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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended June 30, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
From 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 (I.R.S. Employer Identification Number)
incorporation or organization)
4643 South Ulster Street, Suite 1100
Denver, Colorado 80237
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (303) 694-2667
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 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 Market Value Held by
Held by Non-affiliates at September 1, 1998 Non-affiliates
- ------------------------------------------- --------------------
32,867 Shares Unavailable
The number of shares of the registrant's common stock, par value $1.00 per
share, outstanding at September 1, 1998 was 665,145 shares.
DOCUMENTS INCORPORATED BY REFERENCE
NONE
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. For the fiscal year
ended June 30, 1998, the Company had total revenues of $364.3 million and EBITDA
(earnings before interest, taxes, depreciation and amortization) of $51.7
million. See Note 19 to the Consolidated Financial Statements concerning the
Company's industry segments.
One of the Company's wholly owned subsidiaries, Mountaineer Gas Company
("Mountaineer"), operates the largest natural gas distribution utility in West
Virginia supplying natural gas sales and transportation service to approximately
201,000 customers in 45 of the 55 counties in West Virginia. Mountaineer
distributes approximately 49% of the total natural gas volumes distributed to
end users in West Virginia. In fiscal 1998, Mountaineer owned and operated
approximately 3,900 miles of natural gas distribution pipelines, and sold or
transported approximately 62.3 Bcf of gas.
The Company is also engaged in the exploration, development, and production of
natural gas and oil. The Company is one of the largest operators in the
Appalachian Basin where it holds interests in 4,492 gross (2,605 net) wells,
substantially all of which it operates. During the fiscal year ended June 30,
1998, approximately 43% of the natural gas sold by the natural gas distribution
utility operation came from Company operated production in the Appalachian
Basin. In addition, the Company has an exploration and development program in
the Rocky Mountains and New Zealand, having acquired leasehold interests in
approximately 397,000 gross acres (248,000 net) in the Rocky Mountain area and
approximately 7,503,000 gross acres (3,751,500 net) in New Zealand. As of June
30, 1998, the Company had estimated proved reserves of 177.4 Bcfe (95.5% natural
gas and 80.8% developed) with a Present Value (discounted at 10%) of $114
million. For the fiscal year ended June 30, 1998, the Company's net gas and oil
production was approximately 9.3 Bcfe.
The Company is also engaged in the transportation and marketing of natural gas
and oil. The Company owns and operates approximately 2,100 miles of gathering
and intrastate natural gas pipelines in West Virginia and Pennsylvania. During
fiscal year 1998, the Company aggregated and sold an average of 129.5 Mmcf per
day of natural gas, of which 40.6 Mmcf per day represents gas produced from
wells operated by the Company.
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.
NATURAL GAS DISTRIBUTION UTILITY
- --------------------------------
Mountaineer owns the largest natural gas distribution system in West
Virginia, owning approximately 3,900 miles of natural gas distribution
pipelines. Mountaineer provides natural gas sales and transportation service 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.
Customers
---------
The table below sets forth certain information with respect to the
operating revenue and related gas volumes of the utility for the periods
indicated:
Year Ended June 30
------------------
1998 1997 1996
---- ---- ----
Gas Distribution Revenue:
Residential 69.9% 68.4% 71.2%
Commercial 23.4% 25.2% 23.8%
Transportation 6.3% 5.5% 3.8%
Industrial and other .4% .9% 1.2%
----- ----- -----
Total 100.0% 100.0% 100.0%
====== ====== ======
Gas Volumes:
Residential 26.4% 28.2% 30.5%
Commercial 9.4% 11.2% 10.9%
Transportation 64.1% 60.1% 57.9%
Industrial and other .1% .5% 0.7%
----- ----- -----
Total 100.0% 100.0% 100.0%
====== ====== ======
Weighted average sales rate (per Mcf) $ 6.54 $ 6.43 $ 6.40
Average use per customer (Mcf):
Residential 90 99 110
Commercial 339 432 452
Transportation 28,021 19,653 12,076
Industrial and other 6,803 27,458 34,000
Average revenue per customer:
Residential $ 599 $ 653 $ 722
Commercial $ 2,121 $ 2,636 $ 2,765
Transportation $ 6,908 $ 4,931 $ 2,226
Industrial and other $ 25,399 $121,377 $151,818
Average revenue per Mcf:
Residential $ 6.66 $ 6.60 $ 6.56
Commercial $ 6.26 $ 6.10 $ 6.12
Transportation $ 0.25 $ 0.25 $ 0.19
Industrial and other $ 3.73 $ 4.42 $ 4.47
Average gas cost per Mcf sold $ 3.81 $ 3.96 $ 3.46
Weighted average Degree Days (1) 4,941 5,275 5,535
Miles of distribution pipes 3,926 3,897 3,887
Number of customers 201,465 200,203 199,287
___________________________
(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.
More than 95% of the residential and commercial customers of the utility
use natural gas for heating. Revenues, therefore, vary with the weather and
temperature both seasonally and annually. Industrial demand is dependent on
local business conditions, competition from other natural gas suppliers,
alternate sources of energy and weather. Demand for natural gas is also
affected by federal and state energy laws and regulations.
Gas Supply
- ----------
During fiscal 1998, approximately 43% of the natural gas sold by
Mountaineer came from Company operated production. In addition to operated
production, the Company also obtains natural gas from a variety of sources,
including gas purchased in the Gulf Coast and Appalachian regions of the United
States. 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 the
Company's local distribution facilities in West Virginia. Approximately 77% of
the gas purchased in the Appalachian region is transported by Columbia Gas, with
the balance transported by Tennessee Gas or directly delivered into the
Company's gas utility distribution system.
Mountaineer historically has 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. 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 periods indicated:
Year Ended June 30
------------------
1998 1997 1996
---- ---- ----
Volume (Mcf) % of Total Volume (Mcf) % of Total Volume (Mcf) % of Total
Company operated Production 10,972,118 43% 11,364,814 39% 7,751,070 25%
Engage Energy, L.P. 3,580,939 15% 2,554,557 9%
Noble Gas Marketing 2,297,036 9% 2,787,447 10%
Equitable Resources 1,639,469 6% 2,258,074 8% 4,668,201 15%
Texaco Natural Gas 1,579,378 6% 2,346,038 8% 3,159,207 10%
Valero Gas Marketing 1,555,000 6%
Penn Union 2,701,039 9%
Natural Gas Clearinghouse 1,908,762 6%
Cabot Oil and Gas 2,391,652 8%
The following table sets forth certain information relating to Mountaineer's
gas supply purchases for the periods indicated:
Year Ended June 30
------------------
1998 1997 1996
---- ---- ----
Interstate suppliers 55% 56% 62%
Company operated production 43% 39% 25%
Other Appalachian Basin producers 2% 5% 11%
Interstate pipelines and other - - 2%
---- ---- ----
Total 100% 100% 100%
==== ==== ====
Transportation and Storage Capacity
- -----------------------------------
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
("FTS") to no-notice service ("NTS") and storage with such contracts expiring on
various dates ranging from October 31, 2000 through October 31, 2004. The
aggregate annual reservation fees associated with such contracts totaled
approximately $28,068,000 for the fiscal year ended June 30, 1998. To the
extent that Mountaineer may revise its gas procurement practices so as to
procure a greater percentage of its gas supply from local sources in West
Virginia, such firm transportation agreements and their associated reservation
fees may be phased out as such contracts expire or may be brokered and released
for various periods of time.
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 West Virginia Public Service Commission
("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.
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 has provided
rate certainty to Mountaineer's customers by fixing the price of gas for three
years. By entering into the moratorium, Mountaineer has assumed the risks and
benefits of fixed utility rates, its gas purchasing activities, ancillary
business activities and achieving operational efficiencies. Mountaineer has
capitalized on the opportunities provided by the rate moratorium by providing
billing services for a fee for a local water company, consolidating multiple
customer service centers into one location and entering into a multi-year gas
purchase contract with Mountaineer's exploration and production subsidiary,
Mountaineer Gas Services, Inc., as well as its affiliate Eastern American.
In January 1998, Mountaineer filed with the WVPSC for an increase in its
base rates which would become 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.
The agreement further 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 has 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.
Competition
- -----------
The natural gas business competes with oil for industrial uses and with
electricity for drying, cooking, water heating and space heating. Mountaineer
competes with a number of other gas utilities in West Virginia and it also
competes with gas marketers in the sale, but not the delivery (transportation),
of natural gas. Large industrial and commercial end users also have the option
to bypass Mountaineer's distribution system by constructing pipelines to
interconnect directly with the interstate pipeline that transports natural gas
into the region. 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.
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.
Mountaineer began offering gas transportation service to its industrial
customers in 1983. 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
the Company in obtaining gas supply and transportation services.
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 six month
winter heating season, with highest sales volumes occurring in December, January
and February. In fiscal 1998, gas sales from October through March accounted
for approximately 78% 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.
GAS AND OIL EXPLORATION AND PRODUCTION
- --------------------------------------
The Company, through its wholly owned subsidiary, Eastern American Energy
Corporation ("Eastern American") and Mountaineer Gas Services, a wholly-owned
subsidiary of Mountaineer, is engaged in the exploration and production of
natural gas and oil primarily within the Appalachian Basin in the states of West
Virginia, Pennsylvania, and Ohio. The Company, through its wholly owned
subsidiary Westech Energy Corporation ("Westech"), owns interests in the Rocky
Mountains and another wholly owned subsidiary, Westech Energy New Zealand
Limited ("WENZL"), owns interests in New Zealand. The Company, through WENZL, is
currently evaluating a number of exploration projects in New Zealand. The
Company's proved net gas and oil reserves are estimated as of June 30, 1998 at
169.5 Bcf and 1,330.4 Mbbls, respectively. For the fiscal year ended June 30,
1998, the Company's net gas production was approximately 8.5 Bcf and net oil
production was approximately 127.4 Mbbls, for a total of 9.3 net Bcfe.
Revenues from the sale of oil and gas production accounted for 6.8% of the
Company's consolidated revenues for 1998. For the fiscal year ended June 30,
1998, the Company's oil and gas production subsidiaries' net operating margin
was $1.49 per Mcfe.
Regional Operations
- -------------------
APPALACHIAN BASIN. The Company holds interests in 4,492 gross (2,605 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, 1998 at 164 Bcfe, of which approximately 98% was gas reserves and 2%
was oil reserves. For the fiscal year ended June 30, 1998, the Company's gas
production from its Appalachian Basin properties was approximately 8.5 net Bcf.
In the Appalachian Basin, the Company has interests in approximately 310,500
gross acres (192,300 net) of producing properties and an additional 106,500
gross acres (72,000 net) of undeveloped properties located primarily in West
Virginia, Pennsylvania and Ohio.
During the 1998 fiscal year the Company drilled a total of 30 gross wells and
23.4 net wells and added 4.9 net Bcfe in reserves.
ROCKY MOUNTAINS. Westech owns developed and undeveloped leasehold interests
in approximately 397,000 gross acres (248,000 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.
NEW ZEALAND. In 1996, WENZL obtained a five-year exploration Licence, which
includes approximately 7,503,000 gross acres (3,751,500 net) located onshore and
offshore of the North Island of New Zealand. WENZL subsequently entered into a
joint venture arrangement with Enerco New Zealand Limited, a major New Zealand
gas utility company, providing for an equal sharing of costs and benefits
associated with exploration and production activities on these properties. WENZL
and its joint venture partner have reprocessed existing seismic data and
acquired 2-D seismic surveys on a portion of the onshore acreage. The Company
anticipates initiating one onshore and three offshore 3-D surveys in fiscal year
1999. Three onshore test wells were drilled in the latter half of fiscal year
1998 and added net proved reserves of approximately 10 Bcfe. Plans include
drilling at least two additional wells in fiscal year 1999. Production and
marketing studies for the initial wells are being developed.
Oil and Gas Properties
-------------------------
As of June 30, 1998, the Company's properties included working interests in
4,512 gross (2,611 net) productive oil and gas wells. The following table sets
forth summary information with respect to the Company's estimated proved oil and
gas reserves at June 30, 1998.
Present Value Natural Gas
Amount % Oil & NGLs Natural Gas Equivalent
Region (thousands) (Mbbls) (Mmcf) (Mmcfe)
- ----------- ------------ ------ ----------- ------------ ------------
Appalachian $ 110,444 97.0% 777 159,566 164,228
Rockies 848 0.7% 217 41 1,343
New Zealand 534 0.5% 0 9,690 9,690
Other 2,072 1.8% 336 163 2,179
------------ ------ ----------- ------------ ------------
Total $ 113,898 100.0% 1,330 169,460 177,440
============ ====== =========== ============ ============
Oil and Gas Reserves
--------------------
The following table sets forth summary information with respect to the
Company's estimated proved oil and gas reserves. Substantially all information
in this Form 10-K as of June 30, 1998, 1997 and 1996 relating to estimated oil
and gas reserves and the estimated future net cash flows attributable thereto is
based upon the Reserve Reports prepared by Ryder Scott Company, independent
petroleum engineers (the "Independent Engineers"). All calculations of
estimated reserves and future net cash flows have been made in accordance with
the rules and regulations of the Securities and Exchange Commission, and, except
as otherwise indicated, give no effect to federal or state income taxes
(including Section 29 credits) otherwise attributable to estimated future cash
flows from the sale of oil and gas. The Present Value of estimated future net
cash flows has been calculated with constant prices in effect at the time of the
estimates. The term "Present Value" as used in this section means the estimated
future gross revenue to be generated from the production of proved reserves, net
of estimated production and future development costs, using prices and costs in
effect as of the date indicated, without giving effect to non-property related
expenses such as general and administrative expenses, debt service and future
income tax expenses or to depreciation, depletion and amortization, discounted
using an annual discount rate of 10%.
1998 1997 1996
-------- -------- --------
Total net proved:
Gas (Mmcf) 169,460 160,331 159,449
Oil (Mbbls) 1,330 1,233 6,668
-------- -------- --------
Total (Mmcfe) 177,440 167,729 199,457
======== ======== ========
Net proved developed:
Gas (Mmcf) 138,935 141,116 153,232
Oil (Mbbls) 733 748 6,668
-------- -------- --------
Total (Mmcfe) 143,333 145,604 193,240
======== ======== ========
Estimated future net cash flows
before income taxes (in thousands) $286,846 $301,245 $304,237
Present Value of estimated future net
cash flows before income taxes (in
thousands)(1) $113,898 $128,440 $130,778
(1) Estimated future net revenues and discounted estimated future net revenues
(10%) are not intended, and should not be interpreted, as representing the fair
market value for the estimated reserves.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and the timing of
development expenditures, including many factors beyond the control of the
producer. The reserve data set forth herein represent only estimates. Reserve
engineering is a subjective process of estimating underground accumulations of
oil and gas that cannot be measured in an exact way, and the accuracy of any
reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment and the existence of
development plans. As a result, estimates of reserves made by different
engineers for the same property will often vary. Results of drilling, testing
and production subsequent to the date of an estimate may justify a revision of
such estimates. Accordingly, reserve estimates are generally different from
quantities of oil and gas that are ultimately produced. Further, the estimated
future net revenues from proved reserves and the present value thereof are based
upon certain assumptions, including geological success, prices, future
production levels and costs that may not prove to be correct. Predictions about
prices and future production levels are subject to great uncertainty, and the
meaningfulness of such estimates depends on the accuracy of the assumptions upon
which they are based.
Producing Wells
- ---------------
The following table sets forth certain information relating to productive
wells at June 30, 1998. 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 12 4,480 4,492 3.25 2,602.0 2,605.25
Rocky Mountain 14 0 14 3.25 0.0 3.25
New Zealand 0 1 1 0.00 .5 .50
Other 5 0 5 2.00 0.0 2.00
--- ----- ----- ---- ------- --------
Total 31 4,481 4,512 8.5 2,602.5 2,611
=== ===== ===== ==== ======= ========
Acreage
- -------
The following table sets forth the developed and undeveloped gross and net
acreage held at June 30, 1998.
Developed Acreage Undeveloped Acreage
Region Gross Net Gross Net
Appalachian Basin 310,500 192,300 106,500 72,000
Rocky Mountains 500 100 396,500 247,900
New Zealand 640 320 7,503,000 3,751,500
------- ------- --------- ---------
Total 311,640 192,720 8,006,000 4,071,400
======= ======= ========= =========
Production, Prices and Production Costs
-------------------------------------------
The following table sets forth certain production data and average sales
prices attributable to the Company's properties on a historical basis for the
periods indicated:
Production Data: 1998 1997 1996
Oil (Mbbls) 127 447 522
Natural gas (Mmcf) 8,525 9,106 9,812
Natural gas equivalent (Mmcfe) 9,287 11,788 12,948
Average Sales Price:
Oil ($/Bbl) $14.30 $ 18.13 $ 16.02
Natural gas ($/Mcf) $ 2.61 $ 2.39 $ 2.01
Drilling Activities
- --------------------
The Company's gas and oil exploratory and developmental drilling activities
are as follows for the periods indicated. A well is considered productive for
purposes of the following table if it justifies the installation of permanent
equipment for the production of gas or oil. A well is deemed to be
nonproductive if is determined to be incapable of commercial production. The
term "gross wells" means the total number of wells in which the Company owns an
interest, while the term "net wells" means the sum of the fractional working
interests the Company owns in gross wells.
Year Ended June 30
------------------
1998 1997 1996
---- ---- ----
Gross Net Gross Net Gross Net
Development:
Productive
Appalachian 27 21.6 18 9.1 36 13.6
Other 5 .9 - - 2 0.8
----- ---- ----- --- ----- ----
Total 32 22.5 18 9.1 38 14.4
===== ==== ===== === ===== ====
Nonproductive
Appalachian 3 1.8 0 0 0 0
Other 1 .2 0 0 1 0.4
----- ---- ----- --- ----- ----
Total 4 2.0 0 0 1 0.4
===== ==== ===== === ===== ====
Exploratory:
Productive
Appalachian 0 0 0 0 1 0.4
Other 4 .9 1 .7 2 0.9
----- ---- ----- --- ----- ----
Total 4 .9 1 .7 3 1.3
===== ==== ===== === ===== ====
Nonproductive
Appalachian 0 0 0 0 5 2.1
Other 10 3.4 8 3.7 12 3.6
----- ---- ----- --- ----- ----
Total 10 3.4 8 3.7 17 5.7
===== ==== ===== === ===== ====
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 aggregates natural gas through 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 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 on the East Coast, 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 premium-priced 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 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 March 1998, the Company acquired a 63 mile natural
gas gathering and pipeline system for $1.3 million. The acquisition was funded
with existing cash and a long-term note of $0.9 million. See Note 5 to the
Consolidated Financial Statements. 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, 1998, the Company aggregated and sold an average of 129.5 Mmcf of gas per
day, of which 40.6 Mmcf per day represented sales of gas produced from wells
operated by the Company. This represents a decrease compared to fiscal year
1997, during which the Company aggregated and sold an average of 137.8 Mmcf of
gas per day.
Gas Sales and Purchase Contracts
- --------------------------------
In addition to supplying the Company's natural gas distribution utility,
the Company has been party to fixed price gas sales contracts with third parties
having an initial term of more than one year which obligated the Company to sell
approximately 5.2 Bcf of natural gas in fiscal 1998.
The Company satisfied its obligations under all gas sales contracts in
fiscal year 1998 through gas production attributable to its own interests in oil
and gas properties (7 Bcf in fiscal 1998), through production attributable to
third party interests in oil and gas properties (7.8 Bcf in fiscal 1998), and
from natural gas aggregated by the Company pursuant to its aggregation and
marketing activities from third parties (32.5 Bcf in fiscal 1998).
The Company's subsidiary, Eastern American, currently has a gas sales
contract with Hope Gas, Inc. ("Hope"), a subsidiary of Consolidated Natural Gas,
which requires Eastern American to sell up to 5,300 Mmbtu per day to Hope
through October 31, 1998. Pricing under the contract is based on both a demand
and commodity component. The contract requires Hope to pay Eastern American a
demand component of $51,589 per month and a commodity component that is $2.00
per Mmbtu through October 31, 1998. For fiscal year 1998, the gas sold pursuant
to this contract accounted for 1.3% of the Company's consolidated revenues and
7.8% of the total gas production volumes operated by the Company.
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, the Company's subsidiary,
Eastern Marketing Corporation ("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 $2.57 per Mcf in calendar year 1997 and is $2.84 per Mcf in
calendar year 1998. The fixed price component was $3.23 in calendar year 1997
and is $3.39 in calendar year 1998. 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.
Eastern American and Eastern Marketing have been parties to a gas contract
with Mountaineer since September 1995. This contract will expire by its terms
on November 1, 1998. The contract provides for a gas demand charge of $0.08 per
Mmbtu up to the daily contract demand volume of 28,000 Mmbtu per day. The
contract commodity price paid by Mountaineer was $2.10 per Mmbtu for the period
October 1, 1996 through September 30, 1997 and $2.00 per Mmbtu for the period
October 1, 1997 through June 30, 1998. During fiscal year 1998, approximately
9.8 Bcf of natural gas was sold pursuant to this contract.
In March 1998, Eastern American entered into a Termination Agreement with
Seneca Power Partners, L. P. ("Seneca") which provided for the termination of a
long-term gas sales contract between Eastern American and Seneca effective June
30, 1998. Prior to such termination, Eastern American was obligated to deliver
up to 12,000 mcf of natural gas per day to Seneca's cogeneration facility
located in Batavia, New York. The Termination 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 which was precipitated by the New York State Regulatory Agency's
refusal to allow Niagara to increase its rates to satisfy rising costs under its
existing Power Purchase Agreements. Pursuant to the Termination Agreement,
Eastern American received cash consideration of approximately $22 million on
June 30, 1998. Additionally, as owner of a 10% limited partnership interest in
Seneca, Eastern American also received a partnership distribution, which
consisted of (i) cash in the amount of $5,943,085 and (ii) 187,035 shares of
common stock of Niagara, which at the time of distribution had a market value of
$2,793,835. For a further discussion, see Note 17 to the Consolidated Financial
Statements below.
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, 1998, the Company had approximately 700 full-time employees.
Approximately 280 employees are covered by six separate collective bargaining
agreements. Negotiation of three of these agreements was completed during
fiscal 1998. 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.
Item 4. Submission of Matters to a Vote of Security Holders
- ------- ---------------------------------------------------
No matters were submitted to a vote of security holders during the 1998
fiscal year.
PART II
Item 5. Market for Registrant's Common Stock and Related Stockholder Matters
- ------- --------------------------------------------------------------------
The Company's common stock is not traded in a public market. As of
September 1, 1998, the Company had 28 record holders of its common stock.
The Company declared dividends in fiscal years 1998, 1997 and 1996 of
$1,131,000, $1,007,000, and $1,457,000 respectively.
Item 6. Selected Financial Data
-------- -------------------------
YEAR ENDED JUNE 30
1998 1997 1996 1995 1994
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE ITEMS)
Operating revenue $364,336 $373,941 $375,794 $145,494 $ 95,789
Income(loss) from continuing operations $ 3,014 $ 2,018 $ 7,820 $ 1,185 $ (1,360)
Income(loss) from continuing operations $ 4.53 $ 2.93 $ 11.15 $ 1.67 $ (1.93)
-per common share basic
-assuming dilution
Total assets $439,945 $434,757 $461,504 $471,497 $222,491
Long term debt $261,507 $260,089 $254,647 $267,647 $112,430
Dividends declared per common share $ 1.70 $ 1.50 $ 2.10 $ 0.65 $ 0.78
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 thereto (including the segment information contained
therein) and the Selected Financial Data in 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.
Important factors that could cause actual results to differ materially from
the forward-looking statements include, but are not limited to, 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, 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.
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 11.4% 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 $17.4 million from
$152.7 million during the period ended June 30, 1997 to $135.3 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 4.0% decrease in gas marketing and pipeline
costs, a 14.0% decline in the field and lease operating expenses and an 18.4%
decline in impairment and exploratory expenses.
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 $5.8 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 $2.9 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 3.6% 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
Eatern Systems Corporation ("ESC") and Eastern American of $35 million and $136
million, respectively.
Comparison of Results of Operations for the Fiscal Years Ended June 30, 1997 and
1996.
NET INCOME. The Company's net income decreased from $7.8 million to a loss
of $5.8 million for the years ended June 30, 1996 and 1997, respectively. The
change is primarily attributable to a $1.9 million decrease in revenue, and an
extraordinary loss of $7.9 million (net of a $4.2 million tax benefit) partially
offset by a $5.1 million increase in gain on the sale of properties primarily
due to the sale of WOPLP.
REVENUES. Revenues from operations decreased 0.5%, from $375.8 million to
$373.9 million for the years ended June 30, 1996 and 1997, respectively. The
decrease is due to a 5.2% decrease in utility sales and transportation partially
offset by a 4.3% increase in oil and gas sales and a 4.3% increase in gas
marketing sales.
The utility's sales decreased 5.2% primarily as result of a decrease in the
weighted average number of Degree Days during the most recent year.
Gas marketing and pipeline revenues increased $6.3 million from $146.4
million to $152.7 million for the respective years. Gas marketing and pipeline
sales volumes (exclusive of gas gathering and gas processing volumes) increased
approximately 9% while the average sales price increased approximately 9% per
Mcf.
COSTS AND EXPENSES. The Company's costs and expenses increased 3.2% from
$343.8 million to $354.9 million from year to year, primarily as a result of a
5.9% increase in utility gas purchased, a 4.3% increase in gas marketing
purchase costs and a 49.8% increase in impairment and exploratory costs
resulting from increased exploration activity. The increases were partially
offset by a 10.6% decrease in utility operations and maintenance.
The utility's purchased gas costs increased $5.6 million over the prior
year. This increase was primarily the result of reduced rate refunds received
from the utility's pipeline suppliers in fiscal year 1997 compared to fiscal
year 1996. This increase was partially offset by reduced volumes purchased due
to lower sales volumes caused by a decrease in the weighted average Degree Days
in fiscal year 1997 and by a full year of amortization of previously
overrecovered gas costs in fiscal year 1997 compared to eight months in fiscal
year 1996. See Note 18 to the Consolidated Financial Statements.
Gas marketing and pipeline purchase costs increased $5.9 million from
$138.1 million to $144.0 million for the respective years. Gas marketing and
pipeline purchase volumes increased due to the increase in gas marketing and
pipeline sales, previously discussed.
Operations and maintenance costs were 10.6% lower than the prior year.
These costs declined in fiscal year 1997 due primarily to a one time charge of
$1.3 million recorded in fiscal year 1996 resulting from the relocation of a
customer service and reduced labor and benefit costs.
Exploration and impairment costs increased 49.8% to $10.1 million due to
increased charges related to geological and geophysical costs and activities for
the most recent year.
Field and lease operating expenses, production and other taxes, general and
administrative costs, and depreciation, depletion and amortization expenses were
comparable between the two years.
INTEREST EXPENSE. Interest expense was comparable between the two years.
This is primarily due to similar outstanding debt levels, including the current
and long-term portions.
OTHER (INCOME) EXPENSE. Other income and expense included a $3.2 million
gain on sale of oil and gas properties in 1996 and an $8.3 million gain on sale
of oil and gas properties in fiscal year 1997, including the WOPLP sale
discussed previously.
PROVISION FOR INCOME TAXES. The provision for income taxes decreased $1.3
million as a result of decreased book pre-tax income levels.
Liquidity and Capital Resources
Working capital at June 30, 1998 was a negative $15.3 million and the ratio
of current assets to current liabilities was .84 to 1 as compared to June 30,
1997 when working capital was $0.5 million and the current ratio was 1 to 1.
The decrease in working capital of $15.8 million was principally due to a $5.0
million decrease in accounts receivable, a $7.8 million increase in accounts
payable, a $3.5 million increase in short-term debt and an increase in all other
current liabilities of $2.1 million. This was partially offset by an increase
in all other current assets of $2.7 million. The decrease in accounts
receivable is due to lower revenues associated with the Company's utility
operations. The increase in accounts payable is associated with a $5.3 million
increase at the Company's utility operation and a $3.2 million increase in the
Company's oil and gas operations. The $3.4 million increase in short-term debt
is associated with the Company's utility operation partially to fund its
operational needs, capital expenditures, and acquisitions.
Cash provided by operating activities for fiscal 1998 was $6.7 million
exclusive of the $30.0 million (net) proceeds from the Contract Settlement as
discussed in Note 17 of the Consolidated Financial Statements. Cash provided by
operating activities represents a major source of cash of the Company. During
fiscal 1997 and 1996, net cash provided by operating activities was $9.5 and
$17.1 million, respectively.
Net cash used in investing activities in fiscal 1998, 1997 and 1996 was
$38.7, $15.5 and $23.9 million, respectively. This use was primarily for oil
and gas properties ($21.4, $17.9 and $25.9 million) and utility assets ($13.5,
$10.3 and $12.6 million). Proceeds from sale of assets totaled $0.6, $12.4 and
$17.4 million, respectively for such years and represents, from time-to-time, a
major source of cash for the Company.
During fiscal 1998, 1997, and 1996 cash provided by financing activities
was $2.4, $12.7 and $(0.2) million, respectively. Net proceeds from borrowing
(including short and long-term) totaled $4.5, $22.5 and $5.4 million for the
fiscal year 1998, 1997 and 1996, respectively, constitute major sources of cash
for the Company and together with cash provided by operations were used to fund
operations, acquire assets, conduct exploration and development activities, make
acquisitions and pay dividends.
The Company and certain operating subsidiaries of the Company have (i) a
$50 million secured, revolving credit facility under which no amounts were
outstanding at June 30, 1998 and (ii) $74 million in unsecured, revolving bank
lines of credit, under which approximately $19.2 million was drawn at June 30,
1998.
The Company believes that its cash balances together with cash flows from
operations and its borrowing capacity will be sufficient to meet its working
capital needs for the foreseeable future.
Factors Affecting Future Operating Results
Net cash provided by operating activities is primarily affected by oil and
gas prices, seasonality, heating Degree Days, marketing margins and the
Company's success in drilling activities.
Prior to October 1995, the Company's utility operation was subject to
traditional regulatory rate making procedures. Effective November 1995, the
WVPSC issued an order implementing a three-year rate moratorium (the
"Moratorium") wherein the utility's customers' rates were fixed for a three year
period and its purchased gas adjustment procedures were suspended. As a result
of the moratorium, the utility assumes the risk and benefits of fixed customer
rates, the risk of increases in the cost of gas purchased and interstate and
intrastate pipeline transportation rates, and the risks and benefits of
achieving other operational efficiencies. In July 1998, an additional
Moratorium was entered into for a three-year period through October 31, 2001.
Additionally, the WVPSC increased customer rates. The Moratorium also requires
the utility to make minimum capital expenditures of $9.0 million per year during
the Moratorium period.
The Company's utility operation has entered into a letter of intent with a
major energy management firm. In accordance with the letter of intent, the
utility will purchase a significant portion of its gas supply at a fixed unit
price from the energy management firm. The term of this arrangement is
contemplated to extend from November 1, 1998 to October 31, 2001 and
contemplates, in addition to the fixed unit price, other provisions related to
the utility's gas supply management including capacity storage and
transportation obligations.
WELL DRILLING ACTIVITIES AND ACQUISITIONS. The Company drilled 36 gross
(24.5 net) development wells and 14 gross (4.3 net) exploratory wells during the
year ended June 30, 1998. Of these, 36 gross (23.4 net) wells are considered
successful. During the same period, the Company drilled 14 gross (5.4 net) dry
holes, of which 10 gross (3.4 net) were exploratory.
On November 1, 1997, the Company acquired a data conversion and software
development company for approximately $1.4 million that was funded with existing
cash.
In March 1998, the Company acquired a 63 mile natural gas gathering and
pipeline system for $1.3 million. The acquisition cost was funded with existing
cash and a long-term note of $0.9 million.
YEAR 2000 COMPLIANCE. The Company 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.
These steps include the purchase and implementation of an integrated
application software package, which is expected to cost approximately $4.7
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 by mid
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 plans to initiate 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,
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. Based upon
current information, management believes that the costs incurred to ensure
compliance with Year 2000 issues, or potential operating disruptions, will not
have a material adverse effect on the Company's financial condition, results of
operations or liquidity.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
--------- ----------------------------------------------------------------
The Company is generally exposed to commodity price and interest rate
risks. 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 roll-over risk for borrowings as they mature
and are renewed at current market rates. The extent of this risk is not
quantifiable or predictable because of the variability of future interest rates
and the Company's future financing needs.
The following summarizes the Company's existing long-term debt outstanding
at June 30,1998 (in thousands):
Senior Subordinated Notes bearing interest at
9.5% payable semi-annually with principal due
in 2007 $200,000
Unsecured Senior Notes bearing interest at
7.59% payable semi-annually with principal
amortization beginning in 2002 60,000
Installment Notes bearing interest at 6.2% to 8%
requiring monthly amortization of principal plus
interest 2,088
--------
Total $262,088
========
Fair Value $267,000
========
The Company has not attempted to hedge the interest rate risk associated
with its debt. The fair value of this debt results from a decline
in market rates since these financing arrangements were established. The
following is a summary of cash flows relative to long-term debt for the next
five years and thereafter (in thousands) and assumes no prepayments:
Principal Interest Total
--------- -------- -------
1999 $ 581 $ 24,704 $ 25,285
2000 594 24,668 25,262
2001 338 24,632 24,970
2002 3,446 23,525 26,971
2003 3,446 23,257 26,703
Thereafter 253,683 102,400 356,083
---------- --------- --------
Total $ 262,088 $ 223,186 $485,274
========== ========= ========
The Company's short term debt is variable rate and approximated 6% on average
balances of $26.2 million in fiscal year 1998. Anticipated short term interest
rate volatility should not have a material impact on cash flows of the Company.
The Company's operations as described in detail in Item 1 "Business"
consists primarily of exploring for, 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 has only occasionally used derivative instruments to
hedge its commodity price risk and then only to a very limited degree.
Notwithstanding the above, the Company's future cash flows from gas and oil
production are exposed to significant volatility as commodity prices change.
Mountaineer has entered into a new rate moratorium with the WVPSC through
2001 thereby exposing itself to the volatility of gas supply costs. Its future
cash flows could vary significantly from historical cash flows. Mountaineer has
attempted to minimize this risk by entering into a letter of intent with a major
energy management firm to supply a majority of its necessary gas supply at a
fixed price. Similar to the discussion above, but having the opposite effect,
this agreement limits Mountaineer's benefit of declining natural gas prices.
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, 1998 and 1997, and the
related consolidated statements of operations, stockholders' equity, and cash
flows for each of the three years in the period ended June 30, 1998. 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, 1998 and 1997, and the results of their operations
and their cash flows for each of the three years in the period ended June 30,
1998 in conformity with generally accepted accounting principles. Also, in our
opinion, such financial statement schedules, when considered in relation to the
basic consolidated financial statements taken as a whole, present fairly in all
material respects the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Denver,Colorado
September 18, 1998
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
JUNE 30, 1998 AND 1997
(Amounts in Thousands)
- ------------------------------------------------------------------------------
ASSETS 1998 1997
CURRENT ASSETS:
Cash and cash equivalents $ 21,547 $ 20,814
--------- ---------
Accounts receivable:
Utility gas and transportation 13,027 19,168
Gas marketing and pipeline 5,528 5,705
Oil and gas sales 7,595 7,511
Other 7,959 7,133
--------- ---------
34,109 39,517
Less allowance for doubtful accounts (1,281) (1,660)
--------- ---------
32,827 37,857
Gas in storage, at average cost 13,249 12,641
Income taxes receivable 4,310 1,392
Deferred income tax asset 3,307
Prepaid and other current assets 5,839 4,114
--------- ---------
Total current assets 77,773 80,125
--------- ---------
NET PROPERTY, PLANT AND EQUIPMENT (Note 2) 318,547 308,864
--------- ---------
OTHER ASSETS:
Deferred financing costs, less accumulated
amortization of $1,046 and $452, respectively 9,545 9,956
Notes receivable, less allowance for doubtful accounts
of $400 in 1998 4,402 5,875
Notes receivable - related party 1,216 1,428
Deferred utility charges 18,233 18,259
Other 10,229 10,250
--------- ---------
Total other assets 43,625 45,768
--------- ---------
TOTAL $439,945 $434,757
========= =========
See notes to consolidated financial statements. (Continued)
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
JUNE 30, 1998 AND 1997
(Amounts in Thousands)
- -------------------------------------------------------------------------------
LIABILITIES AND STOCKHOLDERS' EQUITY 1998 1997
CURRENT LIABILITIES:
Accounts payable and accrued expenses $ 38,883 $ 31,037
Current portion of long-term debt 581 55
Short-term debt 19,174 15,724
Funds held for future distribution 5,716 6,015
Accrued taxes, other than income 8,472 7,781
Overrecovered gas costs 6,485 9,650
Deferred income tax liability 5,643
Other current liabilities 8,115 9,401
--------- ---------
Total current liabilities 93,069 79,663
LONG-TERM OBLIGATIONS
Long-term debt 261,507 260,089
Gas delivery obligation and deferred trust revenue 16,127 18,580
Deferred income tax liability 24,552 32,018
Other long-term obligations 12,837 14,000
--------- ---------
Total liabilities 408,092 404,350
--------- ---------
COMMITMENTS AND CONTINGENCIES (Note 15)
MINORITY INTEREST 1,883 1,809
--------- ---------
STOCKHOLDERS' EQUITY:
Common stock, par value $1.00; 2,000 shares authorized;
720 and 714 shares issued in 1998 and 1997, 720 714
respectively
Additional paid-in capital 4,510 4,221
Retained earnings 29,132 27,249
Treasury stock and notes receivable arising from
issuance of common stock (4,082) (3,435)
Cumulative foreign currency translation adjustment (310) (151)
--------- ---------
Stockholders' equity - net 29,970 28,598
--------- ---------
TOTAL $439,945 $434,757
========= =========
See notes to consolidated financial statements. (Concluded)
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED JUNE 30, 1998, 1997 AND 1996
(Amounts in Thousands, Except Per Share Data)
- ----------------------------------------------------------------------------------------------------
1998 1997 1996
REVENUES:
Utility gas sales and transportation $156,579 $173,463 $182,929
Gas marketing and pipeline sales 135,348 152,720 146,398
Oil and gas sales 24,689 33,301 31,940
Well operations and service revenues 15,536 14,151 14,003
Contract settlement and other 32,184 306 524
-------- --------- ---------
364,336 373,941 375,794
-------- --------- ---------
COSTS AND EXPENSES:
Utility gas purchased 85,166 100,774 95,157
Gas marketing and pipeline cost of sales 138,211 144,006 138,067
Field operating expenses 17,945 20,874 21,796
Utility operations and maintenance 22,084 21,320 23,841
General and administrative 23,330 22,640 23,247
Taxes, other than income 14,881 16,094 16,165
Depletion and depreciation of oil and gas properties 8,021 8,756 9,204
Depreciation of pipelines, other property and equipment 12,017 10,289 9,613
Exploration and impairment 8,262 10,121 6,756
-------- --------- ---------
329,917 354,874 343,846
-------- --------- ---------
Income from operations 34,419 19,067 31,948
-------- --------- ---------
OTHER (INCOME) AND EXPENSE:
Interest 26,386 23,881 23,782
Loss (gain) on sale of assets 1,208 (8,303) (3,214)
Other 1,551 (647) 93
-------- --------- ---------
29,145 14,931 20,661
-------- --------- ---------
Income before income taxes, minority interest and extraordinary loss 5,274 4,136 11,287
Provision for income taxes 2,017 1,966 3,274
-------- --------- ---------
Income before minority interest and extraordinary loss 3,257 2,170 8,013
Minority interest 243 152 193
-------- --------- ---------
Income before extraordinary loss 3,014 2,018 7,820
Extraordinary loss on early extinguishment of debt (net of income
tax benefit of $4,233) - 7,861 -
-------- --------- ---------
NET INCOME (LOSS) $ 3,014 $ (5,843) $ 7,820
======== ========= =========
Earnings per common share, basic
Income before extraordinary loss $ 4.53 $ 2.93 $ 11.17
Extraordinary loss - (11.42) -
-------- --------- ---------
Net income (loss) 4.53 (8.49) 11.17
======== ========= =========
Earnings per common share, assuming dilution
Income before extraordinary loss $ 4.53 $ 2.93 $ 11.15
Extraordinary loss - (11.40) -
-------- --------- ---------
Net income (loss) 4.53 (8.47) 11.15
======== ========= =========
See notes to consolidated financial statements.
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED JUNE 30, 1998, 1997 AND 1996
(Amounts in Thousands, Except Per Share Data)
- --------------------------------------------------------------------------------------------------------
Additional
Common Paid-In Retained Treasury
Stock Capital Earnings Stock
Balance, June 30, 1995 $ 708 $ 3,961 $ 27,736 $ (489)
Net income 7,820
Dividends ($2.10 per share) (1,457)
Exercise of employee stock options 3 125
Purchase of treasury stock (632)
Reduction of notes receivable
Adjustment for foreign currency translation - - - -
------------ -------- --------- ----------
Balance, June 30, 1996 711 4,086 34,099 (1,121)
Net loss (5,843)
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
Adjustment for foreign currency translation - - - -
------------ -------- --------- ----------
Balance, June 30, 1997 714 4,221 27,249 (3,175)
Net income 3,014
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
Adjustment for foreign currency translation - - - -
------------ -------- --------- ----------
Balance, June 30, 1998 $ 720 $ 4,510 $ 29,132 $ (3,698)
============ ======== ========= ==========
See notes to consolidated financial statements (Continued)
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED JUNE 30, 1998, 1997 AND 1996
(Amounts in Thousands, Except Per Share Data)
- ----------------------------------------------------------------------------------------------------------
Notes Cumulative
Received from Foreign
Issuance of Currency Stockholders'
Common Stock Translation Equity
Balance, June 30, 1995 $ (303) $ - $ 31,613
Net income 7,820
Dividends ($2.10 per share) (1,457)
Exercise of employee stock options 128
Purchase of treasury stock (632)
Reduction of notes receivable 53 53
Adjustment for foreign currency translation - 25 25
--------------- ------------- ---------------
Balance, June 30, 1996 (250) 25 37,550
Net loss (5,843)
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
Adjustment for foreign currency translation - (176) (176)
--------------- ------------- ---------------
Balance, June 30, 1997 (260) (151) 28,598
Net income 3,014
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
Adjustment for foreign currency translation - (159) (159)
--------------- ------------- ---------------
Balance, June 30, 1998 $ (384) $ (310) $ 29,970
=============== ============= ===============
See notes to consolidated financial statements. (Concluded)
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED JUNE 30, 1998, 1997 AND 1996
(Amounts in Thousands)
- -------------------------------------------------------------------------------------------------------
1998 1997 1996
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ 3,014 $ (5,843) $ 7,820
Adjustments to reconcile net income (loss) to net cash provided by
Operating activities:
Minority interest 243 152 193
Depletion, depreciation and amortization 20,825 19,955 19,471
Write-off of deferred financing costs 4,363
Loss (gain) on sale of assets 1,208 (8,304) (3,934)
Deferred income taxes 1,482 (2,534) 1,518
Exploration and impairment 8,262 10,121 6,756
Provision for losses on accounts receivable 2,572 2,102 1,800
Other, net (3,539) (2,319) (2,447)
--------- ---------- ----------
34,067 17,693 31,177
Changes in assets and liabilities:
Accounts receivable 2,631 1,407 (17,288)
Gas in storage (608) (353) 3,154
Income taxes receivable (2,918) 1,850 1,723
Prepaid and other assets (1,725) (3,014) 6,155
Accounts payable and other current liabilities 7,846 (5,905) 4,081
Funds held for future distribution (299) 823 (1,946)
Overrecovered gas costs (3,165) (2,128) (8,741)
Other 897 (849) (1,221)
--------- ---------- ----------
Net cash provided by operating activities 36,726 9,524 17,094
--------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment (38,693) (26,376) (39,445)
Proceeds from sale of oil and gas properties 568 1,114 17,426
Proceeds from sale of limited partnership interest 11,250
Notes receivable and other (238) (1,556) (804)
--------- ---------- ----------
Net cash used in investing activities (38,363) (15,568) (22,823)
--------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt 1,298 271,000 250,998
Principal payments on long-term debt (296) (255,854) (218,352)
Short-term borrowings, net 3,450 7,332 (27,203)
Purchase of treasury stock (523) (2,054) (632)
Dividends (834) (1,007) (1,199)
Other equity transactions (124) 299 109
Deferred financing costs (601) (7,055) (3,919)
--------- ---------- ----------
Net cash provided by (used in) financing activities 2,370 12,661 (198)
--------- ---------- ----------
Net increase (decrease) in cash and cash equivalents 733 6,617 (5,927)
Cash and cash equivalents, beginning of year 20,814 14,197 20,124
--------- ---------- ----------
CASH AND CASH EQUIVALENTS, END OF YEAR $ 21,547 $ 20,814 $ 14,197
========= ========== ==========
See notes to consolidated financial statements.
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED JUNE 30, 1998, 1997 AND 1996
1. NATURE OF ORGANIZATION
Energy Corporation of America (the "Company") was formed in June 1993 through an
exchange of shares with the common stockholders of Eastern American Energy
Corporation ("Eastern"). The Company is an independent integrated energy
company that, through its subsidiaries, is primarily engaged in operating a
natural gas distribution system in West Virginia and oil and gas operations in
West Virginia and Pennsylvania. The Company also is engaged in the exploration
and production of oil and natural gas in other parts of the United States,
primarily in the Rocky Mountains, and New Zealand. All references to the
"Company" include Energy Corporation of America and its consolidated
subsidiaries.
Natural Gas Distribution System - The Company operates, through its wholly owned
subsidiary Mountaineer Gas Company ("Mountaineer"), a natural gas distribution
system in West Virginia. Mountaineer provides natural gas sales, transportation
and distribution service to residential, commercial, industrial and wholesale
customers. As a public utility, Mountaineer is subject to regulation by the
West Virginia Public Service Commission ("WVPSC").
Oil and Gas Exploration, Development, Production and Marketing - The Company,
primarily through its subsidiary Eastern, is engaged in exploration, development
and production, transportation and marketing of natural gas primarily within the
Appalachian Basin in West Virginia, Pennsylvania and Ohio. The Company owns all
of the voting common shares of Eastern, while certain officers and stockholders
of the Company ("minority interest") own non-voting Class A common shares,
representing less than two percent of Eastern common shares.
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 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 and Mountaineer.
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).
Cash and Cash Equivalents - Cash and cash equivalents include short-term
investments maturing in three months or less from the date acquired.
Property, Plant and Equipment - Oil and gas properties are accounted for using
the successful efforts method of accounting. Under this method, certain
expenditures such as exploratory geological and geophysical costs, exploratory
dry hole costs, delay rentals and other costs related to exploration are
recognized currently as expenses. All direct and certain indirect costs
relating to property acquisition, successful exploratory wells, development
costs, and support equipment and facilities are capitalized. The Company
computes depletion, depreciation and amortization of capitalized oil and gas
property costs on the units-of-production method using proved developed
reserves. Direct production costs, production overhead and other costs are
charged against income as incurred. Gains and losses on the sale of oil and gas
property interests are generally included in operations.
The provision for depreciation of Mountaineer's utility plant is based on a
composite straight-line method. The average composite depreciation rate was
3.73% and 3.77% for 1998 and 1997, respectively. Mountaineer's property, plant
and equipment includes capitalized overhead for payroll related costs and
administrative and general expenses, as well as an allowance for funds used
during construction ("AFUDC") of approximately $37,000 and $61,500 for the years
ended June 30, 1998 and 1997. AFUDC is an accounting procedure that capitalizes
the cost of funds used to finance utility construction projects as part of
utility plant on the balance sheet and credits the cost as a non-cash item on
the income statement. During the years ended June 30, 1998 and 1997 this amount
related only to debt financing in accordance with WVPSC policies.
Other property, equipment, pipelines and buildings are stated at cost and are
depreciated using straight-line and accelerated methods over estimated useful
lives ranging from three to 30 years.
Repairs and maintenance costs are charged against income as incurred;
significant renewals and betterments are capitalized. Gains or losses related
to retirement of utility property, net of any salvage and cost of removal are
credited or charged to accumulated depreciation. Gains and losses on
dispositions of other property, equipment, pipelines and buildings are included
in operations.
At June 30 property, plant and equipment consisted of the following (in
thousands):
1998 1997
---- ----
Oil and gas properties $ 210,650 $200,368
Utility plant 170,721 160,545
Other property and equipment 23,743 19,328
Pipelines 18,783 17,069
---------- ---------
423,897 397,310
Less accumulated depletion, depreciation and amortization (105,350) (88,446)
---------- ---------
Net property, plant and equipment $ 318,547 $308,864
========== =========
Long-Lived Assets - In March 1995, Statement of Financial Accounting Standards
("SFAS") No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of," was issued. The standard requires all
companies to assess long-lived assets and assets to be disposed of for
impairment and requires rate-regulated companies to write-off regulatory assets
to earnings whenever those assets no longer meet the criteria for recognition of
a regulatory asset as defined by SFAS No. 7l, "Accounting for the Effects of
Certain Types of Regulation." For the years ended June 30, 1998 and 1997, the
Company determined that no impairment loss needed to be recognized for
applicable assets.
Gas in Storage - Gas in storage is stated at the lower of average cost or market
value.
Deferred Financing Costs - Certain legal, underwriting fees and other direct
expenses associated with the issuance of credit agreements, lines of credit and
other financing transactions have been capitalized. These financing costs are
being amortized over the term of the related credit agreement.
Foreign Currency Translation - The translation of applicable foreign currencies
into U.S. dollars is performed for balance sheet accounts using current exchange
rates in effect at the balance sheet date and for revenue and expense accounts
using an average exchange rate during the period. The cumulative translation
adjustment is included in 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 each of the years ended June 30, 1998
and 1997, purchased gas costs included $4 million 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 - In October 1995, SFAS No. 123, "Accounting for Stock-Based
Compensation," was issued. As permitted under SFAS No. 123, the Company has
elected to continue to measure compensation costs for stock-based employee
compensation plans as prescribed by Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees."
Hedging Activities - The Company periodically hedges a portion of its oil and
gas production through swap agreements. The purpose of the hedges is to provide
a measure of stability in the volatile environment of oil and gas prices. The
Company recognizes gains and losses in the swap agreements at the time the
hedged volumes are sold.
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.
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.
The risk of significant nonpayment by the utility customers is considered
minimal.
Environmental Concerns - The Company is continually taking actions it believes
necessary in its operations to ensure conformity with applicable federal, state
and local environmental regulations. As of June 30, 1998, 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 - In June 1997, SFAS No. 130, "Reporting
Comprehensive Income" was issued, which requires businesses to disclose
comprehensive income and its components in their general-purpose financial
statements, with reclassification of comparative (earlier period) financial
statements. The Company does not believe that SFAS No. 130 will have a
significant impact on its financial statements.
In June 1997, SFAS No. 131, "Disclosures about Segments of an Enterprise and
Related Information" was issued and made effective for periods beginning after
December 15, 1997. SFAS 131 redefines how operating segments are determined and
requires disclosure of certain financial and descriptive information about a
company's operating segments. These standards increase disclosure in the
financial statements and will have no significant impact on the Company's
financial position or results of operations.
In June 1998, SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities" was issued, which is effective for all fiscal years beginning after
June 15, 1999. SFAS No. 133 establishes accounting and reporting standards for
derivative instruments and hedging activities. The Company estimates there will
be no significant impact to the financial statements as derivative and hedging
activities are minimal.
Supplemental Disclosures of Cash Flow Information - Supplemental cash flow
information for the years ended June 30 is as follows (in thousands):
1998 1997 1996
---- ---- ----
Cash paid (received) for:
Interest (net of capitalized interest of $37, $323
and $630 in 1998, 1997 and 1996, respectively) $25,025 $19,921 $15,207
Income taxes, net 3,004 (1,142) 2,440
Noncash investing and financing activities:
Dividends declared and unpaid at year end 316 258
Seller financed acquisition 943
3. DISPOSITIONS
Eastern Producing Limited Partnership - In November 1995, the Company sold
interests in certain producing natural gas properties for total cash
consideration of $17,360,000 realizing a gain on sale of $3,269,000. The
Company contributed its remaining interest in these properties in exchange for a
general partner interest in the partnership that acquired the properties,
representing a 1% interest until "payout" (as defined), at which time the
Company's interest increases to 49%.
Westside Operating Partnerships LP - In March 1997, the Company exchanged
warrants held representing a 30% ownership interest of a third party for a 30%
interest in a newly formed oil and gas limited liability company, 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 $11,250,000 plus a $1,500,000 variable rate note with certain conversion
options and distributing certain WOPLP oil and gas properties and real estate to
the Company. The Company recognized a gain of $7,800,000 in fiscal 1997on the
transaction and its remaining interest in BEC, $0 and $296,000, is included in
other long-term assets at June 30, 1998 and 1997.
4. RISK MANAGEMENT
Fixed Price Gas Purchase Contracts - Mountaineer has entered into fixed price
contracts to purchase gas in the future for the purpose of mitigating its
commodity price risk. At June 30, 1998, there were a total of 20 such contracts
extending through September 1998, to purchase, in the aggregate, 3.1 Bcf of gas
for an aggregate purchase price of $6,632,000.
Gas Supply Management Agreement - Subsequent to June 30, 1998, Mountaineer
signed a letter of intent with a major energy management firm, whereby
Mountaineer will purchase a significant portion of its citygate natural gas
system supply volumes for the period November 1, 1998 through October 31, 2001
at a fixed price. In addition to the fixed unit price, the letter of intent
contemplates other provisions relating to the utility's gas supply management
including capacity storage and transportation obligations.
Natural Gas Hedges - In fiscal 1997, the Company entered into certain natural
gas swaps to reduce its exposure to fluctuations in the price of natural gas.
These instruments involve, generally, elements of market and credit risk in
excess of the amount recognized in the consolidated balance sheets. As of June
30, 1998, the Company still had one swap outstanding totaling a notional
quantity of approximately 2.7 Mmbtu per day through October 31, 1998. At June
30, 1998, the market value of this swap is approximately zero. As of June 30,
1997, the Company had two natural gas swap agreements totaling a notional
quantity of approximately 16.7 Mmbtu per day through October 31, 1997, in
addition to the swap mentioned above. At June 30, 1997, the market value of
these swaps was estimated to be a loss of $46,000, the net amount the Company
would have paid to terminate the agreements. For the years ended June 30, 1998,
1997 and 1996 the Company recognized a net gain (loss) on its oil and natural
gas hedging activities of ($47,000), $265,000, and ($388,000), respectively.
5. DEBT
Long-Term Debt - At June 30 long-term debt consisted of the following (in
thousands):
1998 1997
---- ----
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
Installment notes payable, collateralized by deeds of trust,
at interest rates ranging from 6.2% to 8%, respectively 2,088 144
--------- ---------
262,088 260,144
Less current portion (581) (55)
--------- ---------
$261,507 $260,089
========= =========
The Company's various debt agreements contain certain restrictions and
conditions among which are limitations on indebtedness, funding of certain
subsidiaries, dividends and investments, and certain tangible net worth and debt
and interest coverage ratio requirements. The agreements require the Company to
maintain certain financial conditions, including a minimum net worth,
restriction on funded debt and restrictions on the amount of dividends which can
be declared. As of June 30, 1998, Mountaineer had approximately $12.6 million
available for declaration of dividends under the debt covenants.
The scheduled maturities of the Company's long-term debt at June 30, 1998 for
each of the next five years and thereafter are as follows (in thousands):
June 30,
1999 $ 581
2000 594
2001 338
2002 3,446
2003 3,446
Thereafter 253,683
--------
$262,088
========
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 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 $74
million and $71 million as of June 30, 1998 and 1997, respectively. During the
years ended June 30, 1998 and 1997, the maximum outstanding balance was
$44,871,100 and $45,064,000, respectively, and the average daily balance was
$26,223,800 and $28,499,800, respectively. The weighted average interest rate
was 6.02% and 6.0% on the balance outstanding during the years ended June 30,
1998 and 1997, respectively.
Other Credit Facilities - The Company has a $50 million revolving credit
facility secured by certain properties, interest and contracts. The interest
rate is variable based on Eurodollars or other defined basis. The annual
commitment fee is .25%. As of June 30, 1998 and 1997, no borrowings were
outstanding under this facility. Eastern had a $6 million and $9 million letter
of credit, as of June 30, 1998 and 1997, respectively, issued by a bank in
support of Eastern'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, 1998 and 1997,
no amounts had been drawn under the letter of credit. The letter of credit
agreement between Eastern and the bank requires Eastern to maintain certain
financial covenants, including a minimum net worth and interest coverage ratio.
Eastern also has an unsecured revolving line of credit totaling $2 million. As
of June 30, 1998 and 1997, no amounts were outstanding under the line of credit.
Seller Financed Note - The Company purchased a natural gas gathering system in
West Virginia for $1,219,500. The Company paid $277,000 in cash and issued a
note for $942,500 payable to the seller in 100 consecutive equal monthly
payments. As of June 30, 1998, the balance of the note was $914,200. Other
costs incurred and paid related to the acquisition were approximately $107,000.
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):
1998 1997 1996
------- -------- -------
Current:
Federal $ 586 $ 491 $1,278
State (51) (224) 478
------- -------- -------
Total current 535 267 1,756
------- -------- -------
Deferred:
Federal (155) (4,141) (159)
State 1,637 1,607 1,677
------- -------- -------
Total deferred 1,482 (2,534) 1,518
------- -------- -------
Total provision (benefit) for income taxes $2,017 $(2,267) $3,274
======= ======== =======
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):
1998 1997 1996
-------- -------- --------
Tax expense at the federal statutory rate $ 1,793 $(2,707) $ 4,448
State taxes, net of federal tax effects 358 (541) 806
Foreign losses 838 635 -
Section 29 tax credits (1,783) (1,866) (1,129)
Increase in valuation allowance on federal,
foreign and state deferred tax assets, net of federal benefit 571 1,805 1,161
Change in estimate (1,178)
Other, net 240 407 (834)
-------- -------- --------
Provision (benefit) for income taxes $ 2,017 $(2,267) $ 3,274
======== ======== ========
In 1995, the Company estimated that it would carry back its 1995 tax loss and
realize the tax benefit based on the alternative minimum tax rate. During 1996,
management decided to carry forward this loss, at regular tax rates, which
generated a $1.2 million tax benefit in 1996.
Components of the Company's federal and state deferred tax assets and
liabilities, as of June 30 are as follows (in thousands):
1998 1997
---- ----
Federal State Total Federal State Total
-------- ------ ------ -------- ------ ------
Deferred tax assets:
Overrecovered gas costs $ 2,209 $ 583 $ 3,281 $ 869
Bad debt allowance 641 169 597 158
Deferred compensation and profit sharing 1,155 304 1,939 513
Other postretirement benefit and pension
obligations 696 183 2,785 737
Tax credits and carryforwards 14,892 10,553 16,804 12,623
Other long-term obligations 860 228 1,412 374
Other 9,408 1,345 5,727 136
--------- --------- --------- ---------
Total deferred tax assets 29,861 13,365 32,545 15,410
--------- --------- --------- ---------
Deferred tax liabilities:
Property, plant and equipment (48,897) (13,263) (51,739) (13,043)
Federal income tax on state tax credits (3,588) (4,292) -
Other liabilities (1,976) (525) (1,885) (500)
--------- --------- --------- ---------
Total deferred tax liabilities (54,561) (13,788) (57,916) (13,543)
--------- --------- --------- ---------
Valuation allowance (1,252) (3,920) (635) (4,572)
--------- --------- --------- ---------
Net deferred income tax liability (25,852) (4,343) (26,006) (2,705)
--------- --------- --------- ---------
Current deferred tax asset (liability) (4,698) (945) $ (5,643) 2,615 692 $ 3,307
--------- --------- --------- --------- -------- ---------
Long-term deferred tax liability $(21,154) $ (3,398) $(24,552) $(28,621) $(3,397) $(32,018)
========= ========= ========= ========= ======== =========
At June 30, 1998, the Company has the following federal and state tax credits
and carryforwards (in thousands):
Year of
Tax Credits or Carryforwards Amount Expiration
AMT and Section 29 tax credits $ 12,067 None
Investment tax credits 1,143 1999-2001
Net operating loss carryforwards 1,682 2017
--------
Total federal credits $ 14,892
========
West Virginia tax credits $ 10,108 2002
West Virginia net operating loss carryforwards 445 2012
--------
Total state credits and carryforwards $ 10,553
========
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, 1998 and 1997 is a net
regulatory asset recorded by Mountaineer in accordance with state utility
ratemaking practices related to future amounts recoverable for income taxes of
$11.3 million and $11.6 million, respectively.
7. EMPLOYEE BENEFIT PLANS
The Company and certain operating subsidiaries, have a Profit Sharing/Incentive
Stock Plan (the "Plan") for the stated purpose of expanding and improving
profits and prosperity and to assist the Company in attracting and retaining key
personnel. The Plan is noncontributory, and its continuance from year to year
is at the discretion of the Board of Directors. The annual profit sharing pool
is based on calculations set forth in the Plan. One-half of the pool is
generally paid to eligible employees within 120 days of the end of the fiscal
year and one-half is deferred to the following year. Generally, to be eligible
to participate, an employee must have been continuously employed for two or more
years; however employees with less than two years of employment may participate
under certain circumstances. Additionally, Eastern participants may elect to
receive their profit sharing award in the form of nonvoting and nontransferable
nonvoting Class A common stock of Eastern, subject to the applicable terms and
conditions of the Plan document. The Company recognized $2.6 million, $1.1
million and $3.1 million of profit sharing expense during the years ended June
30, 1998, 1997, and 1996, 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 $153,600, $140,300 and $145,000 for
the years ended June 30, 1998, 1997 and 1996, 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.
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):
1998 1997
--------- ---------
Actuarial present value of benefit obligations:
Accumulated benefit obligation, including vested benefits of
$27,039 and $25,587 at June 30, 1998 and 1997, respectively $(29,259) $(27,456)
========= =========
Projected benefit obligations for service rendered to date $(33,110) $(29,777)
Pension Plan assets at fair value 27,052 24,954
--------- ---------
Projected benefit obligation in excess of plan assets (6,058) (4,823)
Unrecognized net gain (loss) from past experience 1,488 (77)
--------- ---------
Accrued pension cost $ (4,570) $ (4,900)
========= =========
Net periodic pension cost for the years ended June 30 as determined by an
independent actuary, included the following components (in thousands):
1998 1997
-------- --------
Service cost $ 717 $ 589
Interest cost 2,219 2,205
Actual return on plan assets (3,612) (3,241)
Net amortization and deferral 1,753 1,453
-------- --------
Net periodic pension cost 1,077 1,006
Amount capitalized as construction cost (242) (176)
-------- --------
Amount charged to expense $ 835 $ 830
======== ========
The assumptions used at the beginning of the fiscal year in accounting for
Mountaineer's Pension Plan at June 30 are as follows:
1998 1997
---- ----
Discount rate 7.75 7.75
Expected average increase in compensation 4.50 4.00
Expected long-term rate of return 8.00 8.00
9. POSTRETIREMENT MEDICAL AND LIFE INSURANCE BENEFITS
Mountaineer provides certain medical and life insurance benefits for retired
employees. Substantially all of Mountaineer's employees may become eligible for
these benefits if they choose to retire after reaching age 55 while working for
Mountaineer and are provided until age 65. Life insurance benefits of
approximately two times annual salary are provided while an employee is active
and working at Mountaineer. On the date of an employee's retirement and on the
date the employee reaches age 70, life insurance benefits decrease to
approximately 80% and 40% of annual salary, respectively. These benefits are
provided to retirees who meet the service requirements of 10 continuous years of
service prior to retirement at age 55 or 5 continuous years of service prior to
retirement at age 65. The plan is unfunded.
The following table sets forth the postretirement medical and life insurance
plans' funded status and amounts recognized in the consolidated balance sheets,
as determined by an independent actuary, as of June 30 (in thousands):
1998 1997
-------- --------
Accumulated postretirement benefit obligation:
Retirees $(4,034) $(3,788)
Fully eligible active participants (1,345) (1,571)
Other active employees (1,889) (1,634)
-------- --------
Total accumulated postretirement benefit obligation (7,268) (6,993)
Unrecognized actuarial gain (18) (243)
-------- --------
Accrued postretirement benefit liability (included in other
long-term obligations) $(7,286) $(7,236)
======== ========
Net periodic postretirement benefit cost for years ended June 30 as determined
by an independent actuary, included the following components (in thousands):
1998 1997
------ ------
Service cost-benefits attributable to service during the period $ 437 $ 376
Interest cost on the accumulated postretirement benefit obligation 515 499
------ ------
Net periodic postretirement benefit cost 952 875
Amount capitalized as construction cost (210) (203)
------ ------
Amount charged to expense $ 742 $ 672
====== ======
The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation was 9.0% and 9.5% in the years ended June 30,
1998 and 1997, declining gradually to 5.5% in 2005 and remaining at that level
thereafter. The health care cost trend rate assumption has a significant effect
on the amounts reported. A one percentage point increase in the assumed health
care cost trend rate would increase the aggregate service and interest cost by
$59,600 for the year ended June 30, 1998 and accumulated postretirement benefit
obligation as of June 30, 1998 by $290,900. The weighted average discount rate
used in determining the accumulated postretirement benefit obligation was 7.75%
and 7.75% for the years ended June 30, 1998 and 1997, respectively. The average
assumed annual rate of salary increase for the life insurance benefit plan was
4% in 1998 and 1997.
As part of a WVPSC rate order dated October 29, 1993, the WVPSC ruled that the
permitted rate recovery mechanism for other post retirement benefits would be a
modified accrual method. The modified accrual method allows for the recovery of
current service costs on an accrual basis and recovery of the transition
obligation on a cash basis.
10. COMMON STOCK
Voting Common Stock - In May 1995, the Company was reincorporated in the State
of West Virginia. As part of this reincorporation, each outstanding share of
then existing no-par value common stock was converted to one share of $1 par
value common stock.
The Company has an agreement with a stockholder covering the sale or disposition
of stock that provides the stockholder cannot sell stock without first offering
such shares to the Company. Under certain circumstances, the Company would be
required to purchase the related stock if not previously tendered to the Company
or otherwise sold or disposed of in accordance with the provisions of the
agreement.
Treasury Stock - The Company has 54,648 and 47,668 shares of treasury stock,
which are carried at cost, at June 30, 1998 and 1997, respectively. The Company
purchased 6,980 and 27,230 shares of common stock in the years ended June 30,
1998 and 1997, respectively.
Stock Options - In 1994, the Company created an incentive stock option plan (the
"Stock Option Plan"). Under the Stock Option Plan, options vested annually in
25% increments from January 1, 1994 to December 31, 1997 and were exercisable at
$40 per share. In addition, if any of the optionees' employment with the
Company is terminated within four years, the optionee must resell any exercised
options back to the Company at $40 per share.
A summary of the Company's Option Plan as of June 30 and the changes during the
years then ended is presented below:
1998 1997 1996
---- ---- ----
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
Outstanding at beginning of year 3,200 $ 40.00 6,400 $ 40.00 9,600 $ 40.00
Exercised 3,200 40.00 3,200 40.00 3,200 40.00
------ --------- ------ --------- ------ ---------
Outstanding at end of year 0 $ 0.00 3,200 $ 40.00 6,400 $ 40.00
====== ========= ====== ========= ====== =========
Options exercisable at year end 0 3,200 3,200
====== ===== ======
There have been no issuances since 1994 and therefore no compensation expense
was recognized under SFAS 123. The options exercised above were paid for in the
form of notes, which have been charged against equity until collected.
11. EARNINGS PER SHARE
Effective December 15,1997, the Company adopted SFAS No. 128, "Earnings per
Share" which replaces the presentation of primary and fully diluted earnings per
share with basic and diluted earnings per share. Basic earnings per share is
computed by dividing net earnings available for common stockholders by the
weighted average number of common shares outstanding for the year. Diluted
earnings per share reflects the potential dilution that could occur if options
to issue common stock were exercised. Dilutive earnings per share is computed
based upon the weighted average number of common shares and dilutive common
equivalent shares outstanding.
A reconciliation of the numerators and denominators of the basic and diluted
per-share computations for income from continuing operations is as follows:
Per-Share
Income Shares Amount
For the Year Ended June 30, 1998
Basic and Diluted Earnings per Share
Income available to common shareholders $ 3,014,000 665,074 $ 4.53
============ ======= ===========
For the Year Ended June 30, 1997
Basic Earnings per Share
Income (loss) available to common shareholders $(5,843,000) 688,247 $ (8.49)
===========
Effect of dilutive stock options - 1,493
------------ -------
Diluted Earnings per Share
Income (loss) available to common shareholders
plus assumed conversions $(5,843,000) 689,740 $ (8.47)
============ ======= ===========
For the Year Ended June 30, 1996
Basic Earnings per Share
Income available to common shareholders $ 7,820,000 700,373 $ 11.17
===========
Effect of dilutive stock options - 711
------------ -------
Diluted Earnings per Share
Income available to common shareholders
plus assumed conversions $ 7,820,000 701,084 $ 11.15
============ ======= ===========
12. UNCONSOLIDATED AFFILIATE
The Company's investment in BEC is accounted for under the equity method (see
Note 3). Summarized financial information for BEC is as follows (in thousands):
For the Year Ended June 30, 1998
Current assets $ 1,506 Current liabilities $ 2,894
Oil and gas properties 31,580 Long-term debt 4,300
Other assets 2,508 Other liabilities 152
-------- Equity 28,248
--------
Total assets $35,594 Total liabilities and equity $35,594
======== =======
Net sales $ 8,969
========
Gross profit $ 2,379
========
Net (loss) income $(1,772)
========
For the Year Ended June 30, 1997
Current assets $ 2,088 Current liabilities $ 2,372
Oil and gas properties 30,485 Long-term debt 30,500
Other assets 1,554 Other liabilities 135
-------- Equity 1,120
--------
Total assets $34,127 Total liabilities and equity $34,127
======== =======
BEC began operations on March 30, 1997. Results of operations were not material
for the three months ended June 30, 1997.
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 $1.7, $1.3 and $1.2 million for the years ended June 30, 1998,
1997 and 1996, respectively.
At June 30, 1998 future minimum lease payments for each of the next five years
and thereafter are as follows (in thousands):
1999 $1,391
2000 1,216
2001 971
2002 610
2003 397
Thereafter 799
------
$5,384
======
14. RELATED PARTY TRANSACTIONS
The Company has entered into a rental arrangement for the building used as its
headquarters from a partnership in which certain officers are partners. Rent
payments totaled approximately $339,470, $336,000, $300,000 for the years ended
June 30, 1998, 1997 and 1996, respectively.
Mountaineer purchases a portion of its gas supply requirements from a subsidiary
and from Eastern. The price paid for such purchases has been approved by the
WVPSC. During 1998, 1997 and 1996 Mountaineer purchased approximately
$5,569,000, $5,297,000 and $5,342,000 respectively, from its subsidiary and
$22,186,000, $23,225,000 and $15,258,000 respectively, from Eastern. The
related revenues and expenses between Mountaineer and its subsidiary and Eastern
have not been eliminated in these financial statements due to the regulated
nature of Mountaineer. At June 30, 1998, Mountaineer has $7,628,000 of
outstanding gas purchase commitments with Eastern.
The Company advanced funds to certain officers in 1991 and 1994, which bear
interest at 8% and are secured by non-voting common shares of Eastern. Balances
totaled $320,400 and $497,800, respectively, at June 30, 1998 and 1997 and are
due in 2001.
The Company also advanced funds in 1988 to certain officers and directors which
bear interest at 8%, are secured by interests in oil and gas properties and are
payable out of net proceeds from the oil and gas production on these properties.
Balances outstanding at June 30, 1998 and 1997 totaled $912,000 and $960,400,
respectively.
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 (the "Trust"). A
portion of the proceeds from the sale of these interests, representing a term
net profits interest, was accounted for as a production payment. Unamortized
proceeds totaling $13,504,700 and $15,121,700 at June 30, 1998 and 1997
respectively, have been classified as deferred trust revenue.
Certain gas production attributable to the Trust is purchased by a wholly owned
subsidiary of the Company pursuant to a gas purchase contract, which expires in
2013. The purchase price under the contract is based on escalating fixed price
and spot market components. 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 $6
million. The letter of credit is subject to annual reductions of $3 million
beginning June 30, 1996, and fully expires on June 30, 2000.
The Company has entered into an agreement whereby it funded a specified monthly
amount, through December 31, 1996, to assist in the development of oil and gas
projects by a third party. No remaining commitment exists as of June 30, 1998.
Amounts funded are accounted for as an advance and all outstanding amounts are
due on January 1, 1999. As of June 30, 1998 and 1997, the Company had $1.4
million and $2.5 million, respectively, in long-term notes receivable relating
to this agreement. In addition to the commitment, the Company has certain other
rights and options regarding the acquisition, exploration and development of the
oil and gas projects that may be acquired as a result of this agreement.
In connection with an existing gas delivery obligation agreement, whereby
Eastern received an advance payment, a subsidiary of Eastern entered into a
credit line deed of trust which has an available balance of $8 million as of
June 30, 1998 to collateralize its performance under the gas delivery
obligation. This credit line deed of trust declines at a rate of 7.5% per year.
On February 1, 1996, Mountaineer's largest pipeline supplier, Columbia
Transmission Corporation ("Columbia Transmission") placed increased rates into
effect pending hearing and decision by the Federal Energy Regulatory Commission
("FERC"). A settlement was approved by FERC on April 17, 1997, which provided
for reduced rates and refunds. The settlement resolved all issues except for
approximately $18 million annually in environmental remediation costs which
Columbia Transmission proposes to recover from its customers, including
Mountaineer. The issue has been set for hearing. In accordance with the
provisions of the settlement, Mountaineer received refunds totaling $6,142,000
which were credited against cost of gas in fiscal 1997.
On May 1, 1997, Columbia Gulf Transmission Company placed increased rates into
effect pending hearing and decision by FERC. A settlement was approved April
29, 1998 by FERC which eliminates the rate increase, reduces the rates paid by
Mountaineer below the pre-existing rate levels, and provides for certain refunds
of past over-collections.
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 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):
June 30, 1998 June 30, 1997
------------- -------------
Carrying Fair Carrying Fair
Value Value Value Value
Assets:
Cash and cash equivalents $ 21,547 $ 21,547 $ 20,814 $ 20,814
Accounts receivable 32,827 32,827 37,857 37,857
Notes receivable 5,618 5,580 7,303 7,227
Investment in common stock 2,794 2,794
Liabilities:
Accounts payable and
accrued expenses 38,834 38,834 31,037 31,037
Short-term debt 19,174 19,174 15,724 15,724
Funds held for future distribution 5,716 5,716 6,015 6,015
Long-term debt 262,088 266,856 260,144 260,905
Other long-term obligations 12,838 12,838 14,000 14,000
The following methods and assumptions were used by the Company in estimating the
fair value of its financial instruments:
Cash and Cash Equivalents, Accounts Receivable, Accounts Payable and Funds Held
for Future Distribution - Due to the short-term nature of these instruments,
carrying value is estimated to approximate fair value.
Notes Receivable - The notes receivable accrue interest at a fixed rate. Fair
value was estimated using discounted cash flows based on current interest rates
for notes with similar credit characteristics and maturities.
Investment in Common Stock - The fair value of the common stock is based on
quoted market prices.
Short-Term Debt and Line of Credit - The short-term debt is borrowed on a
revolving basis at a variable interest rate, approximately market; as a result,
the carrying value approximates fair value of the outstanding debt. Due to the
short-term nature of the line of credit, carrying value approximates fair value
of the outstanding debt.
Long-Term Debt - A portion of long-term debt was borrowed under a revolving
credit facility, which accrues interest at variable rates; as a result, carrying
value approximates fair value. The remaining portion of the Company's long-term
debt is comprised of fixed rate facilities; for this portion, fair value was
estimated using discounted cash flows based upon the Company's current borrowing
rates for debt with similar maturities.
Other Long-Term Obligations - The other long-term obligations were borrowed
under agreements, which accrue interest at variable rates, approximately market;
as a result, carrying value approximates fair value.
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 ("MRA").
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 estimates future losses on certain of its gas purchase commitments
of approximately $2 million and has accordingly offset the contract settlement
revenue by that amount.
The Company has retained its 10% limited partnership interest in Seneca. For
the fiscal year ended June 30, 1998, the Company recorded partnership
distributions of $10,029,000, comprised of $7,235,000 in cash and $2,794,000 of
Niagara common stock.
18. RATE MATTERS
Since November 1995, Mountaineer has operated under the terms of an agreement
whereby during the three year period November 1, 1995 through October 31, 1998
(the "Moratorium Period"), Mountaineer would maintain its rates at an agreed
upon level. The agreement stipulated that during the Moratorium Period,
Mountaineer's annual purchased gas adjustment filing with the WVPSC would be
temporarily suspended and the deferral accounting for the majority of costs
associated with gas purchases will not be in effect. In accordance with the
terms of the agreement, $12 million of the overrecovered gas costs recorded at
October 31, 1995 was amortized over the Moratorium Period. The amount of
overrecovered gas costs recorded at October 31, 1995 totaled $12.7 million. The
excess of the overrecovered gas costs over the amount to be amortized and
certain transportation revenues, storage balancing fees and standby charges are
subject to deferred accounting as authorized by the WVPSC for consideration in
the next rate proceeding. Consequently, Mountaineer assumed the risk of changes
in the cost of gas purchases and any changes in interstate pipeline rates and
charges during the Moratorium Period (see Note 4).
In January 1998, Mountaineer filed with the WVPSC for an increase in its base
rates which would become effective upon expiration of the Moratorium Period. 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 provides for a new three year Moratorium Period from November 1,
1998 to October 31, 2001. Other significant terms and conditions of the
Settlement are similar to those under which Mountaineer operated under during
the prior Moratorium Period. Beginning November 1, 1998, the excess of the
overrecovered gas costs and certain transportation revenues, storage balancing
fees and standby charges previously deferred as authorized by the WVPSC will be
credited to gas expense over the three-year period ending October 31, 2001.
19. INDUSTRY SEGMENTS
The following table sets forth the Company's principal industry segments and
their contribution to its revenues, operating profits, capital expenditures and
depletion, depreciation and amortization for the periods. Also shown are the
identifiable assets associated with each segment as of the end of each year
indicated (in thousands):
Year Ended June 30, 1998
------------------------
Regulated
Oil and Gas Utility Corporate
Operations Operations and Other Consolidated
Sales to unaffiliated customers $ 148,419 $ 158,134 $ 306,553
Intersegment 27,754 - 27,754
Contract settlement 30,029 - 30,029
------------- ------------ -------------
Total revenue $ 206,202 $ 158,134 $ 364,336
============= ============ =============
Operating profit $ 23,801 $ 14,276 $ (3,657) $ 34,419
Interest and other (3,587) (6,177) (19,381) (29,145)
------------- ------------ ----------- --------------
Income (loss) before income taxes $ 20,214 $ 8,099 $ (23,038) $ 5,274
============= ============ =========== ==============
Depletion, depreciation and
amortization expense $ 10,976 $ 8,902 $ 160 $ 20,038
============= ============ =========== ==============
Capital expenditures $ 22,599 $ 13,466 $ 2,358 $ 38,423
============= ============ =========== ==============
Total assets $ 172,758 $ 219,801 $ 47,386 $ 439,945
============= ============ =========== ==============
Year Ended June 30, 1997
------------------------
Regulated
Oil and Gas Utility Corporate
Operations Operations and Other Consolidated
Sales to unaffiliated customers $ 171,956 $ 173,463 $ 345,419
Intersegment 28,522 - 28,522
------------- ------------ -------------
Total revenue $ 200,478 $ 173,463 $ 373,941
============= ============ =============
Operating profit $ 6,169 $ 15,564 $ (2,666) $ 19,067
Interest and other (3,569) (9,761) (1,601) (14,931)
------------- ------------ ----------- --------------
Income (loss) before income taxes $ 2,600 $ 5,803 $ (4,267) $ 4,136
============= ============ =========== ==============
Depletion, depreciation and
amortization expense $ 11,597 $ 7,407 $ 40 $ 19,044
============= ============ =========== ==============
Capital expenditures $ 15,842 $ 10,305 229 $ 26,376
============= ============ =========== ==============
Total assets $ 166,723 $ 224,322 $ 43,712 $ 434,757
============= ============ =========== ==============
Year Ended June 30, 1996
------------------------
Regulated
Oil and Gas Utility Corporate
Operations Operations and Other Consolidated
Sales to unaffiliated customers $ 172,265 $ 182,929 $ 355,194
Intersegment 20,600 - 20,600
------------- ------------ -------------
Total revenue 192,865 182,929 375,794
============= ============ =============
Operating profit $ 6,791 $ 27,532 $ (2,375) $ 31,948
Interest and other (9,679) (10,982) - (20,661)
------------- ------------ ----------- --------------
Income (loss) before income taxes $ (2,888) $ 16,550 $ (2,375) $ 11,287
============= ============ =========== ==============
Depletion, depreciation and
amortization expense $ 12,930 $ 5,863 $ 24 $ 18,817
============= ============ =========== ==============
Capital expenditures $ 26,703 $ 12,629 $ 113 $ 39,445
============= ============ =========== ==============
The Company operates in two industry segments; oil and gas operations including
exploration and development, production, aggregation and marketing of third
party and Company owned oil and gas; operation of a regulated local gas
distribution company. Operating profit represents revenues less costs which are
directly associated with such operations. Revenues are priced and accounted for
consistently for both unaffiliated and intersegment sales. Intersegment sales
have not been eliminated in consolidation because of the regulated nature of the
gas distribution segment.
20. SUBSEQUENT EVENTS
On July 31, 1998 the Company's Board of Directors agreed to change the capital
structure by adding a new class of nonvoting Class A common stock. The common
stockholders approved this action on August 10, 1998. Articles of Amendment to
the Company's Articles of Incorporation were filed on August 21, 1998
authorizing the issuance of 100,000 shares of Class A stock. As of the date of
this report, no shares have been issued.
On July 31, 1998 Eastern's Board of Directors agreed to change its capital
structure by redeeming and canceling all 100,000 shares of Eastern's Class A
stock. Eastern's common stockholder approved this action on July 31, 1998.
Eastern's Class A stockholders approved this action on August 10, 1998. The
cancellation may be effected either by an exchange of shares for the Company's
new Class A stock, or the Company will pay cash to the stockholders, at each
Class A stockholder's option. Articles of Amendment to Eastern's Articles of
Incorporation were filed on August 21, 1998 terminating the Class A stock. As
of the date of this report, no exchanges or cash payments have been made.
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):
1998 1997 1996
---- ---- ----
Capitalized costs:
Proved properties $197,137 $192,970
Unproved properties 13,513 7,398
--------- ---------
Total 210,650 200,368
Less accumulated depletion and depreciation (64,770) (57,001)
--------- ---------
Net capitalized costs $145,880 $143,367
========= =========
Company's share of equity method investee's net
Capitalized costs $ 9,474 $ 8,877
========= =========
Costs incurred:
Acquisition of proved properties $ 2,039 $ 143 $ 4,318
Development costs 10,227 11,649 13,470
Exploration costs 9,154 3,728 6,141
--------- --------- -------
Total costs incurred $ 21,420 $ 15,520 $23,929
========= ========= =======
Company's share of equity method investee's total
Costs incurred $ 944 $ 115
========= =========
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):
1998 1997 1996
---- ---- ----
Revenues from sale of oil and gas $24,689 $33,301 $31,940
Less:
Production costs 3,101 7,997 7,986
Production taxes 1,448 1,966 1,407
Exploration and impairment 8,262 10,121 6,756
Depletion, depreciation and amortization 8,021 8,325 9,204
Income tax expense 1,453 1,712 1,647
------- ------- -------
Income from oil and gas operations $ 2,404 $ 3,180 $ 4,940
======= ======= =======
Company's share of equity method investee's
Income from oil and gas operations $ 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 to
be commercially recoverable fluctuate with changes in prices and operating
costs. Reserve estimates, by their nature, are generally less precise than
other financial statement disclosures.
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, 1995 171,818 7,020
Revisions of previous estimates 3,693 170
Purchases of reserves in place 7,500
Extensions and discoveries 5,950
Sales of reserves in place (19,700)
Production (9,812) (522)
-------- -------
June 30, 1996 159,449 6,668
Revision of previous estimates 331 (197)
Extensions and discoveries 13,331 545
Sales of reserves in place (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
======== =======
Proved developed reserves:
June 30, 1996 153,232 6,668
======== =======
June 30, 1997 141,116 748
======== =======
June 30, 1998 138,935 733
======== =======
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
======== =======
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.
The assumptions used to compute estimated future net revenues do not necessarily
reflect the Company's expectations of actual revenues or costs, nor their
present worth. In addition, variations from the expected production rates also
could result directly or indirectly from factors outside of the Company's
control, such as unintentional delays in development, changes in prices or
regulatory controls. The reserve valuation further assumes that all reserves
will be disposed of by production. However, if reserves are sold in place, this
could affect the amount of cash eventually realized.
Future development and production costs are computed by estimating the
expenditures to be incurred in developing and producing the proved oil and gas
reserves at the end of the year, based on period-end costs and assuming
continuation of existing economic conditions.
Future income tax expenses are computed by applying the appropriate year-end
statutory tax rates and existing tax credits, with consideration of future tax
rates already legislated, to the future pretax net cash flows relating to the
Company's proved oil and gas reserves.
An annual discount rate of 10% was used to reflect the timing of the future net
cash flows relating to proved oil and gas reserves.
Information with respect to the Company's estimated discounted future net cash
flows related to its proved oil and gas reserves as of June 30 is as follows (in
thousands):
1998 1997 1996
---- ---- ----
Future cash in flows $ 457,015 $ 473,464 $ 500,839
Future production and development costs (170,169) (172,219) (196,602)
Future income tax expense (57,000) (50,607) (48,860)
---------- ---------- ----------
Future net cash flows before discount 229,846 250,638 255,377
10% discount to present value (138,581) (143,791) (145,436)
---------- ---------- ----------
Standardized measure of discounted future
net cash flows related to proved oil and gas
reserves $ 91,265 $ 106,847 $ 109,941
========== ========== ==========
Company's share of equity method investee's
standardized measure of discounted future net
cash flows $ 19,975 $ 27,201
========== ==========
Principal changes in the standardized measure of discounted future net cash
flows for the years ended June 30 are as follows (in thousands):
1998 1997 1996
---- ---- ----
Standardized measure of discounted future
net cash flows at beginning of period $106,847 $109,941 $110,739
Sales of oil and gas produced, net of
production costs (13,816) (17,854) (16,528)
Net changes in prices and production costs (12,729) 17,395 21,717
Changes in production rates and other (14,256) 50 (11,057)
Extensions, discoveries and other additions,
net of future production and development
costs 5,910 12,185 3,944
Changes in estimated future development costs (1,495) (7,609) (13,685)
Development costs incurred 10,227 11,649 13,470
Revisions of previous quantity estimates 422 (1,022) 3,120
Purchase of reserves in place 2,026 4,918
Sales of reserves in place (56) (25,075) (12,919)
Accretion of discount 10,685 10,994 11,074
Net change in income taxes (2,500) (3,807) (4,852)
--------- --------- ---------
Standardized measure of discounted
future net cash flows at end of period $ 91,265 $106,847 $109,941
========= ========= =========
* * * * *
ENERGY CORPORATION OF AMERICA SCHEDULE I
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED BALANCE SHEETS INFORMATION
JUNE 30, 1998 AND 1997
(Dollars in Thousands)
- -----------------------------------------------------------
ASSETS 1998 1997
CURRENT ASSETS:
Cash $ 19,158 $ 16,192
Accounts receivable, affiliates 25,195 18,529
Accounts receivable, other 388 158
Other current assets 5,324 108
-------- --------
Total current assets 50,065 34,987
PROPERTY, PLANT AND EQUIPMENT - Net 3,226 288
INVESTMENT IN SUBSIDIARIES 168,032 192,649
OTHER ASSETS 13,448 8,447
-------- --------
TOTAL $234,771 $236,371
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued expenses $ 3,833 $ 2,500
Taxes payable - 5,122
-------- --------
Total current liabilities 3,833 7,622
LONG-TERM LIABILITIES
Long-term debt 200,661 200,000
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY 30,277 28,749
-------- --------
TOTAL $234,771 $236,371
======== ========
See notes to condensed financial information.
ENERGY CORPORATION OF AMERICA SCHEDULE I
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF OPERATIONS INFORMATION
FOR THE YEARS ENDED JUNE 30, 1998, 1997 AND 1996
(Dollars in Thousands)
- ------------------------------------------------------------------------------
1998 1997 1996
COSTS AND EXPENSES:
General and administrative $ 3,355 $ 2,608 $ 2,352
Depreciation of property, plant and equipment 160 40 24
--------- -------- --------
LOSS FROM OPERATIONS (3,515) (2,648) (2,376)
INTEREST EXPENSE 19,875 2,152
OTHER (INCOME) EXPENSE (1,072) (1,246) 1,931
--------- -------- --------
LOSS BEFORE INCOME TAXES AND EQUITY
IN EARNINGS OF SUBSIDIARIES (22,318) (3,554) (4,307)
BENEFIT FROM INCOME TAXES (8,335) (2,565) (1,142)
--------- -------- --------
LOSS BEFORE EQUITY IN EARNINGS OF
SUBSIDIARIES (13,983) (989) (3,165)
EQUITY IN EARNINGS (LOSSES) OF SUBSIDIARIES 16,997 (4,854) 10,985
--------- -------- --------
NET INCOME (LOSS) $ 3,014 $(5,843) $ 7,820
========= ======== ========
See notes to condensed financial information.
ENERGY CORPORATION OF AMERICA SCHEDULE I
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF CASH FLOWS INFORMATION
FOR THE YEARS ENDED JUNE 30, 1998, 1997 AND 1996
(Dollars in Thousands)
- -----------------------------------------------------------------------------------------------
1998 1997 1996
CASH FLOWS FROM OPERATIONS:
Net income (loss) $ 3,014 $ (5,843) $ 7,820
Adjustments to reconcile net income to cash
Provided by (used in) operating activities:
Equity in undistributed (earnings) losses of subsidiaries (16,997) 4,854 (10,985)
Depreciation and amortization 946 104 24
Changes in operating assets and liabilities (9,524) 5,077 (5,824)
Other (2,340) (4,634) 801
---------- --------- ---------
Net cash used in operating activities (24,901) (442) (8,164)
---------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Advances to subsidiaries (7,430) (9,821)
Expenditures for property (2,358) (229) (113)
Other investing activities (3,137) - -
---------- --------- ---------
Net cash used in investing activities (12,925) (10,050) (113)
---------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends paid (815) (1,007) (1,457)
Proceeds from issuance of debt 1,298 200,000
Principal payments on debt (217)
Contributions to capital of subsidiaries (178,378)
Deferred financing costs (601) (7,055)
Repurchase of common stock (523) (2,054) (632)
Subsidiary dividends and other 41,650 11,724 7,684
---------- --------- ---------
Net cash provided by financing activities 40,792 23,230 5,595
---------- --------- ---------
Net increase (decrease) in cash and cash equivalents 2,966 12,738 (2,682)
Cash and cash equivalents, beginning of year 16,192 3,454 6,136
---------- --------- ---------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 19,158 $ 16,192 $ 3,454
========== ========= =========
See notes to condensed financial information.
ENERGY CORPORATION OF AMERICA SCHEDULE I
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
NOTES TO CONDENSED FINANCIAL INFORMATION
FOR THE YEARS ENDED JUNE 30, 1998, 1997 AND 1996
- --------------------------------------------------------------------------------
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Investments in Subsidiaries - The financial statements of Energy Corporation of
America (the "Company") reflect investments in Eastern American Energy
Corporation, Eastern Systems Corporation, Westech Energy Corporation, Westech
Energy New Zealand Limited, and Westside Acquisition Corporation ("the
subsidiaries"), majority or wholly-owned subsidiaries, using the equity method.
Income Taxes - The benefit for income taxes is based on losses recognized for
financial statement purposes determined on a separate company basis. Deferred
income taxes are recognized for the tax effects of temporary differences between
such losses and those recognized for income tax purposes. The Company files a
consolidated U.S. income tax return with its subsidiaries.
2. CONSOLIDATED FINANCIAL STATEMENTS
Reference is made to the Consolidated Financial Statements and related Notes of
Energy Corporation of America and Subsidiaries for additional information.
3. LONG-TERM DEBT
Information concerning debt of the Company on a consolidated basis is disclosed
in Note 5 of the Notes to Consolidated Financial Statements of Energy
Corporation of America and Subsidiaries included elsewhere herein. The
Company's $200 million in 9-1/2% senior subordinated notes are due in 2007.
4. DIVIDENDS RECEIVED
The Company received dividends from its subsidiaries of $41.6 million, $10.4
million and $7.6 million for the years ended June 30, 1998, 1997 and 1996,
respectively.
* * * * *
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED JUNE 30, 1998, 1997 AND 1996
(Amounts in Thousands)
- ----------------------------------------------------------------------
1998 1997 1996
Balance at beginning of period $ 1,660 $ 1,744 $ 1,141
Charged to costs and expenses 2,572 2,102 1,800
Charged to other accounts (1) 58 291
Deductions (2) (2,609) (2,477) (1,197)
-------- -------- --------
Balance at end of period $ 1,681 $ 1,660 $ 1,744
======== ======== ========
(1) Recoveries of accounts previously written off.
(2) Accounts written off
Item 9. Changes In and Disagreements with Accountants on Accounting and
- ------- ---------------------------------------------------------------
Financial
- ---------
Disclosure
- -----------------------
Pursuant to Rule 12b-2 of the Exchange Act of 1934, the information required by
this Item 9 was previously reported by the Company in its S-4 Registration
Statement, as amended, filed with the Commission on June 11, 1997.
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, 1998 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 1997
annual meeting of stockholders. Executive officers are appointed by the Board
of Directors.
Name Age Position with Company or Subsidiary
- ------------------------ --- -----------------------------------------------------------------
Kenneth W. Brill 90 Chairman of the Board of the Company; Director
John Mork 50 President and Chief Executive Officer of the Company; Director
Joseph E. Casabona 54 Executive Vice President of the Company; Director
J. Michael Forbes 38 Vice President of the Company
Richard E. Heffelfinger 40 President of Eastern American; Director
Donald C. Supcoe (1) 42 Vice President, General Counsel and Secretary of Eastern American
F. H. McCullough, III 50 Vice President of the Company; Director
Richard L. Grant (1) 43 President of Mountaineer Gas Company
Michael S. Fletcher (1) 49 Senior Vice President and Chief Financial Officer of Mountaineer
Pamela T. Gates 51 Secretary of the Company
Peter H. Coors 51 Director
L. B. Curtis 74 Director
John J. Dorgan 74 Director
Arthur C. Nielsen, Jr. 79 Director
Julie Mork 48 Director
W. Gaston Caperton, III 58 Director
_______________
(1) Subsequent to June 30, 1998, Richard L. Grant resigned as President of
Mountaineer Gas Company and Michael S. Fletcher was appointed as Mr. Grant's
replacement. Also subsequent to June 30, 1998, Donald C. Supcoe was appointed
Senior Vice President of Mountaineer Gas Company.
Kenneth W. Brill has been the Chairman of the Board of the Company since
its formation. He served as Chairman of Eastern American from 1974 until it
became a wholly owned subsidiary of the Company in 1993. He was employed by
Conoco, Inc. from 1930 to 1973, and served as Vice President and Regional
General Manager of the Rocky Mountain Division for thirteen years.
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 Director of the Institute on Education and
Government, at the Teachers College of Columbia University. Mr. Caperton
presently serves on the Boards 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 1984 with KPMG Main Hurdman ("KPMG, Peat Marwick"). Mr. Casabona
graduated from the University of Pittsburgh with a B.A. in Accounting and from
the Colorado School of Mines with a M.S. in mineral economics. Mr. Casabona has
been a Certified Public Accountant since 1967.
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 Energy Corporation 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
graduated from The Colorado School of Mines with an Engineer of Petroleum
Professional degree.
John J. Dorgan has been a Director of the Company since 1993. He served as
a Director for Eastern American Energy Corporation in 1992. He is a former
Executive Vice President and now a consultant to Occidental Petroleum
Corporation where he has worked in various capacities since 1972.
Michael S. Fletcher has been Senior Vice President and Chief Financial
Officer of Mountaineer Gas Company since 1987. Prior to that time, Mr. Fletcher
was a partner of Arthur Andersen and Company and was employed by that firm for
15 years. Mr. Fletcher is also a Certified Public Accountant. Mr. Fletcher
graduated from Utah State University with a Bachelors Degree in Accounting.
Effective August of 1998, Mr. Fletcher was appointed President of Mountaineer
Gas Company.
J. Michael Forbes is Vice President of the Company and served as Treasurer
from 1995 to mid-1998. Mr. Forbes joined Eastern American in 1982 and was the
Vice President of Accounting, Treasurer and Chief Financial Officer of Eastern
American. Mr. Forbes graduated with a B.A. in accounting and finance from
Glenville State College and is a Certified Public Accountant. He also holds a
M.B.A. from Marshall University and is a graduate of Stanford University's
Program for Chief Financial Officers.
Pamela T. Gates is the Secretary of the Company. She has served as the
Executive Assistant to John Mork since 1984.
Richard L. Grant has been President of Mountaineer Gas Company since 1988.
Prior to his service with Mountaineer Gas Company, Mr. Grant served as legal
counsel with the Cincinnati Gas and Electric Company. Mr. Grant is both a
licensed professional engineer and attorney having graduated from Rose Hulman
Institute of Technology and Northern Kentucky University. Mr. Grant resigned as
President of Mountaineer Gas Company effective September 1, 1998.
Richard E. Heffelfinger is President of Eastern American and Eastern
Marketing and has been a Director of the Company since 1993. 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. 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.
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 Santa Fe International and 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 Energy
Corporation 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 in 1994-1995. 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 B.A. 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 Energy Corporation from 1985 until 1993. He
is Chairman, Emeritus of A.C. Nielsen Company and serves on the Boards of
Directors of Marsh and McLennan, Harris Trust and Savings Bank and General
Binding Corporation. He also serves as senior advisor to the Toshiba
Corporation.
Donald C. Supcoe is Vice President, General Counsel and Secretary of
Eastern American. He has been employed by Eastern American since 1981. Mr.
Supcoe 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 B.S. in
Business Administration. Mr. Supcoe received a Doctor of Jurisprudence Degree
from West Virginia University College of Law. Mr. Supcoe was named Senior Vice
President of Mountaineer Gas Company in August, 1998.
Item 11. Executive Compensation
- -------- ----------------------
The following table sets forth for fiscal year 1998 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 $211,488 $165,078 $39,664(1) $416,230
President and Chief Executive Officer
Joseph E. Casabona 194,955 130,854 8,569(2) 334,378
Executive Vice President
J. Michael Forbes 126,940 74,711 5,227(3) 206,878
Vice President
Richard L. Grant 272,569 185,240 23,119(4) 480,928
President of Mountaineer Gas Company
Richard E. Heffelfinger 180,133 56,500 3,987(5) 240,620
President of Eastern American Energy Corporation
______________
(1) Includes $7,748 in compensation related to insurance policies provided for the benefit
of John Mork, and 31,916 for personal use of company owned assets.
(2) lncludes $3,693 in compensation related to insurance policies provided for the benefit
of Joseph E. Casabona,
$1,553 for personal use of company owned assets, and $3,323 in 401K matching contributions.
(3) Includes $96 in compensation related to an insurance policy provided for the benefit of
J. Michael Forbes, $2,555 for personal use of company owned assets and $2,576 in 401K
matching contributions.
(4) Includes $19,811 for personal use of company owned assets and $3,302 for tax return
preparation.
(5) Includes $174 in compensation related to an insurance policy provided for the benefit of
Richard E. Heffelfinger, $546 for personal use of company owned assets and $3,267 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
June 30, 1998. 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.
Beneficial Ownership
--------------------
Number of
Shares Percent
-------------------- --------
Kenneth W. Brill (1) 68,310 10.27%
W. Gaston Caperton, III 160 *
Joseph E. Casabona 18,830 2.83%
Peter H. Coors 460 *
L. B. Curtis 12,560 1.89%
John J. Dorgan 810 *
J. Michael Forbes 3,200 *
Pamela T. Gates 300 *
Richard E. Heffelfinger 6,560 *
F. H. McCullough, III (3)(4) 96,125 14.19%
John Mork (2) 385,603 57.97%
Julie Mork (2) 385,603 57.97%
Arthur C. Nielsen, Jr. 36,160 5.44%
Donald C. Supcoe 3,200 *
All officers and Directors as a group (14 persons) 632,278 95.06%
__________
* 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's Common Stock owned by him, 22,940 of which have
been purchased by the Company.
(2) Includes 377,360 shares held by John and Julie Mork as joint tenants,
2,343 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, 5,960 of which have
been purchased by the Company.
(4) Includes 94,365 shares held by F.H. McCullough, III and Kathy McCullough
as joint tenants, 560 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.
Item 13. Certain Relationships and Related Transactions
- -------- ----------------------------------------------
Certain officers, Directors and key employees 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
officer, Director and key employee participate 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, Directors, key employees and their family
members may participate in either or both of the components. The following
table identifies the officers', Directors', key employees' and family members'
aggregate investment in the calendar years shown:
1998* 1997 1996
------------- ----------- --------
K.W. Brill $ 150,000 $ 47,318 $ 32,223
John Mork (1) 375,000 321,317 224,346
Joseph E. Casabona 50,000 41,871 20,858
J. Michael Forbes 10,000 13,120 8,276
Donald C. Supcoe 10,000 4,979 2,751
Richard L. Grant 35,000 21,287 2,751
L.B. Curtis 85,000 39,877 30,932
John J. Dorgan 50,000 32,543 22,232
Arthur C. Nielsen, Jr. 144,000 29,623 24,981
F.H. McCullough, III 150,000 97,458 -
Lesley McCullough Trust(2) 10,000 542 3,300
Kristen McCullough Trust(2) 10,000 542 3,300
Meredith McCullough Trust(2) 10,000 542 3,300
Katherine McCullough Trust(2) 10,000 542 3,300
Alison Mork Trust (3) 35,000 37,300 11,103
Kyle Mork Trust (3) 35,000 37,300 11,103
Gary A. Brill (4) - 325 20,858
E.J. Davies 75,000 26,985 20,858
Peter Coors 50,000 - -
Gaston Caperton 300,000 - -
---------- -------- --------
Total $1,594,000 $755,469 $446,472
========== ======== ========
__________
* These amounts represent only the amounts committed to the 1998
Drilling Program and 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.
(4) Son of Kenneth W. Brill.
Certain officers, Directors and key employees of the Company have notes
payable to the Company or its subsidiaries which are secured by such
individual's interests in certain of the Company's drilling programs. Each of
these notes bears interest at 8% per annum. The balance owed by the individuals
as of June 30, 1998 was $880,026. The amounts owed by the named officers,
Directors and key employees, as of June 30, 1998, are as follows:
K.W. Brill $291,441
John Mork 313,616
Joseph E. Casabona 42,766
J. Michael Forbes 6,969
Richard E. Heffelfinger 4,752
L.B. Curtis 17,740
Arthur C. Neilsen, Jr. 41,182
F. H. McCullough, III 161,560
--------
Total $880,026
========
In addition to the foregoing notes, various officers and Directors of the
Company have borrowed money from the Company and have executed promissory notes
therefor. These promissory notes are generally secured by a pledge of the stock
of the Company or the stock of one of its subsidiaries. The notes bear interest
at 8% per annum. As of June 30, 1998, the following were indebted to the
Company in amounts in excess of $60,000:
Joseph E. Casabona $147,000
J. Michael Forbes 96,000
Richard E. Heffelfinger 192,000
F. H. McCullough, III 176,000
Donald C. Supcoe 96,000
--------
Total $707,000
========
Eastern American entered into an agreement in July 1991 to rent 11,260
square feet of office space in Charleston, West Virginia from Energy Centre,
Inc. a corporation owned 33.33% by John Mork, 16.667% by each of Kenneth W.
Brill, F. H. McCullough, III and Joseph E. Casabona and 5.57% by each of Donald
C. Supcoe, Richard E. Heffelfinger and J. Michael Forbes. The agreement was
amended in April 1994 to provide for the lease of an aggregate of 19,069 square
feet of office space. In June 1998, an additional 2,368 square feet of office
space was leased. The aggregate amount paid by such subsidiary for rent to such
corporation was $339,470 for fiscal year 1998. The Company believes that such
rental terms are no less favorable than could have been obtained from an
unaffiliated party.
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 into
this Registration Statement:
*-3.1 Articles of Incorporation of Energy Corporation of America
-3.2 Amendment to 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.
*-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
-21.1 Subsidiaries of Energy Corporation of America
-23.1 Independent Auditors' Consent on Schedules contained in Item 8
-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 were filed during the fiscal year ended
June 30, 1998.
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 28th day of
September, 1998.
ENERGY CORPORATION OF AMERICA
By: /s/ John Mork
-------------------------------------
John Mork
President and Chief Executive Officer
82
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 J. Michael Forbes 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 of 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 twenty-second day of September, 1998, by the following
persons in the capacities indicated.
Signature Title
- --------------------------- -----------------------------------------------------------------------------
/s/ Kenneth W. Brill
- ---------------------------
Kenneth W. Brill Chairman of the Board of Directors
/s/ John Mork
- ---------------------------
John Mork President, Chief Executive Officer and Director (principal executive officer)
/s/ Joseph E. Casabona
- ---------------------------
Joseph E. Casabona Executive Vice President and Director (principal accounting officer)
/s/ J. Michael Forbes
- ---------------------------
J. Michael Forbes Vice President (principal financial officer)
/s/ Richard E. Heffelfinger
- ---------------------------
Richard E. Heffelfinger Director
/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