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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934 FOR THE FISCAL YEAR ENDED JUNE 30, 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 Number)
4643 SOUTH ULSTER STREET, SUITE 1100
DENVER, COLORADO 80237
(Address of principal executive offices and zip code)
(303) 694-2667
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of the Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in part III of this Form 10-K or any amendment to this
Form 10-K. [X]
The aggregate market value of common stock held by non-affiliates of the
registrant: Class of Voting Stock and Number of Shares Held by Non-affiliates
at September 1, 1999 was 95,477 Shares. Market Value Held by Non-affiliates:
Unavailable.
The number of shares of the registrant's common stock, par value $1.00 per
share, outstanding at September 1, 1999 was 645,964 shares.
DOCUMENTS INCORPORATED BY REFERENCE:
NONE
2
ENERGY CORPORATION OF AMERICA
TABLE OF CONTENTS
Page
Part I
Item 1. Business 4
Item 2. Properties 15
Item 3. Legal Proceedings 15
Item 4. Submission of Matters to a Vote of Security Holders 16
Part II
Item 5. Market for the Registrant's Common Stock and Related Stockholder Matters 16
Item 6. Selected Financial Data 16
Item 7. Management's Discussion and Analysis of Results of Operations
and Financial Condition 16
Item 8. Financial Statements and Supplementary Data
Independent Auditor's Report 25
Consolidated Balance Sheets 26
Consolidated Statements of Operations 28
Consolidated Statements of Stockholders Equity 29
Consolidated Statements of Cash Flows 30
Notes to Consolidated Financial Statements 31
Supplemental Information on Oil and Gas Producing Activities (Unaudited) 51
Schedules 56
Item 9. Changes In and Disagreements With Accountants on Accounting
and Financial Disclosure 60
Part III
Item 10. Directors and Officers of Registrant 61
Item 11. Executive Compensation 64
Item 12. Security Ownership of Certain Beneficial Owners and Management 64
Item 13. Certain Relationships and Related Transactions 66
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 69
Part V
Signatures 72
All defined terms under Rule 4-10 (a) of Regulation S-X shall have their
statutorily prescribed meanings when used in this report. Quantities of natural
gas are expressed in this report in terms of thousand cubic feet (Mcf), million
cubic feet (Mmcf) or billion cubic feet (Bcf). Oil is quantified in terms of
barrels (Bbls), thousand barrels (Mbbls) or million barrels (Mmbbls). Oil is
compared to natural gas in terms of cubic feet of gas equivalent (Mcfe), million
of cubic feet equivalent (Mmcfe) or billion cubic feet equivalent (Bcfe). One
barrel of oil is the energy equivalent of six Mcf of natural gas. A dekatherm
(dth) is equal to one million British Thermal Units (Btu). A Btu is the amount
of heat required to raise the temperature of one pound of water one degree
Fahrenheit. With respect to information relating to the Company's working
interest in wells or acreage, "net" oil and gas wells or acreage is determined
by multiplying gross wells or acreage by the Company's working interest therein.
Unless otherwise specified, all references to wells and acres are gross.
3
PART I
------
ITEM 1. BUSINESS
------- ---------
GENERAL
- -------
Energy Corporation of America (the "Company") is a privately held,
integrated energy company primarily engaged in natural gas distribution in West
Virginia and in the development, production, transportation and marketing of
natural gas and oil, primarily in the Appalachian Basin. The Company was formed
in June 1993 through an exchange of shares with the common stockholders of
Eastern American Energy Corporation ("Eastern American"). For the fiscal year
ended June 30, 1999, the Company had total revenues of $286.0 million and EBITDA
(earnings before interest, taxes, depreciation and amortization) of $28.5
million.
The Company conducts business through its principal wholly owned
subsidiaries, Mountaineer Gas Company ("Mountaineer"), Eastern American, Westech
Energy Corporation ("Westech") and Westech Energy New Zealand Limited ("WENZL").
Mountaineer owns and operates the largest natural gas distribution utility in
West Virginia. Eastern American is one of the largest oil and gas operators in
the Appalachian Basin, including exploration, development and production, and is
engaged in the transportation and marketing of natural gas. Westech is involved
in oil and gas exploration and development in the Rocky Mountain region. WENZL
is involved in oil and gas exploration and development in New Zealand.
The principal offices of the Company are located at 4643 South Ulster
Street, Suite 1100, Denver, Colorado 80237, and the telephone number is (303)
694-2667.
As used herein the "Company" refers to the Company alone or together with
one or more of its subsidiaries.
SEGMENT INFORMATION
- --------------------
The Company's principal businesses constitute three operating segments.
For financial information on these segments, see Note 19 to the Consolidated
Financial Statements.
NATURAL GAS DISTRIBUTION UTILITY
- -----------------------------------
Mountaineer owns the largest natural gas distribution system in West
Virginia, consisting of approximately 3,900 miles of natural gas distribution
pipelines. Mountaineer provides natural gas sales and transportation services
to approximately 201,000 residential, commercial, industrial and wholesale
customers in 45 of the 55 counties in West Virginia, including the cities of
Charleston, Beckley, Huntington and Wheeling. During fiscal 1999, Mountaineer
sold or transported 57 Bcf of gas.
Mountaineer continues to pursue expansion of its customer base and to this
end acquired substantially all of the West Virginia assets of Shenandoah Gas
Company effective July 1, 1999 at a cost of approximately $12.6 million. The
acquired assets consist of natural gas distribution facilities and related
equipment, including approximately 3,600 customers, located in the eastern
panhandle of West Virginia.
4
COMPARATIVE GAS SALES AND TRANSPORTATION DATA
- --------------------------------------------------
The table below sets forth certain information with respect to the
operating revenue and related gas volumes of the utility for the years ended
June 30:
1999 1998 1997
--------- --------- ---------
Gas distribution revenue:
Residential 69.55% 69.90% 68.40%
Commercial 23.44% 23.40% 25.20%
Transportation 6.49% 6.30% 5.50%
Industrial and other 0.52% 0.40% 0.90%
--------- --------- ---------
Total 100.00% 100.00% 100.00%
========= ========= =========
Gas distribution volumes:
Residential 28.30% 26.40% 28.20%
Commercial 10.30% 9.40% 11.20%
Transportation 61.30% 64.10% 60.10%
Industrial and other 0.10% 0.10% 0.50%
--------- --------- ---------
Total 100.00% 100.00% 100.00%
========= ========= =========
Average use per customer (Mcf):
Residential 88 90 99
Commercial 312 339 432
Transportation 37,024 28,021 19,653
Industrial and other 24 6,803 27,458
Average revenue per customer:
Residential $ 603 $ 599 $ 653
Commercial $ 1,978 $ 2,121 $ 2,636
Transportation $ 10,918 $ 6,908 $ 4,931
Industrial and other $ 1,754 $ 25,399 $121,377
Average revenue per Mcf:
Residential $ 6.85 $ 6.66 $ 6.60
Commercial $ 6.34 $ 6.26 $ 6.10
Transportation $ 0.29 $ 0.25 $ 0.25
Industrial and other $ 4.27 $ 3.73 $ 4.42
Weighted average sales rate (per Mcf) $ 6.71 $ 6.54 $ 6.43
Average gas cost per Mcf sold $ 3.35 $ 3.81 $ 3.96
Weighted average Degree Days (1) 4,832 4,941 5,275
Miles of distribution pipes 3,951 3,926 3,897
Number of customers 201,526 201,465 200,203
___________________________
(1) Degree Days measure the amount by which the average of the high
and low temperature on a given day is below 65 degrees Fahrenheit.
5
- ------
GAS SUPPLY
- -----------
On September 30, 1998, Mountaineer entered into a Natural Gas Supply
Management Agreement (the "Supply Agreement") with Coral Energy Resources, L.P.
("Coral") an affiliate of Shell Oil Company, pursuant to which Coral became the
principal gas supplier for Mountaineer for a three-year period commencing as of
November 1, 1998. The term of this Supply Agreement coincides with the
three-year Rate Moratorium as discussed below.
The Supply Agreement with Coral provides that Coral will be responsible for
supplying 100% of Mountaineer's annual gas requirements for the three-year term,
less 2.7 Bcf of local production. The gas is supplied by Coral at a fixed price
per dth at the city gate up to approximately 24.4 Bcf annually. Any volumes in
excess of 24.4 Bcf on an annual basis are priced at the lesser of a specified
index or a previously agreed upon maximum cost. As a result of the Supply
Agreement Mountaineer will purchase approximately 90% of its natural gas supply
from Coral. The remaining 10% of the gas supply will be purchased from local
producers, including Company owned production. Because of the Coral Supply
Agreement, during fiscal 1999, natural gas sold by Mountaineer that came from
Company operated production declined from 43% to 23%.
Prior to the Supply Agreement, Mountaineer purchased its gas supply
pursuant to a balanced portfolio of intermediate term (one to five years) and
short term (less than one year) contractual arrangements from various sources,
including supplies from the Gulf Coast and Appalachian regions of the United
States. The following table sets forth the volume of natural gas purchased and
percentage of total volume of natural gas purchases, with respect to those
suppliers accounting for five percent or more of Mountaineer's purchases for the
years ended June 30:
1999 1998 1997
-------------- -------------- --------------
Volume % of Volume % of Volume % of
Mmcf Total Mmcf Total Mmcf Total
------ ------ ------ ------ ------ ------
Company operated production 5,651 23% 10,972 43% 11,365 39%
Coral Energy Resources, L.P. 13,508 55%
Idaho Power 1,172 5%
Conoco, Inc. 1,114 5%
Engage Energy, L.P. 3,581 15% 2,555 9%
Noble Gas Marketing 2,297 9% 2,787 10%
Equitable Resources 1,639 6% 2,258 8%
Texaco Natural Gas 1,579 6% 2,346 8%
Valero Gas Marketing 1,555 6%
The following table sets forth certain information relating to
Mountaineer's gas supply purchases for the years ended June 30:
1999 1998 1997
----- ----- -----
Interstate suppliers 75% 55% 56%
Company operated production 23% 43% 39%
Other Appalachian Basin producers 2% 2% 5%
----- ----- -----
Total 100% 100% 100%
===== ===== =====
6
TRANSPORTATION AND STORAGE CAPACITY
- --------------------------------------
The gas purchased from producer/suppliers in the Gulf Coast region is
transported through the interstate pipeline systems of Columbia Gulf
Transmission Company ("Columbia Gulf"), Columbia Gas Transmission Corporation
("Columbia Gas"), and Tennessee Gas Pipeline Company ("Tennessee Gas") to
Mountaineer's local distribution facilities in West Virginia. Approximately 83%
of the gas purchased by Mountaineer in the Appalachian region is transported by
Columbia Gas, with the balance transported by Tennessee Gas or directly
delivered into Mountaineer's gas utility distribution system.
To ensure continuous, uninterrupted service to its customers, Mountaineer
has in place long-term transportation and service agreements with Columbia Gas,
Columbia Gulf and Tennessee Gas. These contracts cover a wide range of
transportation services and volumes, ranging from firm transportation service to
no-notice service and storage with such contracts expiring on various dates
ranging from October 31, 2000 through October 31, 2004. Under the terms of the
Supply Agreement, Coral has assumed the management and the financial obligations
of virtually all of Mountaineer's total firm transportation and storage
entitlements. The combination of this Supply Agreement and the Rate Moratorium,
discussed below, substantially reduces Mountaineer's exposure to gas cost
fluctuations.
Gas sales and/or transportation contracts with interruption provisions have
been used for load management by Mountaineer, and the gas industry as a whole,
for many years. Under such contracts, the users purchase gas with the
understanding that they may be forced to shut down or switch to alternate
sources of energy at times when the gas is needed for higher priority customers.
In addition, during times of special supply problems, curtailments of deliveries
to customers with firm contracts may be made in accordance with guidelines
established by appropriate federal and state regulatory agencies.
REGULATION AND RATES
- ----------------------
Mountaineer is regulated by the Public Service Commission of West Virginia
("WVPSC"). Under traditional rate making in West Virginia, Mountaineer is
prohibited from increasing its base rate unless it obtains the approval of the
WVPSC. In general, the WVPSC reviews any requested base rate increase based
upon an analysis of the cost of service, as adjusted for known and measurable
changes in expenses and revenues, and a reasonable return on equity. In
determining the overall rate of return on equity allowed in the rate proceeding,
the WVPSC employs a methodology, which computes both the natural gas
distribution utility's cost of debt capital as well as cost of equity capital.
The allowable return on equity is designed to compensate the equity owner at
rates commensurate with the rate of return on investments at comparable risks.
In order to determine the allowable return on equity, the WVPSC utilizes two
market-oriented methodologies; the discounted cash flow and the capital asset
pricing model. A further review utilized by the WVPSC to check the
reasonableness of the allowable return on equity involves an analysis of the
overall return required to provide reasonable interest coverage, dividend
pay-out ratios and internally generated cash flow. Finally, the WVPSC utilizes
a sample group of approximately ten to twelve gas distribution utilities located
within and outside of West Virginia for comparison purposes with respect to its
discounted cash flow calculation and the capital asset pricing model. The cost
of debt capital allowed is determined by utilizing the utility's actual interest
rates as set forth in its loan documents, provided the rate is determined by the
WVPSC to be reasonable. While the cost of debt capital is normally based on
long-term debt, if the utility uses short-term debt on a regular basis, the
WVPSC may determine that such debt should be treated as a component of the
utility's debt capital. Because the rate regulatory process has certain
inherent time delays, rate orders may not reflect the operating costs at the
time new rates are put into effect.
7
Any change to the rate that Mountaineer charges its customers for natural
gas costs must be approved by the WVPSC. In order to obtain approval of changes
to gas purchase costs, Mountaineer makes purchase gas adjustment filings with
the WVPSC on an annual basis which include a forecast for the upcoming twelve
month period of gas costs and a true-up mechanism for the previous period for
any over or under-recovery balances. The WVPSC reviews Mountaineer's gas
purchasing activities during the previous year to determine the prudence of gas
purchase expenditures and to determine that dependable lower-priced supplies of
natural gas are not readily available from other sources. The forecast of gas
costs submitted by Mountaineer in its annual filings incorporates known and
measurable pipeline fees during the upcoming period and an estimate of gas costs
based on several natural gas futures indices. The WVPSC also reviews
Mountaineer's forecast of gas costs in such filings for reasonableness.
All of the requests of natural gas distribution utilities in West Virginia
for rate changes are reviewed by the staff of the WVPSC as well as the Consumer
Advocate Division of the WVPSC. The Consumer Advocate Division is charged with
representing and protecting the interests of residential customers in regulating
the utility.
Prior to October 1995, Mountaineer was subject to traditional regulatory
rate making in West Virginia as that procedure is described above. However,
following a proposal by Mountaineer, the WVPSC issued an order implementing a
three-year rate moratorium effective November 1995. The moratorium provided rate
certainty to Mountaineer's customers by fixing the price of gas for three years.
By entering into the moratorium, Mountaineer assumed the risks and benefits of
fixed utility rates, its gas purchasing activities, ancillary business
activities and achieving operational efficiencies.
In January 1998, Mountaineer filed with the WVPSC for an increase in its
base rates, effective upon expiration of the moratorium period on October 31,
1998. In July 1998, Mountaineer agreed to a Joint Stipulation and Agreement for
Settlement with various parties including the staff of the WVPSC and the
Consumer Advocate Division regarding Mountaineer's rate filing. Under the terms
of the agreement, Mountaineer was granted an increase in its rates, which
assuming certain weather conditions, would generate additional annual revenues
of approximately $9.4 million. The agreement provides for a three year rate
moratorium period from November 1, 1998 to October 31, 2001. The terms and
conditions of the agreement are similar to those under which Mountaineer
operated under the earlier moratorium period. Mountaineer is also required to
make minimum capital expenditures of $9.0 million per year in its utility
operations during the moratorium period. In addition, as a result of the
Shenandoah Gas Company acquisition, Mountaineer is required to spend, at a
minimum, an additional $1.5 million in capital expenditures over a three year
period, ending October 31, 2001.
COMPETITION
- -----------
Competition in the residential and commercial sales market from alternative
energy sources is minimal in West Virginia. Such competition comes primarily
from sources such as electricity, propane, and to a lesser degree, oil, coal and
wood. However, natural gas continues to be the preferred fuel for West Virginia
homes and businesses. Based on 1990 census data, approximately 51% of the
occupied housing units in the state utilized natural gas for home heating, 25%
utilized electricity, with fuel oil, coal and wood comprising the balance.
Mountaineer's demand from commercial and industrial customers is dependent
on local business conditions and competition from alternate sources of energy.
Demand from residential customers likewise is subject to competition from
alternate energy sources. Mountaineer is also subject to competition from
interstate and intrastate pipeline companies, natural gas marketers, producers
and other utilities that may be able to serve commercial and industrial
customers from their transmission, gathering and/or distribution facilities. In
certain markets, gas has a competitive advantage over alternate fuels, while in
other markets it is not as price competitive.
8
Mountaineer began offering gas transportation service to its industrial
customers in 1984. The availability of both firm and interruptible
transportation service, which enables industrial end users to purchase lower
cost gas supplies directly from producers and/or natural gas marketers is an
important factor in maintaining gas usage by those end users during periods of
low residual oil prices. Continued evolution in the natural gas industry,
resulting primarily from Federal Energy Regulatory Commission Order Nos. 436,
500 and 636, has served to increase the ability of large gas end users to bypass
Mountaineer in obtaining gas supply and transportation services. Although no
bypass by customers has occurred to date, Mountaineer generally realizes lower
transportation revenues from large industrial and commercial end users due to
the possibility of such a bypass. In addition, Mountaineer has negotiated
reduced rates for certain end users to: (1) provide economic relief to aid the
end user in remaining an ongoing concern; and (2) add an incentive to end users
to add incremental load.
SEASONALITY
- -----------
More than 95% of Mountaineer's residential and commercial customers use
natural gas for heating purposes. Accordingly, a significant portion of
Mountaineer's utility gas volumes are attributable to sales during the heating
season, with highest sales volumes occurring in December, January and February.
In fiscal 1999, gas sales from October through March accounted for approximately
78.1% of utility gas sales. Weather patterns experienced in the markets served
by Mountaineer significantly impact the demand for natural gas sales,
particularly during the peak heating season and, as a result, will have a
significant impact on Mountaineer's financial performance, liquidity and capital
resources.
GAS AND OIL EXPLORATION AND PRODUCTION
- -------------------------------------------
The Company's proved net gas and oil reserves are estimated as of June 30,
1999 at 166 Bcf and 962 Mbbls, respectively. For the fiscal year ended June 30,
1999, the Company's net gas production was approximately 8.8 Bcf and net oil
production was approximately 133.1 Mbbls, for a total of 9.6 net Bcfe. Revenues
from the sale of oil and gas production accounted for 7.6% of the Company's
consolidated revenues for 1999.
REGIONAL OPERATIONS
- --------------------
APPALACHIAN BASIN. The Company holds interests in 4,783 gross (2,825 net)
------------------
wells in the Appalachian Basin and serves as operator of substantially all of
such wells in which it has a working interest. The Company's proved gas and oil
reserves attributable to its Appalachian Basin properties are estimated as of
June 30, 1999 at 161 Bcfe, of which approximately 97% was gas reserves and 3%
was oil reserves. For the fiscal year ended June 30, 1999, the Company's gas
production from its Appalachian Basin properties was approximately 8.8 net Bcf.
In the Appalachian Basin, the Company has interests in approximately 570,980
gross acres (433,550 net) of producing properties and an additional 112,890
gross acres (76,270 net) of undeveloped properties located primarily in West
Virginia, Pennsylvania and Ohio. During fiscal 1999, the Company drilled 26
successful gross wells (19 net) and added 3.8 net Bcfe in reserves.
ROCKY MOUNTAINS. Westech owns developed and undeveloped leasehold
----------------
interests in approximately 455,000 gross acres (327,000 net) located in the
Rocky Mountain area. The Company has identified and is currently focusing on
five exploratory plays which are located in the Blanding Basin, Utah; Powder
River Basin (Minnelusa-Muddy), Wyoming; Williston Basin, North Dakota; Wind
River Basin, Wyoming and the Danforth area, Colorado. Commencing in June 1999,
the Company entered into a 10 well exploratory drilling program in the Powder
River Basin. Currently, six wells have been drilled, with one successful well.
9
INTERNATIONAL. WENZL currently operates four offshore permits and two
-------------
onshore permits on the East Coast of the North Island of New Zealand, totaling
7,237,000 gross acres (3,618,500 net). Onshore, a total of six exploratory and
four appraisal wells have been drilled. Currently, additional well testing is
being performed to confirm the threshold deliverability requirements for
commercialization. Offshore a 212 square mile 3-D survey has been acquired to
define drillable prospects. WENZL has also been awarded three new onshore
permits in the producing Taranaki Basin of the North Island of New Zealand
totaling 20,000 gross and net acres. WENZL's obligations under these permits
require a 10 square mile 3-D survey, which is planned during fiscal 2000.
Westech is negotiating an agreement to acquire a 35% working interest in the
Cooper Basin, Queensland, Australia. Two wells are planned during fiscal 2000.
OIL AND GAS RESERVES
- -----------------------
The following information relating to estimated reserve quantities, reserve
values and discounted future net revenues is derived from, and qualified in its
entirety by reference to, the more complete reserve and revenue information and
assumptions included in the Company's Supplemental Oil and Gas Disclosures at
Item 8. The Company's estimates of proved reserve quantities of its properties
have been subject to review by Ryder Scott Company, independent petroleum
engineers. There are numerous uncertainties inherent in estimating quantities
of proved reserves and projecting future rates of production and timing of
development expenditures. The following reserve information represents
estimates only and should not be construed as being exact. Future reserve
values are based on year-end prices except in those instances where the sale of
gas and oil is covered by contract terms providing for determinable escalation.
Operating costs, production and ad valorem taxes and future development costs
are based on current costs with no escalations.
The following table sets forth the Company's estimated proved and proved
developed reserves and the related estimated future value, as of June 30:
1999 1998 1997
-------- -------- --------
Net proved:
Gas (Mmcf) 166,268 169,460 160,331
Oil (Mbbls) 962 1,330 1,233
Total (Mmcfe) 172,040 177,440 167,729
Net proved developed:
Gas (Mmcf) 144,643 138,935 141,116
Oil (Mbbls) 717 733 748
Total (Mmcfe) 148,945 143,333 145,604
Estimated future net cash flows
before income taxes (in thousands) $280,636 $286,846 $301,245
Present Value of estimated future net cash
flows before income taxes (in thousands) (1) $117,227 $113,898 $128,440
_______________
(1) Discounted using an annual discount rate of 10%.
10
The following table sets forth the Company's estimated proved reserves and
the related estimated future value by region, as of June 30, 1999:
Present Value
--------------------- Natural Gas
Amount Oil & NGLs Natural Gas Equivalent
Region (thousands) % (Mbbls) (Mmcf) (Mmcfe)
- ------------------ ------------ ------- ----------- ------------ -----------
Appalachian Basin $ 110,245 94.04% 750 156,405 160,905
Rocky Mountains 1,312 1.12% 212 227 1,499
New Zealand 5,670 4.84% 9,636 9,636
- ------------------ ------------ ------- ----------- ------------ -----------
Total $ 117,227 100.00% 962 166,268 172,040
============ ======= =========== ============ ===========
PRODUCING WELLS
- ----------------
The following table sets forth certain information relating to productive
wells at June 30, 1999. Wells are classified as oil or gas according to their
predominant production stream.
Gross Wells Net Wells
----------------- -----------------
Oil Gas Total Oil Gas Total
--- ----- ----- --- ----- -----
Appalachian Basin 13 4,770 4,783 4 2,821 2,825
Rocky Mountains 8 4 12 3 1 4
--- ----- ----- --- ----- -----
Total 21 4,774 4,795 7 2,822 2,829
=== ===== ===== === ===== =====
ACREAGE
- -------
The following table sets forth the developed and undeveloped gross and net
acreage held at June 30, 1999 (in thousands).
Developed Acreage Undeveloped Acreage
---------------- --------------------
Gross Net Gross Net
------- ------- --------- ---------
Appalachian Basin 570,979 433,549 112,887 76,266
Rocky Mountains 560 168 454,440 326,832
New Zealand - - 7,237,000 3,618,500
------- ------- --------- ---------
Total 571,539 433,717 7,804,327 4,021,598
======= ======= ========= =========
11
PRODUCTION
- ----------
The following table sets forth certain production data and average sales
prices attributable to the Company's properties for the years ended June 30:
1999 1998 1997
------ ------ -------
Production Data:
Oil (Mbbls) 133 127 447
Natural gas (Mmcf) 8,840 8,525 9,106
Natural gas equivalent (Mmcfe) 9,638 9,287 11,788
Average Sales Price:
Oil per Bbl $10.76 $14.30 $ 18.13
Natural gas per Mcf $ 2.30 $ 2.61 $ 2.39
DRILLING ACTIVITIES
- --------------------
The Company's gas and oil exploratory and developmental drilling activities
are as follows for the years ended June 30. The number of wells drilled refers
to the number of wells commenced at any time during the respective fiscal year.
A well is considered productive if it justifies the installation of permanent
equipment for the production of gas or oil.
1999 1998 1997
---------------- ----------- ----------
Gross Net Gross Net Gross Net
---------- ---- ----- ---- ----- ---
Development:
Productive
Appalachian 21.0 16.6 27.0 21.6 18.0 9.1
Other 3.0 0.4 5.0 0.9 - -
---------- ---- ----- ---- ----- ---
Total 24.0 17.0 32.0 22.5 18.0 9.1
========== ==== ===== ==== ===== ===
Nonproductive
Appalachian 2.0 1.6 3.0 1.8 - -
Other 3.0 1.3 1.0 0.2 - -
---------- ---- ----- ---- ----- ---
Total 5.0 2.9 4.0 2.0 - -
========== ==== ===== ==== ===== ===
Exploratory:
Productive
Appalachian 5.0 2.4 - - - -
Other 1.0 0.2 4.0 0.9 1.0 0.7
---------- ---- ----- ---- ----- ---
Total 6.0 2.7 4.0 0.9 1.0 0.7
========== ==== ===== ==== ===== ===
Nonproductive
Appalachian 2.0 0.9 - - - -
Other 9.0 4.1 10.0 3.4 8.0 3.7
---------- ---- ----- ---- ----- ---
Total 11.0 5.0 10.0 3.4 8.0 3.7
========== ==== ===== ==== ===== ===
12
COMPETITION
- -----------
The Company encounters substantial competition in acquiring properties,
marketing oil and gas, securing equipment and personnel and operating its
properties. The competitors in acquisitions, development, exploration and
production include major oil companies, numerous independent oil and gas
companies, gas marketers, individual proprietors and others. Many of these
competitors have financial and other resources, which substantially exceed those
of the Company and have been engaged in the energy business for a much longer
time than the Company. Therefore, competitors may be able to pay more for
desirable leases and to evaluate, bid for and purchase a greater number of
properties or prospects than the financial or personnel resources of the Company
will permit.
Natural gas competes with other forms of energy available to customers,
primarily on the basis of price. These alternate forms of energy include
electricity, coal and fuel oils. Changes in the availability or price of
natural gas or other forms of energy, as well as business conditions,
conservation, legislation, regulations and the ability to convert to alternate
fuels and other forms of energy may affect the demand for natural gas.
REGULATIONS AFFECTING OPERATIONS
- ----------------------------------
The Company's operations are affected by extensive regulation pursuant to
various federal, state and local laws and regulations relating to the
exploration for and development, production, gathering, marketing,
transportation and storage of oil and gas. These regulations, among other
things, can affect the rate of oil and gas production. The Company's operations
are subject to numerous laws and regulations governing plugging and abandonment,
the discharge of materials into the environment or otherwise relating to
environmental protection. These laws and regulations require the acquisition of
a permit before drilling commences, restricts the types, quantities and
concentration of various substances that can be released into the environment in
connection with drilling activities on certain lands lying within wilderness,
wetlands and other protected areas, and impose substantial liabilities for
pollution which might result from the Company's operations.
GAS AGGREGATION AND MARKETING
- ---------------------------------
The Company, primarily through the wholly owned subsidiary of Eastern
American, Eastern Marketing Corporation ("Eastern Marketing"), aggregates
natural gas through the purchase of production from properties in the
Appalachian Basin in which the Company has an interest, the purchase of gas
delivered through the Company's gathering pipelines located in the Appalachian
Basin, the purchase of gas from smaller Appalachian Producers that are not large
enough to have marketing departments, the purchase of gas produced in the
Southwestern areas of the United States pursuant to contractual arrangements and
the purchase of gas in the spot market. The Company sells gas to local gas
distribution companies, industrial end users located in the Northeast, other gas
marketing entities and into the spot market for gas delivered into interstate
pipelines. The Company has historically attempted to balance its gas sales mix
with approximately one-third of its total gas sales being made under long term
contracts (contracts with terms of five years or more), one-third being sold
under intermediate term contracts (contracts with terms of one to five years),
and one-third being sold under short term contracts (contracts with terms of
less than one year) or on a spot market basis. The demand for long term
contracts has decreased substantially and no new long term contracts were
entered into in fiscal year 1999. Volumes that became available from expired
long term contracts were sold under intermediate and short term contracts.
13
The Company owns and operates approximately 2,100 miles of gathering lines
and intrastate pipelines that are used in connection with its gas aggregation
and marketing activities. In addition, the Company has entered into contracts
with interstate pipeline companies that provide it with rights to transport
specified volumes of natural gas. During the fiscal year ended June 30, 1999,
the Company aggregated and sold an average of 95.7 Mmcf of gas per day, of which
39.7 Mmcf per day represented sales of gas produced from wells operated by the
Company. This represents a decrease compared to fiscal year 1998, during which
the Company aggregated and sold an average of 129.5 Mmcf of gas per day.
GAS SALES AND PURCHASE CONTRACTS
- -------------------------------------
The termination of one long term and one intermediate term sales contract
resulted in the 33.8 Mmcf per day decrease in sales in fiscal year 1999. The
sale of gas on a contract basis to the Company's natural gas distribution
utility expired on October 31, 1998 (23.8 Mmcf per day). The Company elected
not to renew the contract, allowing both parties to seek more economical sales
and purchases of natural gas from independent third parties.
The Company satisfied its obligations under all gas sales contracts in
fiscal year 1999 through gas production attributable to its own interests in oil
and gas properties and through production attributable to third party interests
in oil and gas properties (14.5 Bcf in fiscal 1999), and from natural gas
aggregated by the Company pursuant to its aggregation and marketing activities
from third parties (20.5 Bcf in fiscal 1999).
Eastern American has a gas sales contract with Hope Gas, Inc. ("Hope"), a
subsidiary of Consolidated Natural Gas, which requires Eastern American to sell
up to 4,000 but not less than 1,500 Mmbtu per day during the winter months of
November through March to Hope through December 31, 2001. Pricing under the
contract requires Hope to pay Eastern American a ten cent premium above the
posted Appalachian Index.
In March 1993, the Company conveyed to the Eastern American Natural Gas
Trust (the "Royalty Trust"), a trust whose units are traded on the New York
Stock Exchange, certain net profits interests derived from the Company's working
interest in certain natural gas properties located in the Appalachian Basin
whose production is eligible for tax credits under Section 29 of the Internal
Revenue Code. In connection with the Royalty Trust, Eastern Marketing entered
into a gas purchase contract to purchase all gas production attributable to the
Royalty Trust until termination of the Royalty Trust in May 2013. The purchase
price under this gas purchase contract through December 1999 is based in part on
a fixed price component, which escalates each year, and in part on a variable
price component, which fluctuates with certain spot market prices, provided that
the purchase price during such period will not be less than a specified floor
price. The floor price was $2.84 per Mcf in calendar year 1998 and is $3.09 per
Mcf in calendar year 1999. The fixed price component was $3.39 in calendar year
1998 and is $3.56 in calendar year 1999. The variable price is equal to the
future contract price per Mmbtu for natural gas delivered to Henry Hub,
Louisiana plus $0.30 per Mmbtu, multiplied by 110% to reflect a fixed adjustment
for Btu content. The fixed price component is given a weighting of 66 2/3% and
the variable price component is given a weighting of 33 1/3% through December
1999. Beginning in January 2000, the purchase price under this gas purchase
contract will be determined solely by reference to the variable price component
without regard for any minimum purchase price. Eastern American is a party to a
standby performance agreement with the Royalty Trust to support the obligations
of Eastern Marketing under this gas purchase contract.
14
MARKET POSITION
- -----------------
During fiscal 1999, Eastern Marketing purchased call options on 5,000 Mmbtu
of natural gas per day for the period March 1999 through October 1999. The
options were purchased for approximately $0.4 million, or $0.31 per Mmbtu. The
options provided the Company with the right to purchase up to 5,000 Mmbtu per
day during the option period at a price of $2.25 per Mmbtu.
MARKETING FOCUS CHANGE
- -------------------------
At the close of the 1999 fiscal year, it was determined that Eastern
Marketing would no longer enter into contracts to purchase independent producers
gas as this business was becoming less economical to maintain each year. The
strong competition among various marketing companies for this business is
causing margins to "shrink" each year, and in the Company's opinion, this type
of business is rapidly losing its economic validity. Third party contract
business is labor intensive, requiring a sales staff and related accounting
services. It is the intention of Eastern Marketing to sell this portion of its
business, provided an acceptable offer can be achieved, or to operate the
existing contracts until they expire. Most of the effected contracts expire
within a one year period. With this new marketing focus, Eastern Marketing
should be better poised to concentrate its efforts on marketing Eastern
American's natural gas.
REGULATIONS AFFECTING MARKETING AND TRANSPORTATION
- ------------------------------------------------------
As a marketer of natural gas, the Company depends on the transportation
and storage services offered by various interstate and intrastate pipeline
companies for the delivery and sale of its own gas supplies as well as those it
processes and/or markets for others. Both the performance of transportation and
storage services by interstate pipelines and the rates charged for such services
are subject to the jurisdiction of the FERC. In addition, the performance of
transportation and storage services by intrastate pipelines and the rates
charged for such services are subject to the jurisdiction of state regulatory
agencies.
EMPLOYEES
- ---------
As of June 30, 1999, the Company had approximately 760 full-time employees.
Approximately 290 employees are covered by six separate collective bargaining
agreements. None of these agreements will expire during the next fiscal year.
Management believes that its relationship with its employees is good.
ITEM 2. PROPERTIES
------- ----------
See Item 1. Business, for information concerning the general location and
characteristics of the important physical properties and assets of the Company
and information regarding production, reserves, development and interests in oil
and gas producing properties of the Company.
ITEM 3. LEGAL PROCEEDINGS
------- -----------------
The Company is involved in various legal actions and claims arising in the
ordinary course of business. While the outcome of these lawsuits against the
Company cannot be predicted with certainty, management does not expect these
matters to have a material adverse effect on the Company's operations or
financial position.
15
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
------- ---------------------------------------------------
No matters were submitted to a vote of security holders during the fourth
quarter of fiscal year 1999.
PART II
-------
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK
------- ----------------------------------------
AND RELATED STOCKHOLDER MATTERS
-------------------------------
The Company's common stock is not traded in a public market. As of
September 1, 1999, the Company had 25 holders of record of its common stock.
The Company declared dividends in fiscal years 1999, 1998 and 1997 of
$644,505, $1,131,000 and $1,007,000, respectively.
ITEM 6. SELECTED FINANCIAL DATA
------- -----------------------
Year Ended June 30,
-------------------------------------------------
1999 1998 1997 1996 1995
--------- -------- -------- -------- --------
(Dollars in Thousands, except per share items)
Operating revenue $285,603 $364,336 $373,961 $375,794 $145,494
Income (loss) from continuing operations (14,887) 3,014 2,018 7,820 1,185
Income (loss) from continuing operations
Per common share, basic (22.12) 4.53 2.93 11.16 1.68
Per common share, assuming dilution (22.12) 4.53 2.93 11.15 1.68
Total assets 436,942 439,945 434,757 461,504 471,497
Long term debt 280,021 261,507 260,089 254,647 267,647
Dividends declared per common share $ 0.95 $ 1.70 $ 1.50 $ 2.10 $ 0.65
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF
------- --------------------------------------------------
OPERATIONS AND FINANCIAL CONDITION
----------------------------------
The following should be read in conjunction with the Company's Financial
Statements and notes (including the segment information) at Item 8 and the
Selected Financial Data at Item 6.
This discussion and analysis of financial condition and results of
operations, and other sections of this Form 10-K, contain forward-looking
statements that are based on management's beliefs, assumptions, current
expectations, estimates 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.
16
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 YEARS ENDED JUNE 30, 1999 AND 1998
- --------------------------------------------------------------------------------
The Company recorded a net loss of $14.9 million for the year ended June
30, 1999 compared to net income of $3.0 million for the same period in 1998. The
decrease in income of $17.9 million is attributed to a $78.7 million decrease in
revenue, which was partially offset by a $60.7 million decrease in operating
expenses, an $11.1 million increase in impairment and exploratory costs, a $3.9
million increase in other income and a $7.2 million increase in income tax
benefits.
OPERATING MARGINS. Operating Margins (defined as revenue less operating
------------------
costs, taxes other than income taxes, and direct general and administrative
expense) for the Company's operating subsidiaries totaled $49.4 million for the
current year compared to $33.9 million for the prior period. The Company's
Utility Operating Margin (defined as total revenue less utility gas purchased,
utility operations and maintenance expense, taxes other than income taxes and
direct general and administrative expense) totaled $32.6 million for the current
period versus $20.8 million for the prior year. The Company's Oil and Gas
Operating Margin (defined as oil and gas sales and well operations and service
revenues less field operating expenses, taxes other than income, and direct
general and administrative) totaled $12.3 million versus $15.4 million for the
prior year. The Company's Marketing and Pipeline Operating Margin (defined as
gas marketing and pipeline sales less gas marketing pipeline cost of sales)
totaled $4.5 million for the current period versus a loss of $2.3 million for
the prior period.
REVENUES. Total revenues decreased $78.7 million or 21.6% during the
--------
periods. The decrease was due to a 32.4% decrease in gas marketing and pipeline
sales, a 12.0% decrease in oil and gas sales, and a 95.6% decrease in other
operating revenue. Utility gas sales and transportation and well and service
operating revenue remained relatively constant between the periods.
Revenues from gas marketing and pipeline sales decreased $46.6 million from
$144.1 million during the period ended June 30, 1998 to $97.5 million in the
period ended June 30, 1999. The decrease in revenue is primarily attributable
to a 12% decrease in the average unit price from $2.63 to $2.32 and a 27%
decline in marketed volumes from 50.7 million dth at June 30, 1998 to 37.2
million dth at June 30, 1999. The decrease in volumes is primarily a result of
the termination of two contracts that accounted for 9.5 Bcfe and reduced volumes
associated with trading activities. See other operating revenue, discussed
below.
Revenues from oil and gas sales decreased $3.0 million from $24.7 million
for the period ended June 30, 1998 to $21.7 million for the period ended June
30, 1999. The decrease in revenue is primarily attributable to a 29.6% decrease
in the average oil sales price from $15.30 to $10.76 per Bbl and an 8.59%
decrease in the average gas sales price from $2.52 to $2.30 per Mcf between June
30, 1998 and June 30, 1999. The price decline was partially offset by production
increasing 6.21% for oil and 1.23% for gas.
17
Other operating revenues decreased $30.8 million from $32.2 million to $1.4
million between the periods. This was primarily because 1998 included revenue
from the termination of a long-term gas delivery contract. See Note 17 to the
Consolidated Financial Statements for discussion.
COSTS AND EXPENSES. The Company's costs and expenses decreased $60.7
--------------------
million or 18.9% during this period primarily as the result of a 13.3% decline
in the cost of utility gas purchased, a 36.5% decrease in gas marketing and
pipeline costs, which was partially offset by a 7.6% increase in general and
administrative expenses, a 10.0% increase in depreciation, depletion and
amortization and a 134.7% increase in impairment and exploratory costs. Field
and lease operating expenses, utility operations and maintenance costs and taxes
other than income remained relatively constant between the periods.
The $11.3 million decline in the cost of utility gas purchased was
primarily the result of the nonrecurring effect of the initial implementation of
Mountaineer's gas supply management agreement with a third party, which was
effective November 1, 1998.
The $53.4 million decrease in gas marketing and pipeline costs is primarily
the result of a 27% decline in purchased gas volumes from 51.1 Bcfe to 37.6 Bcfe
from June 30, 1998 and June 30, 1999. Contributing to the decline in costs was
a 15% decrease in the average price paid for gas purchased, from $2.67 per Mmbtu
to $2.26 per Mmbtu between the respective periods. Additionally, approximately
$2.4 million of purchased gas costs was charged against a reserve for losses on
future gas purchases, which was primarily related to the contract settlement.
See Note 17 to the Consolidated Financial Statements for discussion.
General and administrative expense increased $1.8 million as a result of
higher labor and benefit costs at the utility and increased overhead at the
corporate level.
Depreciation, depletion and amortization costs increased $2.0 million
primarily due to additions to the utility gas plant in service and corporate
fixed assets.
Impairment and exploratory expenses increased $11.1 million primarily due
to the current year cost of drilling exploratory dry holes of $5.9 million in
New Zealand and $1.6 million domestically. In addition, approximately $2.2
million of leasehold and well in progress costs were written off late in fiscal
1999.
INTEREST EXPENSE. Interest expense remained relatively constant between
-----------------
the periods.
OTHER (INCOME) EXPENSE. Other income increased $3.9 million primarily due
-----------------------
to the recognition of gains on the sale of property during fiscal 1999, compared
to losses in the prior year. Also, during fiscal 1998 a reserve of $1.1 million
was established against a note receivable.
PROVISION FOR INCOME TAXES. The provision for income taxes changed $7.2
-----------------------------
million primarily because of the current year loss.
COMPARISON OF RESULTS OF OPERATIONS FOR THE YEARS ENDED JUNE 30, 1998 AND 1997
- --------------------------------------------------------------------------------
The Company recorded net income and income before extraordinary loss of
$3.0 million for the year ended June 30, 1998 compared to a net loss of $5.8
million and income before extraordinary loss of $2.0 million for the same period
in 1997. The increase in income before extraordinary loss of $1.0 million is
attributed to the contract settlement under which the company received
approximately $30 million (net) in cash and related partnership distributions as
described in Note 17 to the Consolidated Financial Statements. The increase
resulting from the contract settlement was partially offset by a $15 million
decrease in operating income resulting generally from the effects of a warmer
heating season resulting in a $1.3 million reduction in operating income, lower
oil and gas sales, and lower gas marketing and pipeline margins resulting in a
$12.5 million reduction in operating income and increased corporate expenses of
$1.0 million. Additionally, interest expense increased $2.5 million and gain on
sales of assets and other income and expenses decreased $11.7 million between
the two periods.
18
OPERATING MARGINS. Total Operating Margins for the Company's operating
------------------
subsidiaries totaled $33.9 million for 1998 compared to $50.6 million for 1997.
The Company's Utility Operating Margin decreased from $22.3 for 1997 to $20.8
million for 1998. The Company's Oil and Gas Operating Margin decreased from
$18.9 million for 1997 to $15.4 million for 1998. The Company's Marketing and
Pipeline Operating Margin decreased from $9.3 million for the prior year to a
loss of $2.3 million for the current year.
REVENUES. Total revenues decreased $9.6 million or 2.6% during the
--------
periods. The decrease was due to a 9.7% decrease in utility gas sales and
transportation, an 10.1% decrease in gas marketing and pipeline sales and a
25.9% decrease in oil and gas sales, which were partially offset by a $31.9
million increase in other operating revenue. See Note 17 to the Consolidated
Financial Statements for discussion.
Revenues from utility gas sales and transportation decreased $16.9 million
or 9.7% from $173.5 million during the year ended June 30, 1997 to $156.6
million for the same period ended June 30, 1998. The decrease is primarily due
to approximately 3.0 million Mcf less in volumes of gas sold as a result of a
6.3% decrease in the weighted average number of Degree Days in the current
period, partially offset by a 3.2% increase in transportation revenue due to
increased usage by commercial and industrial customers.
Revenues from gas marketing and pipeline sales decreased $16.2 million from
$160.3 million during the period ended June 30, 1997 to $144.1 million in the
period ended June 30, 1998. The decrease in revenue is primarily attributable
to a 3.7% decrease in the average unit price and a 7.5% decline in marketed
volumes from 56.0 million dth at June 30, 1997 to 51.8 million dth at June 30,
1998. The decrease in volumes is a result of a change in pipeline sales and
transportation components, discontinued pipeline sales to a customer, and
reduced volumes associated with trading activities.
Revenues from oil and gas sales decreased $8.6 million from $33.3 million
for the period ended June 30, 1997 to $24.7 million for the period ended June
30, 1998. The decrease in revenue is primarily attributable to a 22.9% decline
in units sold from 12.4 Bcfe at June 30, 1997 to 9.3 Bcfe and a 3.9% decrease in
the average unit sales price from $2.69 to $2.58 per Mcfe for the respective
periods. The 22.9% decline in units sold between June 30, 1997 and 1998 was
primarily as a result of the sale of the Company's limited partnership interests
in Westside Operating Partnership LP ("WOPLP"), which accounted for 2.7 Bcfe and
96.8% of the total decline in units sold. The sale of WOPLP occurred in March
1997.
Other operating revenues increased $31.9 million between the periods
primarily as a result of an agreement to terminate an existing long-term gas
delivery contract. See Note 17 to the Consolidated Financial Statements for
discussion.
COSTS AND EXPENSES. The Company's costs and expenses decreased $25.0
--------------------
million or 7.0% during this period primarily as the result of a 15.5% decline in
the cost of utility gas purchased, a 3.0% decrease in gas marketing and pipeline
costs, a 29.5% decline in the field and lease operating expenses and an 18.4%
decline in impairment and exploratory expenses.
19
The $15.6 million decline in the cost of utility gas purchased was the
result of a decrease in purchased gas volumes of 3.7 Bcf and a decrease in the
average commodity price of natural gas of approximately $0.15 per Mcf purchased
and a $1.9 million decrease in demand charges resulting primarily from a rate
settlement with Columbia Gas Transmission Corporation during fiscal year 1997.
The $4.6 million decrease in gas marketing and pipeline costs is the result
of a 3.9 million dth decline in volumes marketed offset by a $0.09 increase in
the average unit cost of gas sold during fiscal year 1997.
The $4.1 million decline in field and lease operating expense was primarily
the result of the reduction in operating costs of $3.5 million associated with
the sale of the limited partnership interests previously discussed.
Utility operations and maintenance costs increased 3.8% as a result of
increased outside services ($0.3 million) and increased labor costs ($0.3
million)
General and administrative expense increased 3.0% as a result of the
inclusion of the selling expenses of Mapcom Systems, Inc. ($1.3 million)
acquired by Mountaineer in November 1997 partially offset by generally lower
expenses for outside services.
Taxes other than income decreased 7.5% generally as a result of lower
revenues.
Impairment and exploratory expenses decreased $1.9 million primarily due to
non-recurring write-offs of exploratory properties in fiscal 1997 resulting from
decreased domestic exploratory activities and unsuccessful exploratory drilling.
Depreciation of pipelines, other property and equipment increased $1.7
million or 16.8% as a result of higher depreciation related to an increase in
property in service and the effective depreciation rate.
Depletion and depreciation of oil and gas properties decreased $0.7
million. The decrease related to the sale of the WOPLP properties in fiscal year
1997 which accounted for 2.7 Bcfe of production partially offset by a 17.0%
increase in depletion and depreciation rates.
INTEREST EXPENSE. Interest expense increased 10.5% from $23.9 million to
-----------------
$26.4 million in the current year. The increase was due to the additional
average long-term debt outstanding during the periods resulting from the
issuance of the Senior Subordinated Notes and higher interest rates during the
fiscal year ended June 30, 1998.
OTHER (INCOME) EXPENSE. Other income decreased $9.5 million primarily due
-----------------------
to the sale of WOPLP, which occurred in March 1997 resulting in a gain of $7.8
million compared to a loss of $1.2 million on the disposal of certain oil and
gas properties during the year ended June 30, 1998.
PROVISION FOR INCOME TAXES. The provision for income taxes excluding the
----------------------------
tax benefit for the extraordinary loss was relatively unchanged between the
years.
EXTRAORDINARY LOSS. The extraordinary loss of $7.9 million (net of a $4.2
- --------------------
million tax benefit) recorded during the fiscal year ended June 30, 1997 was due
to the early extinguishment of debt. In May 1997, the Company issued $200
million Senior Subordinated Notes using the proceeds therefrom to repay debt at
Eastern Systems Corporation ("ESC") and Eastern American of $35 million and $136
million, respectively.
20
LIQUIDITY AND CAPITAL RESOURCES
- ----------------------------------
Despite improved Operating Margins (as defined above) from the Company's
operating subsidiaries, $49.4 million for the current period versus $33.9
million for the prior period, the Company's financial condition declined during
the current period. The Company's consolidated working capital and funds
available from unused short-term credit facilities and revolving credit
facilities declined from $105.7 million at June 30,1997 to $89.5 million at June
30, 1998 and $37.3 million at June 30, 1999.
Historically, the Company's growth has been accomplished through direct
investment in utility operations ($11.4 million 1999, $15.8 million 1998, $9.9
million 1997) and exploration and development drilling activities ($25.3 million
1999, $20.6 million 1998, $18.0 million 1997). These investments were primarily
financed through a combination of cash provided from operations and through
short and long-term debt financing consisting of $6.2 million cash provided by
operating activities and $22.0 million in proceeds from debt facilities for the
current period, $6.6 million (excluding $30.1 million from a non-recurring
transaction) and $4.5 million respectively for the prior period and $11.4
million and $22.4 million for the period ending June 30, 1997.
In general, the investment return on the Company's capital expenditures for
its utility subsidiary has enabled management of the utility to increase its
Operating Margins and cash provided (used) from operations from $22.3 million
and $(5.1) million in 1997, to $20.8 million and $25.2 million in 1998 to $32.6
million and $28.7 million in 1999, respectively. However, returns on the
Company's investments in its oil and gas operating subsidiaries has fallen below
expectations of management during the same three year period. Operating Margins
and cash provided (used) in operations for the Company's oil and gas operating
subsidiaries totaled $18.9 million and $14.2 million for 1997, $15.4 million and
$6.3 million for 1998, and $12.3 million and $0.4 million in 1999, respectively.
As a result of the lower than expected returns on the Company's investments in
its oil and gas operating subsidiaries, the Company's primary sources of
liquidity (cash provided by operating activities and short and long-term debt)
has been adversely impacted.
In addition to, and primarily as a result of the foregoing, the Company was
in violation of certain covenants of its Revolving Debt Agreement at June 30,
1999 relating to (1) Tangible Net Worth, (2) Current Ratio, and (3) Minimum
Interest Coverage Ratio. The Company's lenders have not accelerated the debt.
However, as a result of the non-monetary violations described above, the Company
was prohibited from drawing down additional borrowings under the Revolving Debt
Agreement. Moreover, if the debt had been accelerated, the Company would have
been required to repay the $25 million drawn under the Revolving Debt Agreement.
Furthermore, an acceleration of the debt under the Revolving Debt Agreement
would have also triggered a cross-default provision of the Company's $200
million Senior Subordinated Notes. Under this circumstance, the Company would
have considered various alternatives, including seeking new and or additional
credit facilities, the sale of certain assets, or other options, to acquire such
funds or restructure its debt.
21
Since June 30, 1999, the Company and its lenders have agreed to amend the
Revolving Debt Agreement to include (1) a reduction of the credit availability
under the Revolving Debt Agreement from $50 million to $22 million, (2) a waiver
of the non-monetary violations as described above, and (3) certain amendments to
the Revolving Debt Agreement which would restructure certain financial covenants
as follows (a) Tangible Net Worth, as defined in the Amendment, will not be less
than $20 million plus fifty percent (50%) of Consolidated Net Income earned
during the period from June 30, 1997, after adding back approximately $19
million, (b) Current Ratio, as defined in the Amendment, requirement from 1 to 1
to 0.6 to 1 through December 30, 1999 and 1 to 1 thereafter, such current ratio
calculation shall be calculated without including any payments of principal on
the Notes or Subordinated Notes which might be required to be repaid within one
year from the time of the calculation, and (c) Interest Coverage ratio, as
defined in the Amendment, reduced from a minimum of 1.5 to 1 to 1.15 to 1 for
the next four quarters and 1.5 to 1 thereafter, except that Adjusted EBITDA, as
defined in the Amendment, and as utilized in the numerator within such
calculation shall have an amount of $19 million added thereto and such
adjustment shall be effective for the calculation during the fiscal quarters
ended September 30, 1999, December 31, 1999, March 31, 2000, and June 30, 2000.
As part of the foregoing waivers and amendments, the Company has agreed to
(1) make an immediate principal reduction payment of $3 million, (2) make four
consecutive quarterly principal payments of $750,000, (3) set the interest rate
on borrowed amounts at LIBOR plus 300 basis points, (4) pay certain fees
totaling $335,000, and (5) permit subsequent redeterminations of the Borrowing
Base as defined under the Revolving Debt Agreement, to be determined, at the
discretion of the lenders, more than once during a fiscal year.
Mountaineer plans to issue approximately $40 million in unsecured,
long-term notes during the fourth quarter of calendar 1999. The proceeds from
this issuance will be used to reduce short-term borrowings ($16.8 million at
June 30, 1999) and for general corporate uses of the utility. While this
financing will significantly improve the consolidated current ratio,
restrictions limit dividend and other payments to the Company from Mountaineer.
Currently, Mountaineer has $67 million of unsecured revolving bank lines of
credit, under which approximately $16.8 million (see above discussion) was drawn
at June 30, 1999. Under Mountaineer's debt covenants, which restrict cash
outflow, $7.3 million of dividends are available to the Company.
The Company believes that its existing capital resources and expected
fiscal year 2000 results of operation will be sufficient for the Company to
remain in compliance with the requirements of the amended Revolving Debt
Agreement, and its Senior Subordinated Note Agreement, and to fund
non-discretionary capital expenditures. However, although the Company expects
that Operating Margins and cash provided from operations will improve, the
Company can give no assurances that such improvements will be realized or that
certain violations of the amended Revolving Debt Agreement and Senior
Subordinated Note Agreement will not occur, since the future profitability, debt
service capability and levels of capital resource as well as capital
availability will depend to a great extent on future weather patterns, oil and
gas prices, and future exploration and development drilling success. In the
event that Operating Margins and cash provided from operations do not meet
expectations of management or if additional debt covenant or debt service
violations occur, the Company may elect to increase debt levels, restructure
debt agreements, sell certain assets or operating subsidiaries, defer certain
discretionary capital spending (including oil and gas exploration and
development drilling activities), consolidate certain field operations, or take
other actions to mitigate liquidity short-falls and remedy any foreseeable or
potential debt covenant issues, 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
substantially 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.
22
These steps include the purchase and implementation of an integrated
application software package, that together with the associated hardware and
external consulting resources, is expected to cost approximately $7.1 million.
In addition, the Company is presently in the process of modifying existing
operating and application systems that are not Year 2000 compliant and
anticipates that it will be successful in completing such modifications before
the calendar year ended 1999. 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 systems are
expected to 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 may invest 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 anticipates
capitalizing and depreciating such costs over their estimated useful life.
In addition to reviewing its own computer operating and application
systems, the Company has initiated communications with its significant suppliers
and vendors to determine the extent to which these parties have addressed Year
2000 issues. To the extent such vendors cannot provide reasonable assurances to
the Company of their readiness to handle Year 2000 issues, contingency plans
will be 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.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES
-------- ----------------------------------------
ABOUT MARKET RISK
-----------------
INTEREST RATE RISK
- ---------------------
Interest rate risk is attributable to the Company's debt. The Company
utilizes United States dollar denominated borrowings to fund working capital and
investment needs. There is inherent rollover risk for borrowings as they mature
and are renewed at current market rates. The extent of this risk is not
predictable because of the variability of future interest rates and the
Company's future financing needs. If interest rates changed by 1%, it would have
an impact of approximately $0.4 million. The Company has not attempted to hedge
the interest rate risk associated with its floating rate debt of which $41.8
million was outstanding at year end. The Company has fixed interest rate debt of
$261.7 million, representing 86.2% of the total debt.
23
COMMODITY RISK
- ----------------
The Company's operations, as described in detail at Item 1 Business,
consists primarily of exploring for, producing, aggregating and distributing
natural gas and oil. The Company attempts to mitigate its commodity price risk
by entering into a mix of short, medium and long-term supply contracts.
Contracts to deliver gas at pre-established prices mitigate the risk to the
Company of falling prices but at the same time limit the Company's ability to
benefit from the effects of rising prices. The Company occasionally uses
derivative instruments to hedge its commodity price risk. Notwithstanding the
above, the Company's future cash flows from gas and oil production are exposed
to significant volatility as commodity prices change.
The Company periodically enters into hedging activities on a portion of its
projected natural gas production through a variety of financial and physical
arrangements intended to support natural gas prices at targeted levels and to
manage its exposure to price fluctuations. The Company may use futures
contracts, swaps, options and fixed price physical contracts to hedge its
commodity prices. Realized gains and losses from the Company's price risk
management activities are recognized in oil and gas sales when the associated
production occurs. The Company does not hold or issue derivative instruments for
trading purposes. For fiscal 2000, the Company has elected to enter into a
combination of forward sale collars and floors, covering the majority of its
Appalachian natural gas.
Mountaineer has entered into a new rate moratorium with the WVPSC through
2001 thereby potentially exposing itself to volatility in its gas supply costs.
If such risk was left unhedged, its future cash flows could vary significantly
from historical cash flows. Mountaineer has entered into the Supply Agreement
with Coral, under which Mountaineer will purchase approximately 90% of its
natural gas supply at a fixed cost for the full duration of the rate moratorium
thereby substantially reducing its exposure to market volatility.
24
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
------- -------------------------------------------
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, 1999 and 1998, and the
related consolidated statements of operations, stockholders' equity, and cash
flows for each of the three years in the period ended June 30, 1999. Our audits
also included the financial statement schedules listed in the Index at Item 14.
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, 1999 and 1998, and the results of their operations
and their cash flows for each of the three years in the period ended June 30,
1999 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.
DELOITTE & TOUCHE LLP
Denver, Colorado
September 27, 1999
25
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
JUNE 30, 1999 AND 1998
(AMOUNTS IN THOUSANDS)
- -----------------------------------------------------------------------------------
ASSETS 1999 1998
------------ ---------
CURRENT ASSETS:
Cash and cash equivalents $ 13,557 $ 21,547
------------ ---------
Accounts receivable:
Utility gas and transportation 14,259 13,027
Gas marketing and pipeline 4,311 5,528
Oil and gas sales 6,686 7,595
Other 9,220 7,959
------------ ---------
34,476 34,109
Less allowance for doubtful accounts (1,622) (1,281)
------------ ---------
32,854 32,828
Gas in storage, at average cost 357 13,249
Income taxes receivable 3,580 4,310
Deferred income tax asset 3,702
Prepaid winter gas service 18,474
Prepaid and other current assets 3,444 5,839
------------ ---------
Total current assets 75,968 77,773
NET PROPERTY, PLANT AND EQUIPMENT (Note 2) 315,316 318,547
------------ ---------
OTHER ASSETS:
Deferred financing costs, less accumulated
amortization of $2,485 and $1,046 8,523 9,545
Notes receivable, less allowance for doubtful accounts
of $440 and $400 1,531 2,902
Notes receivable - related party 2,013 2,716
Deferred utility charges 18,785 18,233
Other 14,806 10,229
------------ ---------
Total other assets 45,658 43,625
------------ ---------
TOTAL $ 436,942 $439,945
============ =========
See notes to consolidated financial statements. (Continued)
26
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
JUNE 30, 1999 AND 1998
(AMOUNTS IN THOUSANDS, EXCEPT SHARES)
- ------------------------------------------------------------------------------------
LIABILITIES AND STOCKHOLDER'S EQUITY 1999 1998
--------- ---------
CURRENT LIABILITIES:
Accounts payable and accrued expenses $ 40,049 $ 38,883
Current portion of long-term debt 6,634 581
Short-term debt 16,799 19,174
Funds held for future distribution 5,378 5,716
Accrued taxes, other than income 7,635 8,472
Overrecovered gas costs 3,927 6,485
Deferred income tax liability 5,643
Other current liabilities 8,465 8,115
--------- ---------
Total current liabilities 88,887 93,069
LONG-TERM OBLIGATIONS
Long-term debt 280,021 261,507
Gas delivery obligation and deferred trust revenue 13,839 16,127
Deferred income tax liability 27,868 24,552
Other long-term obligations 11,850 12,837
--------- ---------
Total liabilities 422,465 408,092
--------- ---------
COMMITMENTS AND CONTINGENCIES (Note 15)
MINORITY INTEREST - 1,883
--------- ---------
STOCKHOLDER'S EQUITY:
Common stock, par value $1.00; 2,000,000 shares authorized;
721,000 and 720,000 shares issued in 1999 and 1998 721 720
Class A non-voting common stock, no par value; 100,000
shares authorized; 26,000 shares issued in 1999 2,940 -
Additional paid-in capital 4,656 4,510
Retained earnings 13,598 29,132
Treasury stock and notes receivable arising from
issuance of common stock (7,261) (4,082)
Accumulated comprehensive loss (177) (310)
--------- ---------
Total stockholder's equity 14,477 29,970
--------- ---------
TOTAL $436,942 $439,945
========= =========
See notes to consolidated financial statements. (Concluded)
27
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED JUNE 30, 1999, 1998 AND 1997
(AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
- ------------------------------------------------------------------------------------------------------------
1999 1998 1997
--------- -------- ---------
REVENUES:
Utility gas sales and transportation $158,439 $156,579 $173,463
Gas marketing and pipeline sales 97,467 144,133 160,345
Oil and gas sales 21,727 24,689 33,301
Well operations and service revenues 6,540 6,751 6,526
Contract settlement and other 1,430 32,184 306
--------- -------- ---------
285,603 364,336 373,941
--------- -------- ---------
COSTS AND EXPENSES:
Utility gas purchased 73,842 85,166 100,774
Gas marketing and pipeline cost of sales 92,981 146,367 150,967
Field operating expenses 9,214 9,788 13,913
Utility operations and maintenance 22,496 22,084 21,320
General and administrative 25,112 23,330 22,640
Taxes, other than income 15,260 14,882 16,094
Depletion and depreciation of oil and gas properties 8,409 8,021 8,756
Depreciation of pipelines, other property and equipment 13,629 12,017 10,289
Exploration and impairment 19,388 8,262 10,121
--------- -------- ---------
280,331 329,917 354,874
--------- -------- ---------
Income from operations 5,272 34,419 19,067
--------- -------- ---------
OTHER (INCOME) AND EXPENSE:
Interest 26,554 26,386 23,881
Loss (gain) on sale of assets (91) 1,208 (8,303)
Other (1,079) 1,551 (647)
--------- -------- ---------
25,384 29,145 14,931
--------- -------- ---------
Income (loss) before income taxes, minority interest and extraordinary loss (20,112) 5,274 4,136
Provision (benefit) for income taxes (5,232) 2,017 1,966
--------- -------- ---------
Income (loss) before minority interest and extraordinary loss (14,880) 3,257 2,170
Minority interest 7 243 152
--------- -------- ---------
Income (loss) before extraordinary loss (14,887) 3,014 2,018
Extraordinary loss on early extinguishment of debt (net of income
tax benefit of $4,233) - - 7,861
--------- -------- ---------
NET INCOME (LOSS) $(14,887) $ 3,014 $ (5,843)
========= ======== =========
Earnings per common share
Income before extraordinary loss $ (22.12) $ 4.53 $ 2.93
Extraordinary loss - - $ (11.42)
--------- -------- ---------
Basic earnings (loss) per common share $ (22.12) $ 4.53 $ (8.49)
========= ======== =========
Diluted earnings (loss) per common share $ (22.12) $ 4.53 $ (8.49)
========= ======== =========
See notes to consolidated financial statements.
28
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERSEQUITY
FOR THE YEARS ENDED JUNE 30, 1999, 1998 AND 1997
(AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
- ------------------------------------------------------------------------------------------------------------------
Class A Additional
Common Common Paid-In Retained Treasury
Stock Stock Capital Earnings Stock
------- -------- ----------- ---------- ----------
Balance, June 30, 1996 $ 711 $ - $ 4,086 $ 34,099 $ (1,121)
Components of comprehensive loss:
Foreign currency translation adjustment
Net loss (5,843)
Comprehensive loss
Dividends ($1.50 per share) (1,007)
Exercise of employee stock options for notes receivable 3 125
Issuance of common stock 10
Purchase of treasury stock (2,054)
Reduction of notes receivable
------- -------- ----------- ---------- ----------
Balance, June 30, 1997 714 - 4,221 27,249 (3,175)
Components of comprehensive income:
Foreign currency translation adjustment
Net income 3,014
Comprehensive income
Dividends ($1.70 per share) (1,131)
Issuance of common stock 3 164
Exercise of employee stock options for notes receivable 3 125
Purchase of treasury stock (523)
Reduction of notes receivable
------- -------- ----------- ---------- ----------
Balance, June 30, 1998 720 - 4,510 29,132 (3,698)
Components of comprehensive loss:
Foreign currency translation adjustment
Net loss (14,887)
Comprehensive loss
Dividends ($0.95 per share) (647)
Common stock issued for services 1 146
Conversion of minority interest 2,040
Employee stock purchases 900
Purchase of treasury stock - common (1,761)
Purchase of treasury stock - Class A (437)
Reduction of notes receivable
------- -------- ----------- ---------- ----------
Balance, June 30, 1999 $ 721 $ 2,940 $ 4,656 $ 13,598 $ (5,896)
======= ======== =========== ========== ==========
Notes Received/ Accumulated
Issuance of Comprehensive Stockholders
Stock Income (Loss) Equity
----------------- --------------- --------------
Balance, June 30, 1996 $ (250) $ 25 $ 37,550
--------------
Components of comprehensive loss:
Foreign currency translation adjustment (176) (176)
Net loss (5,843)
--------------
Comprehensive loss (6,019)
Dividends ($1.50 per share) (1,007)
Exercise of employee stock options for notes receivable (128) -
Issuance of common stock (8) 2
Purchase of treasury stock (2,054)
Reduction of notes receivable 126 126
----------------- --------------- --------------
Balance, June 30, 1997 (260) (151) 28,598
--------------
Components of comprehensive income:
Foreign currency translation adjustment (159) (159)
Net income 3,014
--------------
Comprehensive income 2,855
Dividends ($1.70 per share) (1,131)
Issuance of common stock 167
Exercise of employee stock options for notes receivable (128) -
Purchase of treasury stock (523)
Reduction of notes receivable 4 4
----------------- --------------- --------------
Balance, June 30, 1998 (384) (310) 29,970
--------------
Components of comprehensive loss:
Foreign currency translation adjustment 133 133
Net loss (14,887)
--------------
Comprehensive loss (14,754)
Dividends ($0.95 per share) (647)
Common stock issued for services 147
Conversion of minority interest (150) 1,890
Employee stock purchases (856) 44
Purchase of treasury stock - common (1,761)
Purchase of treasury stock - Class A (437)
Reduction of notes receivable 25 25
----------------- --------------- --------------
Balance, June 30, 1999 $ (1,365) $ (177) $ 14,477
================= =============== ==============
See notes to consolidated financial statements.
29
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED JUNE 30, 1999, 1998 AND 1997
(AMOUNTS IN THOUSANDS)
- -----------------------------------------------------------------------------------------------
1999 1998 1997
--------- --------- ----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $(14,887) $ 3,014 $ (5,843)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Minority interest 7 243 152
Depletion, depreciation and amortization 22,837 20,825 19,955
Write-off of deferred financing costs 4,363
Loss (gain) on sale of assets (91) 1,208 (8,304)
Deferred income taxes (7,574) 1,482 (2,534)
Exploration and impairment 16,778 8,262 10,121
Provision for losses on accounts receivable 2,295 2,572 2,102
Other, net (2,245) (3,539) (2,319)
--------- --------- ----------
17,120 34,067 17,693
Changes in assets and liabilities:
Accounts receivable (2,313) 2,631 1,407
Gas in storage 12,892 (608) (353)
Income taxes receivable 730 (2,918) 1,850
Prepaid and other assets (16,079) (1,725) (3,014)
Accounts payable and other current liabilities 1,163 7,846 (5,905)
Funds held for future distribution (338) (299) 823
Overrecovered gas costs (2,558) (3,165) (2,128)
Other (4,382) 897 (849)
--------- --------- ----------
Net cash provided by operating activities 6,235 36,726 9,524
--------- --------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment (36,659) (38,693) (26,376)
Proceeds from sale of oil and gas properties 3,444 568 1,114
Proceeds from sale of limited partnership interest - - 11,250
Notes receivable and other 70 (238) (1,556)
--------- --------- ----------
Net cash provided by (used in) investing activities (33,145) (38,363) (15,568)
--------- --------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt 27,500 1,298 271,000
Principal payments on long-term debt (3,084) (296) (255,854)
Short-term borrowings, net (2,375) 3,450 7,332
Purchase of treasury stock (2,198) (523) (2,054)
Dividends (967) (834) (1,007)
Other equity transactions 44 (124) 299
Deferred financing costs - (601) (7,055)
--------- --------- ----------
Net cash provided by (used in) financing activities 18,920 2,370 12,661
--------- --------- ----------
Net increase (decrease) in cash and cash equivalents (7,990) 733 6,617
Cash and cash equivalents, beginning of year 21,547 20,814 14,197
--------- --------- ----------
CASH AND CASH EQUIVALENTS, END OF YEAR $ 13,557 $ 21,547 $ 20,814
========= ========= ==========
See notes to consolidated financial statements.
30
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED JUNE 30, 1999, 1998 AND 1997
- ---------------------------------------------------------
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 ("WVPSC").
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 of West Virginia, Pennsylvania and Ohio.
The Company, through its wholly owned subsidiaries Westech Energy Corporation
("Westech") and Westech Energy New Zealand Limited ("WENZL"), 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 American and its subsidiaries; Eastern Systems
Corporation ("ESC") and its wholly owned subsidiary, Mountaineer and its
subsidiaries; 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 American and Mountaineer (see Note 14).
The Company 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 12).
Fourth Quarter Results - During the fourth quarter of fiscal 1999, the Company
- ------------------------
had the normal weather related decline in earnings and unproved property
impairments. However, due to significantly more drilling and other exploratory
related activities in New Zealand and the Rocky Mountains, the fourth quarter
loss is greater than usual.
31
Cash and Cash Equivalents - Cash and cash equivalents include short-term
- ----------------------------
investments maturing in three months or less from the date acquired.
Property, Plant and Equipment - Oil and gas properties are accounted for using
- -------------------------------
the successful efforts method of accounting. Under this method, certain
expenditures such as exploratory geological and geophysical costs, exploratory
dry hole costs, delay rentals and other costs related to exploration are
recognized currently as expenses. All direct and certain indirect costs
relating to property acquisition, successful exploratory wells, development
costs, and support equipment and facilities are capitalized. The Company
computes depletion, depreciation and amortization of capitalized oil and gas
property costs on the units-of-production method using proved developed
reserves. Direct production costs, production overhead and other costs are
charged against income as incurred. Gains and losses on the sale of oil and gas
property interests are generally recognized as income.
The provision for depreciation of Mountaineer's utility plant is based on a
composite straight-line method. The average composite depreciation rate was
3.98%, 3.73% and 3.77% for 1999, 1998 and 1997, respectively. Mountaineer's
property, plant and equipment includes capitalized overhead for payroll related
costs and administrative and general expenses and an allowance for funds used
during construction 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. During fiscal 1999, $8.6 million of
retired other property and equipment was charged against its related accumulated
depreciation.
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, pipe