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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, pipelines and buildings are
recognized as income.
At June 30 property, plant and equipment consisted of the following (in
thousands):
1999 1998
---------- ----------
Oil and gas properties $ 216,650 $ 210,650
Utility plant 182,590 170,721
Other property and equipment 13,948 23,743
Pipelines 19,021 18,783
---------- ----------
432,209 423,897
Less accumulated depletion, depreciation and amortization (116,893) (105,350)
---------- ----------
Net property, plant and equipment $ 315,316 $ 318,547
========== ==========
Long-Lived Assets - Statement of Financial Accounting Standards ("SFAS") No.
- ------------------
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of", requires all companies to assess long-lived assets
and assets to be disposed of for impairment and requires rate-regulated
companies to write-off regulatory assets whenever those assets no longer meet
the recognition criteria as defined by SFAS No. 71, "Accounting for the Effects
of Certain Types of Regulation". For the three years ended June 30, 1999, the
Company determined that no impairment needed to be recognized for applicable
assets.
Gas in Storage - Gas in storage is stated at the lower of average cost or market
- --------------
value.
32
Deferred Financing Costs - Certain legal, underwriting fees and other direct
- --------------------------
expenses associated with the issuance of credit agreements, lines of credit and
other financing transactions have been capitalized. These financing costs are
being amortized over the term of the related credit agreement.
Foreign Currency Translation - The translation of applicable foreign currencies
- -----------------------------
into U.S. dollars is performed for balance sheet accounts using current exchange
rates in effect at the balance sheet date and for revenue and expense accounts
using an average exchange rate during the period. The cumulative translation
adjustment is included in stockholders' equity.
Income Taxes - Deferred income taxes reflect the impact of "temporary
- -------------
differences" between assets and liabilities recognized for financial reporting
purposes and such amounts as measured by tax laws. These temporary differences
are determined in accordance with SFAS No. 109, "Accounting For Income Taxes".
Gas Delivery Obligation - Gas delivery obligation represents deferred revenues
- -------------------------
on gas sales where the Company has received an advance payment. The Company
recognizes the actual gas sales revenue in the period the gas delivery takes
place.
Revenues and Purchased Gas Costs - Utility gas sales and transportation revenues
- --------------------------------
included in income are based on amounts billed to customers on a cycle basis and
estimated amounts for gas delivered but unbilled at the end of each accounting
period.
Gas costs are expensed as incurred. For the years ended June 30, 1999, 1998 and
1997, purchased gas costs included $2.8 million, $4 million and $4 million,
respectively, in amortization of overrecovered gas costs recorded prior to
November 1, 1995. (See Note 18).
Oil and gas sales are recognized as income when the oil or gas is produced and
sold.
Stock Compensation - As permitted under SFAS No. 123, "Accounting for
- -------------------
Stock-Based Compensation", the Company has elected to continue to measure
compensation costs for stock-based employee compensation plans using the
intrinsic value method as prescribed by Accounting Principles Board Opinion No.
25, "Accounting for Stock Issued to Employees".
Hedging Activities - The Company periodically hedges a portion of its oil and
- -------------------
gas production through futures and swap agreements. The purpose of the hedges
is to provide a measure of stability in the volatile environment of oil and gas
prices. The Company recognizes gains and losses in the futures and swap
agreements at the time the hedged volumes are sold as part of oil and gas
revenues.
Use of Estimates - The preparation of financial statements in conformity with
- ------------------
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
The Company's financial statements are based on a number of significant
estimates including oil and gas reserve quantities, which are the basis for the
calculation of depletion, depreciation, amortization and impairment of oil and
gas properties. Management emphasizes that reserve estimates are inherently
imprecise. In addition, utilization of tax credit carryforwards is based
largely on estimates of future taxable income.
Regulatory Accounting - Mountaineer is subject to the provisions of SFAS No. 71,
- ---------------------
"Accounting for the Effects of Certain Types of Regulation." Accordingly,
Mountaineer has recorded certain assets and liabilities that result from the
effects of the ratemaking process that would not be recorded under generally
accepted accounting principles for non-regulated entities. Such amounts are
primarily related to future amounts recoverable for income taxes (see Note 6).
Discontinuance of cost-based regulation or increased competition might require
regulated entities to reduce their asset balances to reflect a market basis less
than cost and to write off their associated regulatory assets and liabilities.
33
The Company has evaluated the continued applicability of SFAS No. 71,
considering such factors as regulatory changes and the impact of competition.
The Company cannot predict the likelihood of discontinuance of cost-based
regulation in the future or the impact of increased competition on the Company's
future financial position and results of operations.
Prior Year Reclassifications - Certain amounts in the financial statements of
- ------------------------------
prior years have been reclassified to conform to the current year presentation.
Concentration of Credit Risk - The Company maintains its cash accounts primarily
- ----------------------------
with a single bank and invests cash in money market accounts, which the Company
believes to have minimal risk. As operator of jointly owned oil and gas
properties, the Company sells oil and gas production to numerous U.S. oil and
gas purchasers, and pays vendors on behalf of joint owners for oil and gas
services. Both purchasers and joint owners are located primarily in the
northeastern United States. The risk of nonpayment by the purchasers or joint
owners is considered minimal. The Company as owner of a utility has receivables
from both residential and commercial customers who are located in West Virginia,
where no one customer constitutes a significant credit risk. The risk of
nonpayment by purchasers, joint owners or utility customers has been considered
in the Company's allowance for doubtful accounts.
Environmental Concerns - The Company is continually taking actions it believes
- -----------------------
necessary in its operations to ensure conformity with applicable federal, state
and local environmental regulations. As of June 30, 1999, the Company has not
been fined or cited for any environmental violations, which would have a
material adverse effect upon capital expenditures, earnings or the competitive
position of the Company.
Recent Accounting Pronouncements - The Company adopted SFAS No. 130, "Reporting
- ---------------------------------
Comprehensive Income", effective July 1, 1998. The standard establishes rules
for the reporting of comprehensive income and its components. The Company's
comprehensive income (loss) consists of foreign currency translation adjustments
and is presented in the Consolidated Statement of Stockholders' Equity. The
adoption of SFAS No. 130 had no impact on the Company's total Stockholders'
equity. Prior year financial statements have been reclassified to conform.
In June 1998, SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities" was issued, which is effective for all fiscal quarters of all fiscal
years beginning after June 15, 2000. SFAS No. 133 establishes accounting and
reporting standards for derivative instruments, including certain derivative
instruments embedded in other contracts, and hedging activities. It requires
the recognition of all derivative instruments as assets or liabilities in the
Company's balance sheet and measurement of those instruments at fair value. The
accounting treatment of changes in fair value is dependent upon whether or not a
derivative instrument is designated as a hedge and if so, the type of hedge.
The Company has not fully analyzed the impact of the provisions of SFAS No. 133
will have on the Company's financial statements.
34
Supplemental Disclosures of Cash Flow Information - Supplemental cash flow
- ------------------------------------------------------
information for the years ended June 30 is as follows (in thousands):
1999 1998 1997
------- ------- --------
Cash paid (received) for:
Interest (net of capitalized interest of $0, $37,
and $323 in 1999, 1998 and 1997, respectively) $25,670 $25,025 $19,921
Income taxes, net 1,451 3,004 (1,142)
Noncash investing and financing activities:
Dividends declared and unpaid at year end 316
Seller financed acquisition 150 943
Acquisition of property for cancellation of notes 1,900
3. DISPOSITIONS
Westside Operating Partnerships LP - In March 1997, the Company exchanged
- -------------------------------------
warrants held representing a 30% ownership interest of a third party for a 30%
interest in a newly formed oil and gas limited liability company, Breitburn
Energy Company, LLC ("BEC"), the successor to WOPLP. BEC redeemed the Company's
previous interest and purchased certain oil and gas properties, paying the
Company $11.3 million plus a $1.5 million variable rate note with certain
conversion options and distributing certain WOPLP oil and gas properties and
real estate to the Company. The Company recognized a gain of $7.8 million in
fiscal 1997 on the transaction. During fiscal 1999, BEC sold additional shares
of stock, which reduced the Company's interest to approximately 25.35%. For
accounting purposes, the Company's equity interest carrying value in BEC has
been eliminated due to the recognition of its proportionate share of operating
losses.
4. RISK MANAGEMENT
Options, Future Contracts, and Swap Agreements -The Company is a party to
- ---------------------------------------------------
natural gas options, future contracts and swap agreements in the normal course
of business. These instruments involve, to varying degrees, elements of market
and credit risk in excess of the amount recognized in the consolidated balance
sheets.
At June 30, 1999, the Company had over-the-counter natural gas futures and
options contracts related to gas sale commitments covering 3,553,000 Mmbtu of
gas maturing through June 2000. As these contracts have been designated as
hedges, any gains or losses resulting from market price changes will be included
in oil and gas sales for the month to which the contract is applicable. The
Company's net unrealized loss related to these contracts was approximately
$88,000 at June 30, 1999.
In addition to futures and options contracts, the Company enters into
over-the-counter price swap agreements to manage its exposure to commodity price
risk under existing sales commitments. At June 30, 1999, the Company had swap
agreements maturing from November 1999 through June 2000 covering 772,000 Mmbtu
under which the Company receives a fixed price in exchange for a variable price.
The Company's net unrealized gain related to these agreements was approximately
$28,000 at June 30, 1999.
35
Also at June 30, 1999, the Company had natural gas fixed price purchase option
contracts for the purchase and physical delivery of 615,000 Mmbtu of gas
expiring through October 1999. The cost of these options, which totaled
approximately $190,000 for the year ended June 30, 1999, is included in Cost of
Gas Sales for the month to which the options were applicable. At June 30, 1999,
the remaining options, for the months of July 1999 through October 1999, are
carried at cost that totaled $189,875 and approximates fair value.
As of June 30, 1998, the Company had natural gas swap agreements maturing
through October 1998 covering 320,000 Mmbtu. At June 30, 1998, the market value
of these swaps, the net amount the Company would receive to terminate these swap
agreements was nominal.
For the years ended June 30, 1999 and 1998, the Company recognized a net loss on
its natural gas hedging activities of $32,240 and $47,000, respectively.
Fixed Price Gas Purchase Contracts - Mountaineer has entered into fixed price
- -------------------------------------
contracts to purchase gas in the future. Effective November 1, 1998,
Mountaineer entered into a contract with a third party to purchase up to 24
million dth of natural gas annually for a fixed price. The third party assumed
management and financial obligation of Mountaineer's firm transportation and
storage agreements. In addition, Mountaineer transferred ownership of all
storage volumes owned on November 1, 1998 to the third party in exchange for the
third party to provide delivery of such volumes during the fiscal 1999 heating
season, which has been recorded as a current asset. The contract expires
October 31, 2001.
5. DEBT
Long-Term Debt - At June 30 long-term debt consisted of the following (in
- ---------------
thousands):
1999 1998
--------- ---------
ECA senior subordinated notes, interest at 9.5% payable
semi-annually, due May 15, 2007 $200,000 $200,000
Mountaineer unsecured senior notes, interest at 7.59% payable
semi-annually, due October 1, 2010 60,000 60,000
ECA revolving credit, interest floating at Prime, plus 1.5% or
LIBOR plus 3%, due 2002 25,000
Installment notes payable, collateralized by deeds of trust,
at interest rates ranging from 6.2% to 8%, respectively 1,655 2,088
--------- ---------
286,655 262,088
Less current portion (6,634) (581)
--------- ---------
$280,021 $261,507
========= =========
The Company's various debt agreements contain certain restrictions and
conditions among which are limitations on indebtedness, funding of certain
subsidiaries, dividends and investments, and certain tangible net worth and debt
and interest coverage ratio requirements. The agreements require the Company to
maintain certain financial conditions, including a minimum net worth,
restriction on funded debt and restrictions on the amount of dividends that can
be declared. Additionally, under its debt covenants, Mountaineer is restricted
in the payment of dividends to the Company. As of June 30, 1999, Mountaineer
had approximately $7.3 million available for declaration of dividends.
36
Scheduled maturities of the Company's long-term debt at June 30, 1999 for each
of the next five years and thereafter are as follows (in thousands):
2000 $ 6,634
2001 3,659
2002 22,461
2003 3,461
2004 3,461
Thereafter 246,979
--------
$286,655
========
Revolving Credit - The Company had a $50 million revolving credit facility
- -----------------
secured by certain properties, interest and contracts. The interest rate is
variable based on Eurodollars or other defined basis. The annual commitment fee
ranges between 0.3% and 0.625% depending on usage. As of June 30, 1999, $25
million was outstanding under this facility. The Company was in violation of
certain financial covenants including tangible net worth, current ratio and
interest coverage at June 30, 1999. The lenders have waived the violations and
amended the agreement. The amendment reduces the borrowing arrangement to $22
million, requires a principal reduction of $6 million during fiscal 2000 and an
amendment fee of $335,000. Interest rates were increased as reflected above
while the minimum financial covenant requirements were reduced through June 30,
2000.
Extinguishment of Debt - In May 1997, the Company issued $200 million senior
- ------------------------
subordinated notes using the proceeds therefrom to repay debt outstanding at ESC
and Eastern American of $35 million and $136 million, respectively. As a
result, the Company recorded an extraordinary loss of $7.86 million, net of a
tax benefit of $4.23 million.
Short-Term Debt - Mountaineer had unsecured bank lines of credit totaling $67
- ----------------
million and $74 million as of June 30, 1999 and 1998, respectively. During the
years ended June 30, 1999 and 1998, the maximum outstanding balance was $53.2
million and $44.9 million, respectively, and the average daily balance was $32.5
million and $26.2 million, respectively. The weighted average interest rate was
5.5% and 6.02% on the balance outstanding during the years ended June 30, 1999
and 1998, respectively.
Other Credit Facilities - Eastern American had a $3 million and $6 million
- -------------------------
letter of credit, as of June 30, 1999 and 1998, respectively, issued by a bank
in support of Eastern American's obligations under a gas purchase contract with
the royalty trust (see Note 15). The letter of credit reduces by $3 million on
June 30 of each year until its expiration on June 30, 2000. As of June 30, 1999
and 1998, no amounts had been drawn under the letter of credit. Eastern
American also has an unsecured revolving line of credit totaling $2 million,
which expires December 31, 1999 and charges an interest rate of prime plus 0.5%.
As of June 30, 1999 and 1998, no amounts were outstanding under the line of
credit.
Seller Financed Note - The Company purchased a natural gas gathering system in
- ----------------------
West Virginia for $1.2 million. The Company paid $0.3 million in cash and
issued a note for the balance payable to the seller in 100 consecutive equal
monthly payments. As of June 30, 1999 and 1998, the balance of the note was
$0.8 million and $0.9 million.
37
6. INCOME TAXES
The following table summarizes components of the Company's provision (benefit)
for income taxes for the years ended June 30 (in thousands):
1999 1998 1997
-------- ------- --------
Current:
Federal $ 2,273 $ 586 $ 491
State 69 (51) (224)
-------- ------- --------
Total current 2,342 535 267
-------- ------- --------
Deferred:
Federal (8,176) (155) (4,141)
State 602 1,637 1,607
-------- ------- --------
Total deferred (7,574) 1,482 (2,534)
-------- ------- --------
Total provision (benefit) for income taxes $(5,232) $2,017 $(2,267)
======== ======= ========
A reconciliation of the provision for income taxes computed at the statutory
rate to the provision for income taxes as shown in the consolidated statements
of operations for the years ended June 30 is summarized below (in thousands):
1999 1998 1997
-------- -------- --------
Tax expense (benefit) at the federal statutory rate $(6,838) $ 1,793 $(2,707)
State taxes, net of federal tax effects (919) 358 (541)
Foreign losses 838 635
Section 29 tax credits 921 (1,783) (1,866)
Change in valuation allowance on federal, foreign
and state deferred tax assets, net of federal effect (592) 571 1,805
Investment tax credit expiration 530
IRS adjustment 519
Other, net 1,147 240 407
-------- -------- --------
Provision (benefit) for income taxes $(5,232) $ 2,017 $(2,267)
======== ======== ========
During fiscal 1999, the Company finalized an IRS examination resulting in
payments for prior taxes of $0.5 million. In addition, Section 29 credits for
1998 were not utilized because of reductions to regular taxable income and have
been added to the current year's tax provision.
38
Components of the Company's federal and state deferred tax assets and
liabilities, as of June 30, are as follows (in thousands):
1999 1998
------------------------------- -------------------------------
Federal State Total Federal State Total
--------- --------- --------- --------- --------- ---------
Deferred tax assets:
Overrecovered gas costs $ 1,339 $ 354 $ 1,693 $ 2,209 $ 583 $ 2,792
Bad debt allowance 566 150 716 641 169 810
Deferred compensation and profit sharing 162 43 205 1,155 304 1,459
Postretirement and pension obligations 913 242 1,155 696 183 879
Tax credits and carryforwards 13,058 8,774 21,832 14,892 10,553 25,445
Other long-term obligations 1,272 337 1,609 860 228 1,088
Other 11,899 3,150 15,049 9,408 1,345 10,753
--------- --------- --------- --------- --------- ---------
Total deferred tax assets 29,209 13,050 42,259 29,861 13,365 43,226
--------- --------- --------- --------- --------- ---------
Deferred tax liabilities:
Property, plant and equipment (39,529) (10,543) (50,072) (48,897) (13,263) (62,160)
Federal income tax on state tax credits (2,983) (2,983) (3,588) (3,588)
Other liabilities (5,920) (2,530) (8,450) (1,976) (525) (2,501)
--------- --------- --------- --------- --------- ---------
Total deferred tax liabilities (48,432) (13,073) (61,505) (54,461) (13,788) (68,249)
--------- --------- --------- --------- --------- ---------
Valuation allowance (4,920) (4,920) (1,252) (3,920) (5,172)
--------- --------- --------- --------- ---------
Net deferred income tax liability (19,223) (4,943) (24,166) (25,852) (4,343) (30,195)
---------
Current deferred tax asset (liability) 2,926 776 3,702 (4,698) (945) (5,643)
--------- --------- --------- --------- --------- ---------
Long-term deferred tax liability $(22,149) $ (5,719) $(27,868) $(21,154) $ (3,398) $(24,552)
========= ========= ========= ========= ========= =========
At June 30, 1999, the Company has the following federal and state tax credits
and carryforwards (in thousands):
Year of
Amount Expiration
------- ----------
AMT and Section 29 tax credits $12,445 None
Investment tax credits 613 2000-2001
-------
Total federal credits $13,058
=======
West Virginia tax credits $ 8,774 2002
=======
The Company is eligible for relocation incentives taken in the form of tax
credits from West Virginia. The incentive amounts are based upon investments
made and jobs created in that state. Tax credits generated by the Company are
used primarily to offset the payment of severance, property and state income
taxes. Based on existing future taxable temporary differences and projections
of future West Virginia severance, property and state income taxes, management
has provided a valuation allowance for that portion of the credits not expected
to be utilized.
Included in other long-term assets as of June 30, 1999 and 1998 is a net
regulatory asset recorded by Mountaineer in accordance with state utility
ratemaking practices related to future amounts recoverable for income taxes of
$10.9 million and $11.3 million, respectively.
39
7. EMPLOYEE BENEFIT PLANS
The Company and certain subsidiaries, have a Profit Sharing/Incentive Stock Plan
(the "Plan") for the stated purpose of expanding and improving profits and
prosperity and to assist the Company in attracting and retaining key personnel.
The Plan is noncontributory, and its continuance from year to year is at the
discretion of the Board of Directors. The annual profit sharing pool is based
on calculations set forth in the Plan. One-half of the pool is generally paid
to eligible employees within 120 days of the end of the fiscal year and one-half
is deferred to the following year. Generally, to be eligible to participate, an
employee must have been continuously employed for two or more years; however,
employees with less than two years of employment may participate under certain
circumstances. The Company recognized $0.5 million, $2.6 million and $1.1
million of profit sharing expense during the years ended June 30, 1999, 1998,
and 1997, respectively.
For certain subsidiaries, the Company sponsors a Section 401(k) plan covering
all full-time employees who wish to participate. The Company's contributions,
which are principally based on a percentage of the employee contributions, and
charged against income as incurred, totaled $182,600, $153,600 and $140,300 for
the years ended June 30, 1999, 1998 and 1997, respectively.
8. PENSION PLAN
Mountaineer sponsors a Retirement Income Plan (the "Pension Plan"), which covers
substantially all qualified Mountaineer employees 21 years of age and over.
Employees become fully vested upon completion of five years of credited service,
as defined. Retirement income is based on credited years of service and the
employees' level of compensation, as defined. The Pension Plan is subject to
the provisions of the Employee Retirement Income Security Act of 1974 ("ERISA").
The determination of contributions is made in consultation with the Pension
Plan's actuary and is based upon anticipated earnings of the Pension Plan,
mortality and turnover experience, the funded status of the Pension Plan and
anticipated future compensation levels. Mountaineer's funding policy is to be
in compliance with ERISA guidelines and to make annual contributions to the
Pension Plan to assure that all employees' benefits will be fully provided for
by the time they retire.
40
The following table sets forth the Pension Plan's funded status and amounts
recognized in the consolidated balance sheets as of June 30, as determined by an
independent actuary (in thousands):
1999 1998
--------- ---------
Reconciliation of Funded Status
Funded status $ (6,640) $ (6,058)
Unrecognized actuarial loss 1,935 1,488
Unrecognized prior service cost 729 -
--------- ---------
Net pension accrued liability (3,976) (4,570)
Adjustment required to recognize minimum liability - -
--------- ---------
Net pension liability recognized $ (3,976) $ (4,570)
========= =========
Change in Projected Benefit Obligation
Benefit obligation at beginning of year $(33,110) $(29,777)
Service cost (750) (717)
Interest cost (2,496) (2,219)
Plan amendments (781) -
Actuarial loss (145) (3,318)
Benefit payments 2,918 2,921
--------- ---------
Benefit obligation at end of year $(34,364) $(33,110)
========= =========
Change in Plan Assets
Fair value of plan assets at beginning of year $ 27,052 $ 24,954
Actuarial return on plan assets 1,628 3,612
Employer contribution 1,962 1,407
Benefit payments (2,918) (2,921)
--------- ---------
Fair value of plan assets at end of year $ 27,724 $ 27,052
========= =========
Net periodic pension cost for the years ended June 30 as determined by an
independent actuary, included the following components (in thousands):
1999 1998
-------- --------
Service cost $ 750 $ 717
Interest cost 2,496 2,219
Expected return on plan assets (1,945) (3,612)
Prior service cost recognized 52
Recognized gains or losses 14 1,753
-------- --------
Net periodic pension cost $ 1,367 $ 1,077
======== ========
41
The assumptions used at the beginning of the fiscal year in accounting for
Mountaineer's Pension Plan at June 30 are as follows:
1999 1998
----- -----
Discount rate 7.75% 7.75%
Expected average increase in compensation 4.50% 4.50%
Expected long-term rate of return 8.00% 8.00%
9. POST-RETIREMENT MEDICAL AND LIFE INSURANCE BENEFITS
Mountaineer provides certain medical and life insurance benefits for retired
employees. Substantially all employees, who meet the service requirements of 10
continuous years of service prior to retirement at age 55 or 5 continuous years
of service prior to retirement at age 60, may become eligible for medical
benefits. Medical benefits are provided to retirees until age 65. Life
insurance benefits of approximately two times annual salary are provided while
an employee is active and working at Mountaineer. On the date of an employee's
retirement and on the date the employee reaches age 70, life insurance benefits
decrease to approximately 80% and 50% of annual salary, respectively. The plan
is unfunded.
The following table sets forth the postretirement medical and life insurance
plans' funded status and amounts recognized in the consolidated balance sheets,
as determined by an independent actuary, as of June 30 (in thousands):
1999 1998
-------- --------
Reconciliation of funded status
Funded status $(7,628) $(7,268)
Unrecognized actuarial gain (197) (18)
-------- --------
Net postretirement benefit liability $(7,825) $(7,286)
======== ========
Change in projected benefit obligation
Benefit obligation at beginning of year $(7,268) $(6,993)
Service cost (461) (437)
Interest cost (537) (515)
Participant contributions (140) (128)
Actuarial (gain) loss 182 (130)
Benefit payments 596 935
-------- --------
Benefit obligation at end of year $(7,628) $(7,268)
======== ========
Components of net periodic postretirement benefit cost
Service cost $ 461 $ 437
Interest cost 537 515
-------- --------
Net periodic benefit cost $ 998 $ 952
======== ========
42
The weighted average discount rate used in determining the accumulated
postretirement benefit obligation was 7.75% for the years ended June 30, 1999
and 1998. The average assumed annual rate of salary increase for the life
insurance benefit plan was 4.5 % and 4.5% in 1999 and 1998, respectively.
The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation was 8.0% in 1999, declining by a half percent
to 5.5% in 2004 and remaining at that level thereafter. The health care cost
trend rate assumption has a significant effect on the amounts reported. A one
percentage point increase in the assumed health care cost trend rate would
increase the aggregate service and interest cost by $63,000 for the year ended
June 30, 1999 and increase accumulated postretirement benefit obligation as of
June 30, 1999 by $315,000. A one percentage point decrease in the assumed
health care cost trend rate would decrease the aggregate service and interest
cost by $57,000 for the year ended June 30, 1999 and decrease accumulated
postretirement benefit obligation as of June 30, 1999 by $290,000.
As part of a WVPSC rate order dated October 29, 1993, the WVPSC ruled that the
permitted rate recovery mechanism for other post retirement benefits would be a
modified accrual method. The modified accrual method allows for the recovery of
current service costs on an accrual basis and recovery of the transition
obligation on a cash basis.
10. CAPITAL STOCK
Voting Common Stock- In May 1995, the Company was reincorporated in the State of
- -------------------
West Virginia. As part of this reincorporation, each outstanding share of then
existing no-par value common stock was converted to one share of $1 par value
common stock.
The Company has an agreement with a stockholder covering the sale or disposition
of 61,000 shares of common stock, at June 30, 1999, that provides the
stockholder cannot sell stock without first offering such shares to the Company.
Under certain circumstances, the Company would be required to purchase the
related stock if not previously tendered to the Company or otherwise sold or
disposed of in accordance with the provisions of the agreement.
Class A Non-Voting Common Stock - In August 1998, the Company amended its
- -----------------------------------
articles of incorporation authorizing the issuance of up to 100,000 shares of
Class A non-voting common stock. The Company then offered and exchanged 13,517
shares of its new Class A stock for the outstanding Class A stock of its
subsidiaries, owned by certain employees, officers and directors. The minority
interest carrying value prior to exchange, which reflected the subsidiaries'
Class A shares, was the basis used to record the issuance of the Company's new
Class A stock.
Treasury Stock - At June 30, 1999, the Company had 75,352 shares of voting
- ---------------
common stock in treasury, carried at cost. The Company purchased 20,704 and
6,980 shares of voting common stock during the years ended June 30, 1999 and
1998, respectively. At June 30, 1999, the Company also had 4,516 shares of
non-voting Class A stock in treasury, carried at cost, all of which were
purchased during the current year.
43
Stock Plans - During fiscal 1999, the Company created an incentive stock
- ------------
purchase agreement, primarily for outside Directors. Under the agreement,
options to purchase voting common stock were granted at $75, based on the fair
market value as determined by the Board of Directors, per share and are
exercisable based on the following schedule:
Number of
Exercise Period Shares
- ------------------------------------- ---------
January 1, 1999 to December 31, 2003 10,002
January 1, 2000 to December 31, 2004 10,002
January 1, 2001 to December 31, 2005 9,996
---------
30,000
=========
A summary of the plan as of June 30, 1999 and the changes during the year is
presented below:
Exercise
Shares Price
-------- ------
Outstanding at beginning of year - $ -
Granted 30,000 75
Exercised
Outstanding at end of year 30,000 $ 75
======== ======
Options exercisable at year end 10,002
========
Fair value of the options at the date of grant, as estimated by management, was
nominal.
During fiscal 1999, the Company created an employee stock purchase plan. Under
the plan, 12,003 Class A shares were issued to employees at $75 per share in
exchange for cash and promissory notes bearing interest of 6.5% or 8%, depending
on the initial cash payment and recourse nature of the notes. The Company has
agreed to forgive the notes over a seven year period assuming continued
employment; therefore, the notes are being amortized over the term of
employment. The Company has a right-of-first refusal to repurchase any shares
employees wish to sell and in the event of death, disability or termination, the
Company has an option to repurchase the shares.
44
11. EARNINGS PER SHARE
A reconciliation of the components of basic and diluted net income (loss) per
common share as of June 30, for the years indicated, is as follows:
Per-Share
Income Shares Amount
------------- ------- --------
1999
- ----
Basic and Diluted Earnings per Share
Loss available to common shareholders $(14,887,000) 672,973 $(22.12)
1998
- ----
Basic and Diluted Earnings per Share
Income available to common shareholders $ 3,014,000 665,074 $ 4.53
1997
- ----
Basic and Diluted Earnings per Share
Loss available to common shareholders $ (5,843,000) 688,247 $ (8.49)
The effect of stock options was not included in the computation of diluted net
loss per share during fiscal years 1997 and 1999 because to do so would have
been antidilutive. There were no stock options exercisable during fiscal 1998.
12. UNCONSOLIDATED AFFILIATE
The Company's investment in BEC is accounted for under the equity method (see
Note 3). Summarized financial information for BEC as of and for the years ended
June 30, is as follows (in thousands):
1999 1998
-------- --------
Current assets $ 5,914 $ 1,506
Oil and gas properties 50,528 31,580
Other assets 1,359 2,508
-------- --------
Total assets $57,801 $35,594
======== ========
Current liabilities $ 5,340 $ 2,894
Long-term debt 26,200 4,300
Other liabilities 170 152
Equity 26,091 28,248
-------- --------
Total liabilities and equity $57,801 $35,594
======== ========
Net sales $11,655 $ 8,969
======== ========
Gross profit $(1,218) $ 2,379
======== ========
Net loss $(2,557) $(1,772)
======== ========
BEC began operations in March 1997. Results of operations were not material for
the three months ended June 30, 1997.
45
13. OPERATING LEASES
The Company has noncancelable operating lease agreements for the rental of
office space, computer and other equipment. Certain of these leases contain
purchase options or renewal clauses. Rental expense for operating leases was
approximately $1.8, $1.7 and $1.3 million for the years ended June 30, 1999,
1998 and 1997, respectively.
At June 30, 1999 future minimum lease payments for each of the next five years
and thereafter are as follows (in thousands):
2000 $1,670
2001 1,135
2002 724
2003 486
2004 250
Thereafter 413
------
$4,678
======
14. RELATED PARTY TRANSACTIONS
The Company has entered into a rental arrangement for office space from a
partnership in which certain officers are partners. Rent payments totaled
$374,200, $339,470 and $336,000 for the years ended June 30, 1999, 1998 and
1997, respectively.
Mountaineer purchases a portion of its gas supply requirements from a subsidiary
and from Eastern American. The price paid for such purchases has been approved
by the WVPSC. During 1999, 1998 and 1997 Mountaineer purchased approximately
$5.4 million, $5.6 million and $5.3 million respectively, from its subsidiary
and $7.8 million, $22.2 million and $23.2 million respectively, from Eastern
American. The contract with Eastern American expired October 31, 1998. The
related revenues and expenses between Mountaineer and its subsidiary and Eastern
American have not been eliminated in these financial statements due to the
regulated nature of Mountaineer.
The Company advanced funds to certain officers, generally at 8% interest.
Balances totaled $0.5 million and $0.2 million, respectively, at June 30, 1999
and 1998.
The Company advanced funds to certain officers in 1991 and 1994, at 8% interest
that were secured by non-voting common shares of Eastern American. Balances
totaled $0 and $320,400, respectively, at June 30, 1999 and 1998.
The Company advanced funds in 1988 to certain officers and directors at 8%
interest, secured by interests in oil and gas properties and were payable out of
net proceeds from the oil and gas production on these properties. During fiscal
1999, Eastern American purchased the related working interest from the officers
and directors, canceling the related notes.
During fiscal 1999, the Company purchased from certain officers and directors,
for $2.4 million, volumetric production from wells in New Zealand. Future
production, totaling 3.3 million Mcf, otherwise allocable to the officers and
directors will be allocated to the Company. The Company has recorded the
payment as an investment in oil and gas properties.
46
15. COMMITMENTS AND CONTINGENCIES
In 1993, the Company sold working interests in certain Appalachian gas
properties in connection with the formation of a royalty trust. A portion of
the proceeds from the sale of these interests, representing a term net profits
interest, was accounted for as a production payment. Unamortized proceeds
totaling $12.0 million and $13.5 million at June 30, 1999 and 1998,
respectively, have been classified as deferred trust revenue.
Certain gas production attributable to the royalty trust is purchased by a
wholly owned subsidiary of the Company pursuant to a gas purchase contract,
which expires in 2013. The purchase price under the contract is based on
escalating fixed price and spot market components. The fixed price component
expires on January 1, 2000. The obligation of the subsidiary to make payments
under the contract is partially supported by a standby letter of credit with a
face amount of $3 million. The letter of credit is subject to annual reductions
of $3 million beginning June 30, 1996, and fully expires on June 30, 2000.
The Company entered into an agreement whereby it funded a specified monthly
amount, through December 31, 1996, to assist in the development of oil and gas
projects by a third party. No remaining commitment existed as of June 30, 1998.
Amounts funded were accounted for as an advance and all outstanding amounts were
due on January 1, 1999. As settlement, during fiscal 1999, the third party
transferred $1.0 million of property and the Company has written off the
remaining balance of $0.3 million.
In connection with an existing gas delivery obligation agreement, whereby
Eastern American received an advance payment, a subsidiary of Eastern American
entered into a credit line deed of trust, which has an available balance of $6.5
million as of June 30, 1999 to collateralize its performance under the gas
delivery obligation. This credit line deed of trust declines at a rate of 7.5%
per year.
The Company is involved in various legal actions and claims arising in the
ordinary course of business. Management does not expect these matters to have a
material adverse effect on the Company's financial position.
16. FINANCIAL INSTRUMENTS
The estimated fair values of the Company's financial instruments, as of June 30,
have been determined using appropriate market information and valuation
methodologies. Considerable judgment is required to develop the estimates of
fair value; thus, the estimates provided below are not necessarily indicative of
the amount that the Company could realize upon the sale or refinancing of such
financial instruments (in thousands):
1999 1998
------------------- -------------------
Carrying Fair Carrying Fair
Value Value Value Value
--------- -------- --------- --------
Notes receivable $ 4,909 $ 4,855 $ 6,002 $ 5,964
Long-term debt $ 286,655 $269,188 $ 262,088 $266,856
Futures, swaps and options $ 490 $ 430 - -
The Company in estimating the fair value of its financial instruments used the
following methods and assumptions:
47
Notes Receivable - The notes receivable accrue interest at a fixed rate. Fair
- -----------------
value was estimated using discounted cash flows based on current interest rates
for notes with similar credit characteristics and maturities.
Long-Term Debt - A portion of long-term debt was borrowed under a senior
- ---------------
revolving credit facility, which accrues interest at variable rates; as a
result, carrying value approximates fair value. The Company's subordinated debt
is traded publicly. The market value at the end of the year was used for
valuation purposes. The remaining portion of the Company's long-term debt is
comprised of fixed rate facilities; for this portion, fair value was estimated
using discounted cash flows based upon the Company's estimated current borrowing
rates for debt with similar maturities.
Futures, swaps and options - The fair value of these instruments are based on
- -----------------------------
quoted market prices.
17. CONTRACT SETTLEMENT
In March 1998, the Company entered into a Termination Agreement (the
"Agreement") with Seneca Power Partners, L.P. ("Seneca"), which provided for the
termination of a long-term gas sale and purchase contract between the Company
and Seneca. Prior to such termination, the Company was obligated to deliver up
to 12,000 Mcf of natural gas per day to Seneca's cogeneration facility. The
Agreement was a direct result of an amendment to the existing Power Purchase
Agreement by and between Seneca and Niagara Mohawk Power Corporation
("Niagara"). Niagara negotiated amendments to all of its existing Power
Purchase Agreements as part of a Master Restructuring Agreement. Pursuant to
the Agreement, the Company received cash consideration of approximately $22
million on June 30, 1998. As a result of this termination, the Company
estimated it would incur future losses of approximately $2 million on its gas
purchase commitments. Accordingly, the provision for anticipated losses was
recorded as an offset to the contract settlement income in fiscal 1998 and
amortized against the cost of gas purchased during fiscal 1999.
Although the Company terminated all rights and obligations under the contract,
the Company retained its 10% limited partnership interest in Seneca. For the
fiscal year ended June 30, 1998, the Company recorded partnership distributions
of $10.0 million, comprised of $7.2 million in cash and $2.8 million of Niagara
common stock. The Niagara stock was sold in November 1998 for $2.9 million.
18. RATE MATTERS
Since November 1995, Mountaineer has operated under a regulatory structure
whereby Mountaineer maintains its rates at an agreed upon level for a specific
period of time (the "Rate Moratorium"). In addition, during the Rate
Moratorium, Mountaineer's annual purchased gas adjustment filing with the WVPSC
is suspended. This regulatory structure results in Mountaineer assuming the
risks and rewards of changes in the cost of gas purchases, changes in interstate
pipeline costs and of all other aspects of Mountaineer's business. The Rate
Moratorium began in November 1995 and ended in October 1998. During this
period, deferral accounting for the majority of gas purchase costs was suspended
and Mountaineer was permitted to amortize $12 million of the $12.7 million
recorded balance of overrecovered gas costs as an offset to purchased gas
expense. In fiscal 1999, Mountaineer recorded total amortization of $1.3
million in accordance with the Rate Moratorium. The excess of the overrecovered
gas costs over the amount to be amortized and certain transportation revenues,
storage balancing fees and standby charges were subject to deferral accounting
in accordance with the Rate Moratorium.
48
In January 1998, Mountaineer filed with the WVPSC for an increase in its base
rates, which would become effective upon expiration of the initial Rate
Moratorium. In July 1998, Mountaineer agreed to a Joint Stipulation and
Agreement for Settlement (the "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 Settlement, Mountaineer was granted an
increase in its rates which, assuming certain weather conditions, would generate
additional annual revenues of approximately $9.4 million and which provided for
a new three year Rate Moratorium which began on November 1, 1998 and continues
through October 31, 2001. Other significant terms and conditions of the
Settlement are similar to those under which Mountaineer operated during the
prior Rate Moratorium. Beginning November 1, 1998, the remaining balance of
overrecovered gas costs and certain transportation revenues, storage balancing
fees and standby charges, totaling $6.4 million, previously deferred during the
initial Rate Moratorium will be credited to gas expense over the three-year
period ending October 31, 2001. During fiscal 1999, Mountaineer credited $1.4
million against gas costs in accordance with the Settlement.
19. INDUSTRY SEGMENTS
The Company adopted SFAS No. 131, "Disclosures About Segments of an Enterprise
and Related Information," in fiscal 1999. The information for fiscal 1998 and
1997 has been restated from the prior year's presentation to conform to the
fiscal 1999 presentation.
The Company's reportable business segments have been identified based on the
differences in products and service provided. Revenues for the exploration and
production segment are derived from the production and sale of natural gas and
crude oil. The regulated utility segment generates revenue from the
transportation and sale of natural gas at retail. Revenues for the marketing
and pipeline segment arise from the marketing of both Company and third party
produced natural gas volumes and the related transportation. The Company
utilizes earnings before interest, taxes, depreciation, depletion, amortization
and exploratory costs ("EBITDAX") to evaluate each segment's operations.
49
Summarized financial information for the Company's reportable segments is shown
in the following table. The "other" column includes items related to corporate
items (in thousands):
Exploration Marketing
and Regulated and
Production Utility Pipeline Other Consolidated
------------- ---------- ---------- -------- -------------
1999
Sales to unaffiliated customers $ 24,836 $ 158,439 $ 88,342 $ 1,430 $ 273,047
Intersegment revenues 3,431 - 9,125 - 12,556
Depreciation, depletion, amortization 10,208 9,027 1,312 1,491 22,038
Exploratory costs 19,388 - - - 19,388
Operating profit (18,031) 26,175 649 (3,521) 5,272
Interest expense 113 6,583 - 19,858 26,554
EBITDAX 12,014 35,385 1,962 (1,500) 47,861
Total assets 133,200 194,025 62,131 47,586 436,942
Capital expenditures 22,351 11,155 544 2,609 36,659
- -------------------------------------- ------------- ---------- ---------- -------- -------------
1998 - - - - -
Sales to unaffiliated customers 27,835 156,579 143,140 11,584 339,138
Intersegment revenues 3,605 - 21,593 - 25,198
Depreciation, depletion, amortization 9,707 7,777 1,270 1,284 20,038
Exploratory costs 8,262 - - - 8,262
Operating profit (2,493) 15,499 14,933 6,480 34,419
Interest expense 248 6,414 9 19,715 26,386
EBITDAX 11,893 23,362 16,202 8,260 59,717
Total assets 137,508 188,931 70,057 43,449 439,945
Capital expenditures 22,188 12,044 681 3,780 38,693
- -------------------------------------- ------------- ---------- ---------- -------- -------------
1997 - - - - -
Sales to unaffiliated customers 36,163 173,463 135,466 306 345,398
Intersegment revenues 3,672 - 24,901 (30) 28,543
Depreciation, depletion, amortization 10,376 6,387 1,222 1,060 19,045
Exploratory costs 10,121 - - - 10,121
Operating profit (1,358) 17,100 5,481 (2,156) 19,067
Interest expense 11,916 6,511 48 5,406 23,881
EBITDAX 27,354 23,490 6,703 (544) 57,003
Total assets 156,743 191,821 56,229 29,964 434,757
Capital expenditures $ 17,632 $ 10,303 $ (183) $(1,376) $ 26,376
- -------------------------------------- ------------- ---------- ---------- -------- -------------
Operating profit represents revenues less costs which are directly associated
with such operations. Revenues are priced and accounted for consistently for
both unaffiliated and intersegment sales. Intersegment sales between the
exploration and production and the utility segments have not been eliminated in
consolidation because of the regulated nature of the gas distribution segment.
The 'Other' column includes items related to non-reportable segments, corporate
and elimination items. Included in the exploration and production segment are
net long-lived assets located in New Zealand of $1.8, $1.4 and $0.1 million, as
of June 30, 1999, 1998, and 1997.
20. SUBSEQUENT EVENTS
On July 1, 1999, Mountaineer acquired substantially all of the West Virginia
assets of Shenandoah Gas Company for the purchase price of approximately $12.6
million. The acquired assets consist primarily of natural gas distribution
facilities and related equipment located in the eastern panhandle of West
Virginia.
50
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
Costs - The following tables set forth capitalized costs as of June 30 and costs
- -----
incurred, including capitalized overhead, for oil and gas producing activities
for the years ended June 30 (in thousands):
1999 1998 1997
--------- --------- ---------
Capitalized costs:
Proved properties $207,400 $197,137 192,970
Unproved properties 9,250 13,513 7,398
--------- --------- ---------
Total 216,650 210,650 200,368
Less accumulated depletion and depreciation (68,833) (64,770) (57,001)
--------- --------- ---------
Net capitalized costs $147,817 $145,880 $143,367
========= ========= =========
Company's share of equity method investee's net
capitalized costs $ 11,607 $ 9,474 8,877
========= ========= =========
Costs incurred:
Acquisition of proved properties $ 2,086 $ 2,039 $ 143
Development costs 7,527 10,227 11,649
Exploration costs 12,738 9,154 3,728
--------- --------- ---------
Total costs incurred $ 22,351 $ 21,420 $ 15,520
========= ========= =========
Company's share of equity method investee's total
costs incurred $ 3,966 $ 944 $ 115
========= ========= =========
51
Results of Operations - The results of operations for oil and gas producing
- -----------------------
activities, excluding corporate overhead and interest costs for the years ended
June 30 are as follows (in thousands):
1999 1998 1997
--------- ------- -------
Revenues from sale of oil and gas $ 21,727 $24,689 $33,301
Less:
Production costs 9,214 3,101 7,997
Production taxes 965 1,448 1,966
Exploration and impairment 19,388 8,262 10,121
Depletion, depreciation and amortization 8,409 8,021 8,325
Income tax expense (benefit) (5,681) 1,453 1,712
--------- ------- -------
Income loss from oil and gas operations $(10,562) $ 2,404 $ 3,180
========= ======= =======
Company's share of equity method investee's
income from oil and gas operations $ 183 $ 714 $ 311
========= ======= =======
Production costs include those costs incurred to operate and maintain productive
wells and related equipment and include costs such as labor, repairs and
maintenance, materials, supplies, fuel consumed and insurance. Production costs
are net of well tending fees, which are included in well operations revenues in
the accompanying consolidated statements of operations.
Exploration and impairment expenses include the costs of geological and
geophysical activity, unsuccessful exploratory wells and leasehold impairment
allowances.
Depletion, depreciation and amortization include costs associated with
capitalized acquisition, exploration, and development costs.
The provision for income taxes is computed at the statutory federal income tax
rate and is reduced to the extent of permanent differences which have been
recognized in the Company's tax provision, such as investment tax credits, and
the utilization of Federal tax credits permitted for fuel produced from a
non-conventional source.
Reserve Quantity Information - Reserve estimates are subject to numerous
- ------------------------------
uncertainties inherent in the estimation of quantities of proved reserves and in
the projection of future rates of production and timing of development
expenditures. The accuracy of such estimates is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Results of subsequent drilling, testing and production may cause either upward
or downward revisions of previous estimates. Further, the volumes considered
commercially recoverable fluctuate with changes in prices and operating costs.
Reserve estimates, by their nature, are generally less precise than other
financial statement disclosures.
52
The following table sets forth information for the years indicated with respect
to changes in the Company's proved reserves, substantially all of which are in
the United States.
Natural Crude
Gas Oil
(Mmcf) (Mbbls)
-------- -------
Proved reserves:
June 30, 1996 159,449 6,668
Revision of previous estimates 331 (197)
Extensions and discoveries 13,331 545
Sales of reserves in place (3,674) (5,336)
Production (9,106) (447)
-------- -------
June 30, 1997 160,331 1,233
Revisions of previous estimates 825 (49)
Extensions and discoveries 14,545 205
Purchases of reserves in place 2,284 79
Sales of reserves in place (11)
Production (8,525) (127)
-------- -------
June 30, 1998 169,460 1,330
Revisions of previous estimates 1,036 (224)
Extensions and discoveries 5,286 74
Purchases of reserves in place - -
Sales of reserves in place (674) (85)
Production (8,840) (133)
-------- -------
June 30, 1999 166,268 962
======== =======
Proved developed reserves:
June 30, 1997 141,116 748
======== =======
June 30, 1998 138,935 733
======== =======
June 30, 1999 144,643 717
======== =======
Company's share of equity method investee's proved reserve at:
June 30, 1997 3,452 4,402
======== =======
June 30, 1998 2,077 3,113
======== =======
June 30, 1999 5,529 9,907
======== =======
Standardized Measure of Discounted Future Net Cash Flows - Estimated discounted
- ---------------------------------------------------------
future net cash flows and changes therein were determined in accordance with
SFAS No. 69, "Disclosures About Oil and Gas Producing Activities." Certain
information concerning the assumptions used in computing the valuation of proved
reserves and their inherent limitations are discussed below. The Company
believes such information is essential for a proper understanding and assessment
of the data presented.
Future cash inflows are computed by applying period-end prices of oil and gas
relating to the Company's proved reserves to the period-end quantities of those
reserves. Future price changes are considered only to the extent provided by
contractual arrangements in existence at period-end.
53
The assumptions used to compute estimated future net revenues do not necessarily
reflect the Company's expectations of actual revenues or costs, or their present
worth. In addition, variations from the expected production rates also could
result directly or indirectly from factors outside of the Company's control,
such as unintentional delays in development, changes in prices or regulatory
controls. The reserve valuation further assumes that all reserves will be
disposed of by production. However, if reserves are sold in place, this could
affect the amount of cash eventually realized.
Future development and production costs are computed by estimating the
expenditures to be incurred in developing and producing the proved oil and gas
reserves at the end of the year, based on period-end costs and assuming
continuation of existing economic conditions.
Future income tax expenses are computed by applying the appropriate year-end
statutory tax rates and existing tax credits, with consideration of future tax
rates already legislated, to the future pretax net cash flows relating to the
Company's proved oil and gas reserves.
An annual discount rate of 10% was used to reflect the timing of the future net
cash flows relating to proved oil and gas reserves.
Information with respect to the Company's estimated discounted future net cash
flows related to its proved oil and gas reserves as of June 30 is as follows (in
thousands):
1999 1998 1997
---------- ---------- ----------
Future cash in flows $ 445,872 $ 457,015 $ 473,464
Future production and development costs (165,236) (170,169) (172,219)
Future income tax expense (63,000) (57,000) (50,607)
---------- ---------- ----------
Future net cash flows before discount 217,636 229,846 250,638
10% discount to present value (126,433) (138,581) (143,791)
---------- ---------- ----------
Standardized measure of discounted future net cash
flows related to proved oil and gas reserves $ 91,203 $ 91,265 $ 106,847
========== ========== ==========
Company's share of equity method investee's
standardized measure of discounted future net
cash flows $ 28,129 $ 19,975 $ 27,201
========== ========== ==========
54
Principal changes in the standardized measure of discounted future net cash
flows for the years ended June 30 are as follows (in thousands):
1999 1998 1997
--------- --------- ---------
Standardized measure of discounted future
net cash flows at beginning of period $ 91,265 $106,847 $109,941
Sales of oil and gas produced, net of
production costs (11,548) (13,816) (17,854)
Net changes in prices and production costs (249) (12,729) 17,395
Changes in production rates and other (7,405) (14,256) 50
Extensions, discoveries and other additions, net
of future production and development costs 4,177 5,910 12,185
Changes in estimated future development costs 2,701 (1,495) (7,609)
Development costs incurred 7,527 10,227 11,649
Revisions of previous quantity estimates (347) 422 (1,022)
Purchase of reserves in place - 2,026
Sales of reserves in place (922) (56) (25,075)
Accretion of discount 9,126 10,685 10,994
Net change in income taxes (3,122) (2,500) (3,807)
--------- --------- ---------
Standardized measure of discounted
future net cash flows at end of period $ 91,203 $ 91,265 $106,847
========= ========= =========
* * * * *
55
ENERGY CORPORATION OF AMERICA SCHEDULE I
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED BALANCE SHEETS INFORMATION
JUNE 30, 1999 AND 1998
(DOLLARS IN THOUSANDS)
- ------------------------------------------------------------
ASSETS 1999 1998
-------- --------
CURRENT ASSETS:
Cash $ 12,388 $ 19,158
Accounts receivable, affiliates 39,175 19,787
Accounts receivable, other 140 388
Other current assets 5,982 5,324
-------- --------
Total current assets 57,685 44,657
PROPERTY, PLANT AND EQUIPMENT - Net 5,476 3,226
INVESTMENT IN SUBSIDIARIES 161,679 173,440
OTHER ASSETS 20,947 13,448
-------- --------
TOTAL $245,787 $234,771
======== ========
LIABILITIES AND STOCKHOLDER'S EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued expenses $ 11,934 $ 3,833
LONG-TERM LIABILITIES
Long-term debt 219,198 200,661
STOCKHOLDER'S EQUITY 14,655 30,277
-------- --------
TOTAL $245,787 $234,771
======== ========
See notes to condensed financial information.
56
ENERGY CORPORATION OF AMERICA SCHEDULE I
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF OPERATIONS INFORMATION
FOR THE YEARS ENDED JUNE 30, 1999, 1998 AND 1997
(DOLLARS IN THOUSANDS)
- ---------------------------------------------------------------------------------
1999 1998 1997
--------- --------- --------
COSTS AND EXPENSES:
General and administrative $ 4,060 $ 3,355 $ 2,608
Depreciation of property, plant and equipment 350 160 40
--------- --------- --------
LOSS FROM OPERATIONS (4,410) (3,515) (2,648)
INTEREST EXPENSE 20,009 19,875 2,152
OTHER (INCOME) EXPENSE (529) (1,072) (1,246)
--------- --------- --------
LOSS BEFORE INCOME TAXES AND EQUITY
IN EARNINGS OF SUBSIDIARIES (23,890) (22,318) (3,554)
BENEFIT FROM INCOME TAXES (11,337) (8,335) (2,565)
--------- --------- --------
LOSS BEFORE EQUITY IN EARNINGS OF
SUBSIDIARIES (12,553) (13,983) (989)
EQUITY IN EARNINGS (LOSSES) OF
SUBSIDIARIES (2,334) 16,997 (4,854)
--------- --------- --------
NET INCOME (LOSS) $(14,887) $ 3,014 $(5,843)
========= ========= ========
See notes to condensed financial information.
57
ENERGY CORPORATION OF AMERICA SCHEDULE I
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF CASH FLOWS INFORMATION
FOR THE YEARS ENDED JUNE 30, 1999, 1998 AND 1997
(DOLLARS IN THOUSANDS)
- -------------------------------------------------------------------------------------------------
1999 1998 1997
--------- ---------- ---------
CASH FLOWS FROM OPERATIONS:
Net income (loss) $(14,887) $ 3,014 $ (5,843)
Adjustments to reconcile net income to cash
Provided by (used in) operating activities:
Equity in undistributed (earnings) losses of subsidiaries 2,334 (16,997) 4,854
Depreciation and amortization 1,149 946 104
Changes in operating assets and liabilities (2,089) (9,524) 5,077
Other (9,346) (2,340) (4,634)
--------- ---------- ---------
Net cash used in operating activities (22,839) (24,901) (442)
--------- ---------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Advances to subsidiaries (18,154) (2,022) (9,821)
Expenditures for property (2,600) (2,358) (229)
Other investing activities (141) (3,137) -
--------- ---------- ---------
Net cash used in investing activities (20,895) (7,517) (10,050)
--------- ---------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends paid (960) (815) (1,007)
Proceeds from issuance of debt 27,500 1,298 200,000
Principal payments on debt (2,923) (217)
Contributions to capital of subsidiaries (5,408) (178,378)
Deferred financing costs (601) (7,055)
Repurchase of stock (2,198) (523) (2,054)
Subsidiary dividends and other 15,545 41,650 11,724
--------- ---------- ---------
Net cash provided by financing activities 36,964 35,384 23,230
--------- ---------- ---------
Net increase (decrease) in cash and cash equivalents (6,770) 2,966 12,738
Cash and cash equivalents, beginning of year 19,158 16,192 3,454
--------- ---------- ---------
CASH AND CASH EQUIVALENTS AT
END OF YEAR $ 12,388 $ 19,158 $ 16,192
========= ========== =========
See notes to condensed financial information.
58
ENERGY CORPORATION OF AMERICA SCHEDULE I
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
NOTES TO CONDENSED FINANCIAL INFORMATION
FOR THE YEARS ENDED JUNE 30, 1999, 1998 AND 1997
- ---------------------------------------------------------
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Investments in Subsidiaries - The financial statements of Energy Corporation of
- ----------------------------
America (the "Company") reflect investments in Eastern American Energy
Corporation, Eastern Systems Corporation, Westech Energy Corporation and Westech
Energy New Zealand Limited ("the subsidiaries"), wholly owned subsidiaries,
using the equity method.
Income Taxes - The benefit for income taxes is based on losses recognized for
- -------------
financial statement purposes determined on a separate company basis. Deferred
income taxes are recognized for the tax effects of temporary differences between
such losses and those recognized for income tax purposes. The Company files a
consolidated U.S. income tax return with its subsidiaries.
2. CONSOLIDATED FINANCIAL STATEMENTS
Reference is made to the Consolidated Financial Statements and related Notes of
Energy Corporation of America and Subsidiaries for additional information.
3. LONG-TERM DEBT
Information concerning debt of the Company on a consolidated basis is disclosed
in Note 5 of the Notes to Consolidated Financial Statements of Energy
Corporation of America and Subsidiaries included elsewhere herein. The
Company's $200 million in 9 1/2% senior subordinated notes are due in 2007. The
Company's $22 million revolving line of credit is due in 2002.
4. DIVIDENDS RECEIVED
The Company received dividends from its subsidiaries of $15.5 million, $41.6
million and $10.4 million for the years ended June 30, 1999, 1998 and 1997,
respectively.
*****
59
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED JUNE 30, 1999, 1998 AND 1997
(AMOUNTS IN THOUSANDS) SCHEDULE II
- -----------------------------------------------------------------------------------------------
1999 1998 1997
-------- -------- --------
Allowance for doubtful accounts, balance at beginning of period $ 1,681 $ 1,660 $ 1,744
Charged to costs and expenses 2,109 2,572 2,102
Charged to other accounts (1) 354 58 291
Deductions (2) (2,082) (2,609) (2,477)
-------- -------- --------
Allowance for doubtful accounts, balance at end of period $ 2,062 $ 1,681 $ 1,660
======== ======== ========
(1) Recoveries of accounts previously written off
(2) Accounts written off
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
------- ----------------------------------------------
ON ACCOUNTING AND FINANCIAL DISCLOSURE
--------------------------------------
There have been no changes in or disagreements with accountants on accounting
and financial disclosure.
60
PART III
--------
ITEM 10. DIRECTORS AND OFFICERS OF REGISTRANT
-------- ------------------------------------
The executive officers and Directors of the Company and the executive
officers of its subsidiaries on June 30, 1999 are listed below, together with a
description of their experience and certain other information. All of the
Directors were re-elected for a one year term at the Company's December 1998
annual meeting of stockholders. Executive officers are appointed by the Board
of Directors.
Name Age Position with Company or Subsidiary
- ----------------------- --- --------------------------------------------------------------
John Mork 51 President and Chief Executive Officer of the Company; Director
Joseph E. Casabona 56 Executive Vice President of the Company; Director
J. Michael Forbes 39 Vice President of the Company
Isobel M. Allan 42 Vice President/Treasurer of the Company
F. H. McCullough, III 52 Vice President of the Company; Director
Donald C. Supcoe 43 Secretary of the Company; Senior Vice President of Mountaineer
Richard E. Heffelfinger 41 President of Eastern American
Michael S. Fletcher 50 President of Mountaineer
Edward J. Davies 57 President of Westech
W. Gaston Caperton, III 59 Director
Peter H. Coors 52 Director
L. B. Curtis 75 Director
John J. Dorgan 75 Director
Arthur C. Nielsen, Jr. 80 Director
Julie Mork 49 Director
Isobel M. Allan joined the Company as Vice President of Finance in November
1998. Prior to joining the Company, Miss Allan was Assistant Treasurer with
Occidental Petroleum Corporation. Miss Allan graduated from the University of
Edinburgh, Scotland with a Bachelor of Science degree with Honors and a Master
of Science degree in Business Studies.
W. Gaston Caperton, III, has been a Director of the Company since September
25,1997. He served as the Governor of the State of West Virginia for two terms,
from 1989 to 1997. Mr. Caperton presently serves as President of The Caperton
Group. He currently serves as President and Chief Executive Officer of The
College Board. Mr. Caperton presently serves on the Board of Directors of Owens
Corning and United Bankshares.
Joseph E. Casabona is Executive Vice President of the Company and has been
a Director since its formation. Mr. Casabona joined Eastern American in 1985
and was Executive Vice President of Eastern American and a Director from 1987
until 1993. Mr. Casabona was employed in various audit staff capacities from
1967 to 1979 in the Pittsburgh, Pennsylvania office of KPMG Main Hurdman ("KPMG,
Peat Marwick"), became a partner in the Firm in 1980 and was named Director of
Accounting and Auditing of the Pittsburgh office in 1983. Mr. Casabona
graduated from the University of Pittsburgh with a B.S. in Business
Administration and from the Colorado School of Mines with a M.S. in Mineral
Economics. Mr. Casabona has been a Certified Public Accountant since 1969. Mr.
Casabona has been a member of the Boards of Directors of the West Virginia and
Pennsylvania Independent Oil and Gas Associations.
61
Peter H. Coors has been a Director of the Company since 1996. Mr. Coors is
Vice Chairman of the Board and Chief Executive Officer of Coors Brewing Company
and Vice President of Adolph Coors Company. He received his Bachelors Degree in
Industrial Engineering from Cornell University in 1969, and he earned his
Masters Degree in Business Administration from the University of Denver in 1970.
Mr. Coors also serves on the Board of Directors of First Bank Systems.
L.B. Curtis has been a Director of the Company since 1993. Mr. Curtis was
a Director of Eastern American from 1988 until 1993. Mr. Curtis is retired from
a career at Conoco, Inc. where he held the position of Vice President of
Production Engineering with Conoco Worldwide. Mr. Curtis was highly recognized
across the Petroleum Industry in the upstream (exploration and production)
segment of the industry. Mr. Curtis graduated from The Colorado School of Mines
with an Engineer of Petroleum Professional degree.
Edward J. Davies has been President of Westech Energy Corporation and
Managing Director of Westech Energy New Zealand Limited since 1994. Previously,
Mr. Davies was with Conoco Inc., where his most recent positions were General
Manager Exploration and Managing Director Nigeria. Mr. Davies holds a Bachelors
of Science in Geology from the University of Wales, a Doctor of Philosophy in
Geology from the University of Alberta, and a Masters of Science from the
Massachusetts Institute of Technology Sloan School of Management.
John J. Dorgan has been a Director of the Company since 1993. He served as
a Director for Eastern American in 1992. He is a former Executive Vice
President and consultant to Occidental Petroleum Corporation where he had worked
in various capacities since 1972.
Michael S. Fletcher has been President of Mountaineer Gas Company since
August 1998. Prior to that time, he also held the positions of Senior Vice
President and Chief Financial Officer of Mountaineer. Before joining
Mountaineer in 1987, Mr. Fletcher was a partner of Arthur Andersen and Company
and was employed by that firm for fifteen (15) years. Mr. Fletcher is a
Certified Public Accountant and a board member for the Board of Risk and
Insurance Management for the State of West Virginia. Mr. Fletcher graduated
from Utah State University with a Bachelors Degree in Accounting.
J. Michael Forbes has been Vice President of the Company since 1995. Prior
to that, Mr. Forbes was an officer with Eastern American, which he joined in
1982. Mr. Forbes graduated with a Bachelors of Arts in Accounting and Finance
from Glenville State College and is a Certified Public Accountant. He also
holds a Masters of Business Administration from Marshall University and is a
graduate of Stanford University's Program for Chief Financial Officers.
Richard E. Heffelfinger is President of Eastern American and Eastern
Marketing. Mr. Heffelfinger joined Eastern American in 1980. Mr. Heffelfinger
currently serves on the Board of Directors of Capital State Bank of West
Virginia. He is a member of the Young Presidents' Organization, Mountain States
Chapter, and a past President and current Board Member of the Independent Oil
and Gas Association of West Virginia. In addition, Mr. Heffelfinger currently
serves as Chairman of the Greater Kanawha Valley YMCA. Mr. Heffelfinger is a
graduate of Glenville State College.
F. H. McCullough, III, has been a Director of the Company since 1993. Mr.
McCullough joined Eastern American in 1977. Mr. McCullough currently serves as
Vice President of the Company. Mr. McCullough was a Director of Eastern
American from 1978 until 1993. Mr. McCullough is a graduate of the University
of Southern California with a Bachelor of Arts Degree in International Economics
and two Masters Degrees in Business Administration and Financial Systems
Management. He is a graduate of the Northwestern University Kellogg Graduate
School of Management Executive Marketing Program. Effective October 1, 1999,
Mr. McCullough resigned as Vice President of the Company and retained his
position as Director.
62
John Mork has been President and Chief Executive Officer of the Company and
a Director of the Company since its formation. Mr. Mork served in various
capacities at Union Oil Company until 1972 when he joined Pacific States Gas and
Oil, Inc. and subsequently founded Eastern American. Mr. Mork was President and
a Director of Eastern American from 1973 until 1993. Mr. Mork is a past Director
of the Independent Petroleum Association of America, and the Independent Oil and
Gas Association of West Virginia. He was chapter chairman of the Young
Presidents' Organization, Inc., Rocky Mountain Chapter from 1994 to 1995. Mr.
Mork also founded the Mountain State Chapter of the Young Presidents'
Organization located in Charleston, West Virginia. Mr. Mork holds a Bachelor of
Science Degree in Petroleum Engineering from the University of Southern
California and he is a graduate of the Stanford Business School Program for
Chief Executive Officers. He is the husband of Julie Mork.
Julie M. Mork has been a Director of the Company since 1993. She was a
Director of Eastern American from 1974 until 1993. Mrs. Mork served as a
founder and Secretary/Treasurer of Pacific States Gas and Oil, Inc. and Eastern
American. Mrs. Mork received a Bachelor of Arts Degree in history from the
University of California in Los Angeles. She is the wife of John Mork.
Arthur C. Nielsen, Jr. has been a Director of the Company since 1993. He
was a Director of Eastern American from 1985 until 1993. He serves on the Board
of Directors of General Binding Corporation. He also serves as senior advisor
to the Toshiba Corporation.
Donald C. Supcoe has been the Senior Vice President of Mountaineer Gas
Company since August 1998. Prior to joining Mountaineer, he was the Vice
President, General Counsel and Secretary of Eastern American with whom he had
been employed since 1981. Mr. Supcoe is a past President of the Independent Oil
and Gas Association of West Virginia and a past Vice President of the
Independent Petroleum Association of America. Mr. Supcoe graduated from West
Virginia University with a Bachelor of Science Degree in Business
Administration. Mr. Supcoe received a Doctor of Jurisprudence Degree from West
Virginia University College of Law.
63
ITEM 11. EXECUTIVE COMPENSATION
-------- ----------------------
The following table sets forth for fiscal year 1999 the total value of
compensation of (i) the Company's Chief Executive Officer and (ii) each other
executive officer of the Company.
Salary Bonus Other Total
-------- -------- ---------- --------
John Mork $246,820 $287,616 54,971 (1) $589,407
President and Chief Executive Officer
Joseph E. Casabona 215,086 144,250 10,300 (2) 369,636
Executive Vice President
Edward J. Davies 181,091 90,150 6,682 (3) 277,923
President of Westech Energy Corporation
Michael S. Fletcher 220,934 122,802 36,254 (4) 379,990
President of Mountaineer Gas Company
Richard E. Heffelfinger 188,356 91,320 4,403 (5) 284,079
President of Eastern American Energy Coporation
_______________
(1) Includes $6,814 in compensation related to insurance policies provided for
the benefit of John Mork, $43,036 for personal use of company owned assets
and $5,121 in 401K matching contributions.
(2) lncludes $4,410 in compensation related to insurance policies provided for
the benefit of Joseph E. Casabona, $2,379 for personal use of company owned
assets and $3,511 in 401K matching contributions.
(3) Includes $1,188 in compensation related to an insurance policy provided for
the benefit of Edward J. Davies, $2,095 for personal use of company owned
assets and $3,399 in 401K matching contributions.
(4) Includes $924 in compensation related to an insurance policy provided for
the benefit of Michael S. Fletcher, $19,332 for personal use of company
owned assets and $16,008 for employee dependent tuition assistance.
(5) Includes $275 in compensation related to an insurance policy provided for
the benefit of Richard E. Heffelfinger, $617 for personal use of company
owned assets and $3,511 in 401K matching contributions.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN
-------- -----------------------------
BENEFICIAL OWNERS AND MANAGEMENT
--------------------------------
The following table sets forth certain information regarding (i) the share
ownership of the Company by each person known to the Company to be the
beneficial owner of more than 5% of the outstanding shares of Common Stock, (ii)
the share ownership of the Company by each Director, (iii) the share ownership
of the Company by certain executive officers and (iv) the share ownership of the
Company by all directors and executive officers as a group, in each case as of
September 1, 1999. The business address of each officer and director listed
below is: c/o Energy Corporation of America, 4643 S. Ulster, Suite 1100,
Denver, Colorado 80237.
64
Beneficial Ownership
Common Stock
-------------------
Number
of Shares Percent
--------- --------
Kenneth W. Brill (1) 65,210 10.09%
W. Gaston Caperton, III 320 *
Joseph E. Casabona 18,216 2.82%
Peter H. Coors 703 *
L. B. Curtis 12,100 1.87%
John J. Dorgan 970 *
J. Michael Forbes 2,400 *
Richard E. Heffelfinger 4,860 *
F. H. McCullough, III (3)(4) 90,325 13.98%
John Mork (2) 379,923 58.81%
Julie Mork (2) 379,923 58.81%
Arthur C. Nielsen, Jr. 36,320 5.62%
Donald C. Supcoe 3,200 *
All officers and Directors as a group (13 persons) 614,547 95.12%
_______________
* Less than one percent.
(1) Pursuant to agreements dated June 30, 1993 and July 8, 1996, Kenneth W.
Brill granted the Company options to purchase 15,400 and 75,850 shares,
respectively, of the Company Common Stock owned by him, 30,050 of which
have been purchased by the Company.
(2) Includes 371,520 shares held by John and Julie Mork as joint tenants, 2,503
shares held by Julie Mork individually, and 2,950 shares held by each of
the Alison Mork Trust and the Kyle Mork Trust.
(3) Pursuant to an agreement dated May 20, 1997, F.H. McCullough, III and his
wife, Kathy L. McCullough, jointly granted the Company an option to
purchase 11,920 shares of the Company's Common Stock owned by them, all of
which have been purchased by the Company.
(4) Includes 88,405 shares held by F.H. McCullough, III and Kathy McCullough as
joint tenants, 720 shares held by the Katherine F. McCullough Trust, and
400 shares held by each of the Lesley McCullough Trust, the Meredith
McCullough Trust and the Kristin McCullough Trust.
The following table sets forth certain information regarding (i) the share
ownership of the Company by each person known to the Company to be the
beneficial owner of more than 5% of the outstanding shares of Class A Stock,
(ii) the share ownership of the Company's Class A Stock by each Director, (iii)
the share ownership of the Company's Class A Stock by certain executive officers
and (iv) the share ownership of the Company's Class A Stock by all directors and
executive officers as a group, in each case as of September 1, 1999. The
business address of each officer an director listed below is : c/o Energy
Corporation of American, 4643 South Ulster Street, Suite 1100, Denver, Colorado
80237.
65
Beneficial Ownership
Class A Stock
-------------------
Number
of Shares Percent
--------- --------
Joseph E. Casabona 5,791 27.57%
Edward J. Davies 5,281 25.14%
Michael S. Fletcher 2,500 11.90%
Richard E. Heffelfinger 168 *
John Mork (1) 796 3.79%
Julie Mork (1) 796 3.79%
Arthur C. Nielsen, Jr. 1,160 5.52%
Donald C. Supcoe 1,667 7.94%
All officers and Directors as a group (8 persons) 17,363 82.66%
_______________
* Less than one percent
(1) Includes 796 shares held by John and Julie Mork as joint tenants.
ITEM 13. CERTAIN RELATIONSHIPS AND
-------- -------------------------
RELATED TRANSACTIONS
--------------------
Certain officers and Directors of the Company and members of their families
regularly participate in the wells drilled by the Company on an actual costs
basis and share in the costs and revenues on the same basis as the Company. The
Company has the right to select the wells drilled and each participant is
involved in all wells included within a Company drilling program (the "Drilling
Program") and cannot selectively choose the wells in which to participate. The
Company typically has a development drilling component and an
exploration-drilling component within each year's Drilling Program. The officers
and Directors and their family members may participate in either or both of the
components. The following table identifies the participants' aggregate
investment in the calendar years shown:
66
1999 * 1998 1997
-------- ---------- --------
Dale P. Andrews $ 10,000 $ 13,137
K.W. Brill 25,000 173,755 $ 47,318
Gaston Caperton 392,150
Joseph E. Casabona 40,000 52,732 41,871
Peter Coors 25,000 52,732
L.B. Curtis 50,000 108,688 39,877
E.J. Davies 125,000 101,051 26,985
John J. Dorgan 50,000 52,732 32,543
J. Michael Forbes 7,636 13,120
Richard L. Grant 27,905 21,287
F.H. McCullough, III 75,000 159,793 97,458
Lesley McCullough Trust (2) 7,636 542
Kristen McCullough Trust (2) 7,636 542
Meredith McCullough Trust (2) 7,636 542
Katherine McCullough Trust (2) 7,636 542
John Mork (1) 250,000 798,966 321,317
Alison Mork Trust (3) 25,000 40,984 37,300
Kyle Mork Trust (3) 25,000 40,984 37,300
Arthur C. Nielsen, Jr. 50,000 139,440 29,623
Donald C. Supcoe 7,636 4,979
ECA Foundation - 78,127 -
-------- ---------- --------
Total $750,000 $2,278,992 $753,146
======== ========== ========
_______________
* These amounts represent only the amounts committed to the 1999 Drilling
Program, the actual investment may vary.
(1) Interest of John Mork and Julie Mork held as joint tenants.
(2) Trusts for Minor children of F. H. McCullough, III and Kathy L. McCullough.
(3) Trusts for Minor children of John Mork and Julie Mork.
Certain officers, Directors and key employees of the Company have notes
payable to the Company related to employee incentive stock options that were
granted and exercised. The notes bear various interest rates, ranging from
LIBOR to 8% per annum. As of June 30, 1999, in excess of $60,000, the following
were indebted to the Company (in thousands):
Dale P. Andrews $ 63
Joseph E. Casabona 187
Edward J. Davies 319
J. Michael Forbes 96
Michael S. Fletcher 187
Richard E. Heffelfinger 192
Donald C. Supcoe 209
------
Total $1,253
======
67
Certain officers and Directors of the Company have borrowed money from the
Company and have executed promissory notes. The notes bear interest at 8% per
annum. As of June 30, 1999, the following were indebted to the Company (in
thousands):
Isobel M. Allan * $158
Michael S. Fletcher * 161
F. H. McCullough, III 160
----
Total $479
====
_______________
* Promissory notes are being forgiven over three years, assuming
continuing employment.
68
During fiscal 1999, the Company purchased from certain officers and
directors volumetric production from wells in New Zealand. Future production,
otherwise allocable to the officers and directors will be allocated to the
Company. The following table identifies the participants' interest:
Payment Volumes
(in thousands) Mmcf
--------------- -------
Dale P. Andrews $ 20 26.7
K.W. Brill 200 266.7
Gaston Caperton 600 800.0
Joseph E. Casabona 50 66.7
Peter Coors 50 66.7
L.B. Curtis 150 200.0
E.J. Davies 150 200.0
John J. Dorgan 50 66.7
Thomas R. Goodwin 50 66.7
Richard L. Grant 50 66.7
F.H. McCullough, III 150 200.0
John Mork 750 1,000.0
Alison Mork Trust 50 66.7
Kyle Mork Trust 50 66.7
Arthur C. Nielsen, Jr. 94 125.3
--------------- -------
Total $ 2,464 3,285.6
=============== =======
The Company rents office space in Charleston, West Virginia from Energy
Centre, Inc. a corporation owned 40.0% by John Mork, 20.0% by each of F. H.
McCullough, III and Joseph E. Casabona and 6.67% by each of Donald C. Supcoe,
Richard E. Heffelfinger and J. Michael Forbes. The aggregate amount paid by the
Company for rent to Energy Centre, Inc. was $339,470 for fiscal year 1999. The
Company believes that such rental terms are no less favorable than could have
been obtained from an unaffiliated party.
69
PART IV
-------
ITEM 14. EXHIBITS, FINANCIAL STATEMENT
-------- -----------------------------
SCHEDULES AND REPORTS ON FORM 8-K
---------------------------------
(a) 1. Financial Statements
The Financial Statements are filed as a part of this annual report at Item 8.
2. Financial Statement Schedules
The Financial Statements are filed as a part of this annual report at Item 8.
3. Exhibits
The following is a complete list of Exhibits filed as part of, or incorporated by
reference to this Registration Statement:
70
* 3.1 Articles of Incorporation of Energy Corporation of America
* 3.2 Amended Articles of Incorporation of Energy Corporation of America
* 3.3 Amended Bylaws of Energy Corporation of America
* 4.1 Credit Agreement among Energy Corporation of America, General Electric
Capital Corporation as Agent, and the lenders named therein, dated as of
May 20, 1997.
* 4.2 Note Purchase Agreement between Mountaineer Gas Company and The
John Hancock Mutual Life Insurance Company dated as of October 12, 1995.
* 4.3 Indenture, dated as of May 23, 1997, between Energy Corporation of America
and The Bank of New York, as Trustee, with respect to the 9 1/2% Senior
Subordinated Notes Due 2007 (including form of 9 1/2% Senior Subordinated
Note Due 2007.
* 4.4 Form of 9 1/2% Senior Subordinated Note due 2007, Series A.
* 4.5 Registration Rights Agreement, dated as of May 20, 1997, among Energy
Corporation of America, as issuer, and Chase Securities Inc. and Prudential
Securities Inc.
* 10.1 Eastern American Energy Corporation Profit/Incentive Stock Plan dated
as of June 4, 1997.
* 10.2 Buy-Sell Stock Option Agreement dated as of May 19, 1997 among Energy
Corporation of America, F.H. McCullough, III and Kathy L. McCullough.
* 10.3 Buy-Sell Stock Option Agreement dated as of July 8, 1996 between Energy
Corporation of America and Kenneth W. Brill.
* 10.4 Gas Purchase Contract dated as of January 1, 1993 between Eastern
American Energy Corporation and Eastern Marketing Corporation.
* 10.5 FTSI Service Agreement No. 37994 dated as of November 1,1993 between
Mountaineer Gas Company and Columbia Gulf Transmission Company.
71
* 10.6 Service Agreement No. 42794 dated as of November 1,1994 between
Mountaineer Gas Company and Columbia Gulf Transmission Company.
* 10.7 SST Service Agreement No. 38087 dated as of November 1,1993 between
Mountaineer Gas Company and Columbia Gas Transmission Corporation
* 10.8 FTS Service Agreement No. 38137 dated as of November 1,1993 between
Mountaineer Gas Company and Columbia Gas Transmission Corporation.
(Previously misidentified as FTS Service Agreement No. 38037)
* 10.9 Supplement No. 1 to Transportation Service Agreement No. 38137 dated
as of May 6, 1994 between Mountaineer Gas Company and Columbia Gas
Transmission Corporation.
* 10.10 FSS Service Agreement No. 38077 dated as of November 1,1993 between
Mountaineer Gas Company and Columbia Gas Transmission Corporation.
* 10.11 NTS Service Agreement No. 39272 dated as of November 1,1993 between
Mountaineer Gas Company and Columbia Gas Transmission Corporation.
* 10.12 FTS Service Agreement No. 38113 dated as of November 1,1993 between
Mountaineer Gas Company and Columbia Gas Transmission Corporation.
* 10.13 Supplement No. 1 to Transportation Service Agreement No. 38113 dated
as of May 6, 1994 between Mountaineer Gas Company and Columbia Gas
Transmission Corporation.
* 10.14 Gas Transportation Agreement dated as of October 1, 1994 between
Mountaineer Gas Company and Tennessee Gas Pipeline Company.
* 10.15 Amendment No. 1 to Gas Transportation Agreement dated as of May 5, 1995
between Mountaineer Gas Company and Tennessee Gas Pipeline Company.
* 10.16 FTS Service Agreement No. 60266 dated May 20, 1998 between Mountaineer
Gas Company and Columbia Gas Transmission Corporation.
* 10.17 Incentive Stock Purchase Agreement dated February 12, 1999 by and
between Energy Corporation of America and Michael S. Fletcher.
10.18 Incentive Stock Purchase Agreement dated December 16, 1998 by and
between Energy Corporation of America and Joseph E. Casabona.
10.19 Incentive Stock Purchase Agreement dated December 16, 1998 by and
between Energy Corporation of America and Edward J. Davies.
10.20 Incentive Stock Purchase Agreement dated December 16, 1998 by and
between Energy Corporation of America and Donald C. Supcoe.
10.21 Incentive Stock Purchase Agreement dated March 19, 1999 by and
between Energy Corporation of America and Gaston Caperton.
10.22 Incentive Stock Purchase Agreement dated March 19, 1999 by and
between Energy Corporation of America and Peter H. Coors.
10.23 Incentive Stock Purchase Agreement dated March 19, 1999 by and
between Energy Corporation of America and L.B. Curtis.
10.24 Incentive Stock Purchase Agreement dated March 19, 1999 by and
between Energy Corporation of America and J. J. Dorgan.
72
10.25 Incentive Stock Purchase Agreement dated March 19, 1999 by and
between Energy Corporation of America and A. C. Nielsen, Jr.
10.26 Stock Purchase Agreement dated February 17, 1999 by and among Westech
Energy Corporation, Westech Energy New Zealand Limited and Edward
J. Davies
10.27 First Amendment to Credit Agreement and Assignment and Waiver dated
September 26, 1997 by and among Energy Corporation of America, General
Electric Capital Corporation, The Bank of Nova Scotia and Union Bank of
California, N.A.
10.28 Second Amendment to Credit Agreement dated April 2, 1999 by
and among Energy Corporation of America, General Electric Capital Corporation,
The Bank of Nova Scotia and Union Bank of California, N.A.
10.29 Third Amendment to Credit Agreement dated September 27, 1999 by
and among Energy Corporation of America, General Electric Capital Corporation,
The Bank of Nova Scotia and Union Bank of California, N.A.
10.30 Natural Gas Supply Management Agreement dated September 30, 1998, by and
Between Coral Energy Resources, L.P., Coral Energy, L.P. and Mountaineer.
21.1 Subsidiaries of Energy Corporation of America.
25.1 Power of Attorney set forth on the signature page contained in Part V.
27.1 Financial Data Schedule.
* Previously filed.
(b) Reports on Form 8-K
No reports on Form 8-K have been filed during the fiscal year ended June 30, 1999.
73
PART V
------
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto, duly authorized, on the 27th day of
September 1999.
ENERGY CORPORATION OF AMERICA
By: /s/ John Mork
-----------------------------------------
John Mork
President and Chief Executive Officer
74
POWER OF ATTORNEY
-----------------
Each of the undersigned officers and directors of Energy Corporation of
America (the "Company") hereby constitutes and appoints John Mork, Joseph E.
Casabona and Isobel M. Allan and each of them (with full power to each of them
to act alone), his true and lawful attorney-in-fact and agent, with full power
of substitution, for him and on his behalf and in his name, place and stead, in
any and all capacities, to sign, execute and file this Form 10-K under the
Securities Act of 1934, as amended, and any or all amendments (including,
without limitation, post-effective amendments), with all exhibits and any and
all documents required to be filed with respect thereto, with the Securities and
Exchange Commission or any regulatory authority, granting unto such
attorneys-in-fact and agents, and each of them acting alone, full power and
authority to do and perform each of every act and thing requisite and necessary
to be done in and about the premises in order to effectuate the same, as full to
all intents and purposes as he himself might or could do if personally present,
hereby ratifying and confirming all the such attorneys-in-fact and agents, or
any of them, or their substitute or substitutes, may lawfully do or cause to be
done.
Pursuant to the requirements of the Securities Act of 1934, this Form 10-K
has been signed on the ___ day of September 1999, by the following persons in
the capacities indicated.
75
Signature Title
- -------------------------- -----------------------------------------------------------
/s/ John Mork
- --------------------------
John Mork President, Chief Executive Officer and Director
(principal executive officer)
/s/ Joseph E. Casabona
- --------------------------
Joseph E. Casabona Executive Vice President
/s/ Isobel M. Allan
- --------------------------
Isobel M. Allan Vice President (principal accounting and financial officer)
/s/ F. H. McCullough III
- --------------------------
F. H. McCullough III Director
/s/ Gaston Caperton
- --------------------------
Gaston Caperton Director
/s/ Peter H. Coors
- --------------------------
Peter H. Coors Director
/s/ L. B. Curtis
- --------------------------
L. B. Curtis Director
/s/ John J. Dorgan
- --------------------------
John J. Dorgan Director
/s/ Julie Mork
- --------------------------
Julie Mork Director
/s/ Arthur C. Nielsen, Jr.
- --------------------------
Arthur C. Nielsen, Jr. Director
76