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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 Mmb