a result of the Company current rate moratorium, which went into
effect on November 1, 1998.
The $8.7 million decrease in gas marketing and pipeline costs is primarily
the result of a 45% decline in purchased gas volumes from 12.9 million Mmbtu to
7.1 million Mmbtu from September 30, 1998 to September 30, 1999. Partially
offsetting this decline in costs was a 19% increase in the average price paid
for gas purchased, from $2.20 per Mmbtu to $2.61 per Mmbtu between periods.
Additionally, approximately $0.8 million of purchased gas costs were charged
against a reserve for losses on future gas purchases during the three months
ended September 30, 1998.
Impairment and exploratory expenses decreased $0.9 million primarily due to the
drilling of two dry holes in New Zealand during the prior period, resulting in
$1.5 million of impairment expense compared to none during the current period.
This was partially offset by an increase in domestic impairment expense increase
of $0.4 million due to the drilling of 3.5 net dry holes in the current period
compared to 0.8 in the prior period.
INTEREST EXPENSE. Interest expense increased between the periods due to
-----------------
the net addition to long-term debt, including the current portion and short term
debt of $33.5 million, when comparing September 30, 1999 to September 30, 1998.
OTHER (INCOME) EXPENSE. Other income decreased a total of $0.9 million
------------------------
primarily due to the recognition of gains on the sale of property during fiscal
1999 and none during the current period. In addition, interest income decreased
$0.1 million due to a decrease in cash and cash equivalents.
BENEFIT FOR INCOME TAXES. The benefit for income taxes changed $2.2
---------------------------
million primarily because of the decrease in pre-tax loss.
<PAGE>
LIQUIDITY AND CAPITAL RESOURCES
- ----------------------------------
The Company's primary sources of liquidity are (1) cash provided from
operating activities (2) short-term debt and credit facilities and (3) long-term
revolving debt facilities. Since July 1, 1999, the Company's financial
condition declined as cash used in operating activities totaled $13.2 million,
cash on hand decreased $3.2 million, working capital increased $23.3 million
after reclassification of $40 million of short-term debt to long-term debt (see
Note 6), debt to equity increased from 21 to 1 to 32 to 1, and the Company's
equity decreased by $3.9 million. Funds available for the Company's utility
operation, resulting from unused short-term and revolving credit facilities
totaled $16.5 million at September 30, 1999 and $47.8 million at November 12,
1999, after reclassification of short-term debt previously discussed. In
addition, on October 12, 1999 Moody's Investors Service downgraded its rating of
the Company's $200 million Senior Subordinated Notes due 2007 to Caa1 from B2,
and the Company's secured $22 million Revolving Credit Facility to Ba3 from Ba2.
On October 18, 1999 Standard and Poor's lowered its corporate credit rating of
the Company to single 'B' plus from double 'B' minus and lowered its Senior
Subordinated Notes rating to single 'B' minus from single 'B'. The agency also
placed the ratings on Credit Watch with negative implications, which indicate
that ratings may be lowered again in the future.
The Company's cash balance decreased $3.2 million during the period. The
decrease in cash during the quarter primarily resulted from cash used in
operating activities totaling $13.2 million after a non-recurring $2.1 million
cash refund from an interstate gas transporter. The Company is generally a net
user of funds from operations during this reporting period due to the seasonal
nature of its utility business and its merchant natural gas business. The
Company's cash balance was also impacted by its investments in property, plant
and equipment, which totaled $19.1 million, debt principal payment of $3.0
million required under the Revolving Credit Facility Amended Debt Agreement and
other uses totaling $1.6 million. Subsequent to the balance sheet date, the
utility operation of the company borrowed $40.0 million, of which all the
proceeds were used to repay short-term indebtedness. This transaction increased
the utility's ability to borrow under its short-term credit facilities by
approximately $40 million.
Prior to the reclassification of the $40 million short-term debt, working
capital decreased from a negative $12.9 at June 30, 1999 to a negative $29.6
million at September 30, 1999. After the reclassification, working capital
increased $23.3 million to a positive $10.4 million, primarily as a result of a
$19.6 million increase in prepaid winter gas service relating to the Company's
utility operation under the utility's Supply Agreement.
The Company's primary sources of liquidity and capital resources have been
adversely impacted by the Company's results of operations, long-term revolving
debt agreement amendments and external capital market ratings. The Company has
attempted to mitigate its exposure to gas price risk by hedging 15,000 Mmbtu per
day of its gas production under various hedging arrangements and has
substantially reduced its purchased gas price exposure at its utility operation
by entering into the Supply Agreement. In addition, the Company has omitted
dividend payments and taken steps to minimize capital expenditure outlays by
restructuring certain opportunities relating to current and future oil and gas
activities. In the remaining portion of the current fiscal year, the Company
estimates it will invest an additional $7.8 million in the Company's utility
operation, repay an additional $3.0 million in long-term debt, pay $19.0 million
in interest payments, and spend approximately $10.5 (including $1.25 million as
other property and equipment) in discretionary oil & gas drilling and
exploration activities. Other than the $3.0 million under the Revolving Credit
Facility repayment during the twelve months ending September 30, 2000, as
mentioned above, no other significant principal payments are due until October
1, 2001 when the Company's utility commences principal repayments of $3.3
million per year on its $60 million, 7.59% notes due to John Hancock. In
addition, the Company's $19.0 million Revolving Credit Facility becomes due May
2002. In the event that cash from operating activities are not sufficient to
offset the cash outflows required above, the Company believes that the capital
expenditures and debt service obligations, required at the Company's utility
operations, can be funded through the utility's existing resources and
short-term credit facilities in the near term. The Company believes that the
debt and interest obligations on its Senior Subordinated Debt and its Revolving
Credit Facility can be partially funded through dividend and income tax sharing
arrangement payments from the Company's utility operation and from its existing
oil and gas operating activities. However, the Company's utility operation is
restricted as to the amount of dividends it is permitted to pay to the parent,
$5.3 million is available at September 30, 1999 (see Note 6). Other capital
investments in oil and gas exploration and development drilling opportunities
may be financed on a cash available basis since the Company's amended Revolving
Debt Agreement, typically used to fund such drilling opportunities, is currently
at its maximum draw down capability.
<PAGE>
The Company believes that its existing capital resources, its mitigating
management efforts, and its expected fiscal year 2000 results of operations and
cash flows from operating activities will be sufficient for the Company to
remain in compliance with the requirements of its Senior Subordinated Debt, its
Revolving Credit Facility, and the short and long-term debt and credit
facilities at its utility operation, and will be sufficient to fund
non-discretionary capital expenditures. However, since the expected fiscal year
2000 results of operations and cash flow from operating activities, debt service
capability, and levels and availability of capital resources and continuing
liquidity are dependent on future weather patterns, maintaining current levels
of oil and gas commodity sales prices and future exploration and development
drilling success, the Company can give no assurance that such expectations will
be realized or that debt service or debt covenant violations will not occur. In
such instances, the Company may elect to increase debt levels, restructure debt
agreements (including debt agreements with additional lenders), sell core and
non-core assets including a portion or all of its utility subsidiary or it
exploration and development subsidiaries, defer discretionary capital
expenditures, curtail certain domestic and international oil and gas programs or
take other actions necessary to mitigate liquidity short-falls and debt
agreement violations or acquire new or additional capital resources, although no
assurances can be given that such actions will be successful.
YEAR 2000 COMPLIANCE. The year 2000 issue arose because many computer systems
- ----------------------
and software applications as well as embedded computer chips currently in use
were constructed using an abbreviated date field that eliminates the first two
digits of the year. On January 1, 2000, these systems, applications and
embedded computer chips may incorrectly recognize the date as January 1, 1900.
Accordingly, many computer systems and software applications, as well as
embedded chips, may incorrectly process financial or operating information or
fail to process such information completely. The company recognized this
problem and is addressing its potential effects on its computer systems,
software applications and operating assets.
The Company began its Year 2000 compliance efforts in 1996 and has completed its
assessment of its key business information systems to determine what issues, if
any, exist regarding these systems' compliance with Year 2000 issues and is
taking the necessary steps to ensure its systems will be compliant by the year
2000. These steps include the purchase and implementation of an integrated
application software package, that together with the associated hardware and
external consulting resources, which to date, has cost approximately $7.4
million. In addition, the Company is presently completing of modification of
existing operating and application systems that were not Year 2000 compliant and
anticipates that it will be successful in completing such modifications before
the 1999 calendar year end. With the exception of the new application package
discussed above, the Company anticipates that it can complete the necessary
modifications to its information systems to ensure Year 2000 compliance
utilizing internal resources. The costs associated with modification of
existing information consist primarily of personnel expense for staff dedicated
to the effort. The Company's policy is to expense these costs as incurred. The
Company also has invested in new or upgraded technology, which has definable
value lasting beyond 2000. In these instances, such as the implementation of
the integrated software application discussed above, the Company is capitalizing
and depreciating such costs over their estimated useful life.
<PAGE>
In addition to reviewing its own computer operating and application
systems, the Company has communicated with its significant suppliers and vendors
to determine the extent to which these parties have addressed Year 2000 issues.
To the extent such vendors have not provided reasonable assurances to the
Company of their readiness to handle Year 2000 issues, contingency plans have
been developed. There is no assurance that such parties can complete the
necessary modifications and conversions in a timely manner. To the extent such
modifications and conversions are not completed on a timely basis and issues
outside of the companies control arise, the Year 2000 issue could have an
adverse impact on the operations of the Company.
The costs associated with addressing Year 2000 issues and the date on which
the Company believes it will complete the necessary modifications are based upon
management's best estimates. There can be no guarantee that these estimates
will be achieved and actual results could differ from those anticipated.
<PAGE>
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
The Company is not a party to any legal actions that would materially affect the
Company's operations or financial statements.
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) 27 Financial Data Schedule
(b) No reports on Form 8-K have been filed during the quarter ended
September 30, 1999
<PAGE>
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 15th day of November, 1999.
ENERGY CORPORATION OF AMERICA
By: /s/John Mork
-------------
John Mork
Chief Executive Officer
and Director
By: /s/Isobel Allan
----------------
Isobel Allan
Vice President of Finance
<PAGE>
EXHIBIT INDEX
Exhibit
Number 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 3 - 5 OF THE COMPANY'S
SEPTEMBER 30, 1999 FORM 10-Q AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO
SUCH FINANCIAL STATEMENTS.
</LEGEND>
<CIK> 0000032880
<NAME> ENERGY CORPORATION OF AMERICA
<MULTIPLIER> 1000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> JUN-30-2000
<PERIOD-START> JUL-01-1999
<PERIOD-END> SEP-30-1999
<CASH> 10359
<SECURITIES> 0
<RECEIVABLES> 30972
<ALLOWANCES> 1062
<INVENTORY> 349
<CURRENT-ASSETS> 88985
<PP&E> 448632
<DEPRECIATION> 120595
<TOTAL-ASSETS> 461898
<CURRENT-LIABILITIES> 78605
<BONDS> 319787
0
0
<COMMON> 721
<OTHER-SE> 9865
<TOTAL-LIABILITY-AND-EQUITY> 461898
<SALES> 47535
<TOTAL-REVENUES> 47535
<CGS> 25819
<TOTAL-COSTS> 46563
<OTHER-EXPENSES> (258)
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 7102
<INCOME-PRETAX> (5872)
<INCOME-TAX> (1567)
<INCOME-CONTINUING> (4305)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (4305)
<EPS-BASIC> (6.45)
<EPS-DILUTED> (6.45)
</TABLE>
