UNITED STATES 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 [FEE REQUIRED]
For the fiscal year ended June 30, 1994
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from to
Commission file number 0-10618
ALLEGHENY & WESTERN ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
West Virginia 55-0612692
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
300 Capitol Street, Suite 1600
Charleston, WV 25301
(Address of principal executive office) (Zip Code)
Registrant's telephone number, including area code (304) 343-4567
Securities registered pursuant to Section 12(b) of the Act:
Name of each Exchange on
Title of each class which registered
None None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock - par value $.01 per share
(Title of class)
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 checkmark 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. [ ]
The aggregate market value of Common Stock held by nonaffiliates
on September 1, 1994 was $62,295,642.
As of September 1, 1994, there were 7,479,360 shares of Common
Stock $.01 par value outstanding.
DOCUMENTS INCORPORATED BY REFERENCE.
The information required by Part III of this Form (Items 10, 11,
12 and 13) is incorporated by reference from the registrant's
Proxy Statement to be filed pursuant to Regulation 14A.<PAGE>
<PAGE> 1
PART I
Item 1. Business
GENERAL
Allegheny & Western Energy Corporation (Allegheny or the Company)
is a West Virginia corporation which was incorporated in 1981.
The Company is a diversified natural gas company whose principal
subsidiary, Mountaineer Gas Company (Mountaineer), is the largest
natural gas distribution utility in West Virginia. Allegheny is
also engaged in non-utility enterprises directly and through
subsidiaries, including developmental drilling and production of
natural gas in West Virginia and the marketing of natural gas
directly to consumers in West Virginia. The Company's past
exploration and production activities in the Appalachian Basin of
West Virginia have been conducted for its own account and through
joint ventures with third parties and limited partnerships.
Allegheny has performed no drilling activities since fiscal 1992.
Allegheny's field services operations consist of the
administration and operation of producing properties in West
Virginia for which Allegheny is the operator.
Mountaineer provides natural gas service to approximately 200,000
residential, commercial, industrial and wholesale customers in 45
counties in West Virginia, including the cities of Charleston,
Beckley, Huntington and Wheeling. Mountaineer owns and operates
approximately 3,600 miles of natural gas distribution pipelines
in West Virginia. Acquired in 1984 from The Columbia Gas System,
Inc., Mountaineer is regulated by the Public Service Commission
of West Virginia (PSCWV). In March 1993, Mountaineer, through
its wholly-owned subsidiary Mountaineer Gas Services, Inc. (MGS),
acquired all of the West Virginia assets of Hallwood Energy
Partners, L.P. and Hallwood Consolidated Resources Corporation
(Hallwood). These assets included approximately 13.5 billion
cubic feet (Bcf) of net natural gas reserves, approximately 274
miles of natural gas transmission facilities and approximately
19,600 net acres of undeveloped leaseholds. The transaction was
approved by the PSCWV, and MGS began operating the properties on
April 1, 1993. MGS was formed for the purpose of holding and
operating the acquired assets. Substantially all natural gas
produced by MGS is sold to Mountaineer based on prices approved
by the PSCWV.
Allegheny's non-regulated gas marketing subsidiary, Gas Access
Systems, Inc. (G.A.S.), sells natural gas directly to industrial,
commercial and municipal customers in West Virginia. G.A.S.
markets natural gas produced by Allegheny as well as supplies
obtained from other producers and wholesalers located in West
Virginia and the continental United States.
In November 1990, Allegheny entered into an agreement with a
third party whereby the Company acquired a 50% interest in
petroleum prospecting licenses, which were granted in February
1991 and became effective in August 1991, covering approximately
2.6 million acres in the North Island, New Zealand including<PAGE>
<PAGE> 2
acreage both onshore and offshore. The Company has formed a New
Zealand subsidiary, A&W Exploration New Zealand, Limited (AWENZ)
which holds the Company's interests in the petroleum prospecting
licenses. During fiscal 1992, AWENZ acquired an additional 9.5%
interest in the prospecting licenses.
As of June 30, 1994, Allegheny's and MGS's combined net proved
reserves were approximately 26.7 Bcf of natural gas and 28,000
barrels of oil, based on reports from independent petroleum
engineers. See discussion of "Net Proved Oil and Gas Reserves"
under Item 2.
The principal offices of the Company are located at 300 Capitol
Street, Suite 1600, Charleston, West Virginia 25301, and the
telephone number is (304) 343-4567.
NATURAL GAS UTILITY
Mountaineer purchases, distributes and supplies natural gas to
approximately 200,000 customers in 45 of West Virginia's 55
counties, including the cities of Charleston, Beckley, Huntington
and Wheeling. Mountaineer is the largest natural gas
distribution utility in West Virginia.
Customers
The table below sets forth operating revenues and related gas
volumes (in thousand cubic feet (Mcf)) of Mountaineer for the
periods indicated:
<TABLE>
<CAPTION>
Twelve Months Ended June 30,
(dollars in thousands)
1994 1993 1992
<S> <C> <C> <C>
Gas Distribution Revenues
Residential $ 115,339 $ 110,142 $ 110,172
Commercial 36,949 32,788 34,767
Industrial 1,199 459 606
Other 435 (157) 1,145
Transportation 11,629 12,541 7,331
--------- --------- ---------
Total $ 165,551 $ 155,773 $ 54,021
========= ========= =========
Gas Volumes (Mcf)
Residential 19,091 18,195 18,005
Commercial 6,256 5,489 5,799
Industrial 288 91 152
Other 31 (26) 172
Transportation 35,819 34,979 29,059
--------- --------- ---------
Total Throughput Volume 61,485 58,728 53,187
========= ========= =========
Weighted Average
Sales Rate (per Mcf) $ 6.00 $ 6.03 $ 6.08
========= ========= =========
Average Transportation <PAGE>
<PAGE> 3
Rate (per Mcf) $ .32 $ .36 $ .25
========= ========= =========
</TABLE>
More than 95% of the residential and commercial customers of
Mountaineer 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 and competition from alternate sources of energy.
Demand for natural gas is also affected by Federal and state
energy laws and regulations.
Gas Supply
During the fiscal year ended June 30, 1994, Mountaineer purchased
75% of its natural gas supply from suppliers in the southwestern
United States. The remainder was supplied by local West Virginia
producers (17%), MGS (6%), Allegheny (1%) and Columbia Gas
Transmission Corporation (Columbia Transmission) (1%), an
affiliate of The Columbia Gas System, Inc. During the fiscal
year ended June 30, 1993, Mountaineer purchased 63% of its
natural gas supply from suppliers in the southwestern United
States. The remainder was supplied by Columbia Transmission
(19%), local West Virginia producers (15%), MGS (2%) and
Allegheny (1%). The decline in the natural gas supplied by
Columbia Transmission is due to the implementation of the Federal
Energy Regulatory Commission's (FERC) Order 636 et. seq., (the
636 Orders).
In 1992, the FERC issued the 636 Orders. The 636 Orders required
substantial restructuring of the service obligations of
interstate pipelines. Among other things, the 636 Orders
mandated "unbundling" of existing pipeline gas sales services and
replaced existing statutory abandonment procedures, as applied to
firm transportation contracts of more than one year, with a
right-of-first-refusal mechanism. Mandatory unbundling required
pipelines to sell separately the various components of their
previous gas sales services (gathering, transportation and
storage services, and gas supply). To address concerns raised by
utilities about reliability of service to their service
territories, the 636 Orders required pipelines to offer a no-
notice transportation service in which firm transporters can
receive delivery of gas up to their contractual capacity level on
any day without prior scheduling. In addition, the 636 Orders
provided for a mechanism for pipelines to recover prudently
incurred transition costs associated with the restructuring
process.
All of Mountaineer's pipeline suppliers have filed their
restructuring plans with the FERC. The FERC has reviewed these
plans; however, there are several issues which remain subject to
further action by either the FERC or reviewing courts, including
the ultimate sharing of transition costs, the level of no-notice
protection and the impact on service reliability, and rate design
implementation. Mountaineer's largest pipeline supplier,
Columbia Transmission, received orders from the FERC which
approved its proposed restructuring filing with certain<PAGE>
<PAGE> 4
modifications. One of the FERC modifications prohibited Columbia
Transmission from recovering contract rejection claims it may
incur in its bankruptcy proceeding as part of its transition
costs. Columbia Transmission and others have filed for appellate
review of this disallowance. In addition, Columbia Transmission
filed a revised compliance plan with the FERC on October 22,
1993, which was placed into effect on November 1, 1993, subject
to further modification.
As a consequence of the November 1, 1993 restructuring,
Mountaineer has replaced the bundled firm sales service it
previously received from Columbia Transmission with gas purchase
arrangements negotiated with unregulated suppliers and firm
transportation and storage agreements with Columbia Transmission.
Interim supply arrangements are in place, negotiations for long-
term supplies are underway and the Company is reviewing its
current level of firm service contracts to determine if
additional capacity is necessary to provide reliable service to
its customers. Unresolved issues include whether the new
unbundled transportation and storage services provided by
Columbia Transmission, and the replacement natural gas supplies
provided by others, will result in the same degree of service
reliability as the bundled firm sales service Columbia
Transmission has provided to Mountaineer in the past. Because of
these issues and others, Mountaineer has petitioned for appellate
review of both the 636 Orders and the orders approving the
implementation of Columbia Transmission's restructuring pursuant
to the 636 Orders. Mountaineer's management continues to
actively participate in Columbia Transmission's compliance
filings in order to protect Mountaineer's interests, ensure the
continued reliability of service to its customers and minimize
future transition costs.
Until Mountaineer's pipeline suppliers' rate filings to implement
restructuring, including subsequent filings to recover
transition costs, are fully approved by the FERC, the ultimate
amount of the costs associated with restructuring cannot be
ascertained. However, Mountaineer's management anticipates that
the amount of restructuring costs that will be passed through to
Mountaineer will be significant. Mountaineer will attempt to
obtain approval from the PSCWV to recover any such approved
restructuring costs from its customers. On the basis of previous
state regulatory proceedings involving the recovery of gas
purchase costs and take-or-pay obligations, Mountaineer believes
that the costs passed through from its pipeline suppliers will be
recovered from ratepayers, although there can be no assurance
that this will be the case.
On July 31, 1991, Columbia Transmission and The Columbia Gas
System, Inc. (the Columbia Companies) filed for protection under
Chapter 11 of the Bankruptcy Code. The Columbia Companies stated
that the primary basis for their filing was the failure of
Columbia Transmission to acquire natural gas through existing
producer contracts under terms and conditions, including price,
which would permit Columbia Transmission to compete in the
marketplace. Columbia Transmission's filing could affect its
relationship with Mountaineer. Although Mountaineer only<PAGE>
<PAGE> 5
purchased 1% of its gas supplies from Columbia Transmission
during fiscal 1994, Mountaineer relies upon Columbia Transmission
for the delivery of a majority of Mountaineer's gas supplies.
On January 18, 1994, Columbia Transmission filed a proposed plan
of reorganization in the bankruptcy proceedings, but requested
the Bankruptcy Court to defer all further proceedings on such
plan pending further discussions with Columbia Transmission's
major creditors and official committees, including the official
committee of customers which Mountaineer chairs. The plan, if
ultimately approved by the Bankruptcy Court and accepted by
Columbia Transmission's customers, would inter alia, (i) pay
Columbia Transmission's customers 100% of certain refund amounts
ordered by the FERC, but at a lower interest rate than provided
by the FERC, (ii) pay Columbia Transmission's customers 90% of
certain other refunds ordered by the FERC, and (iii) require any
customer accepting the plan to waive its entitlement to all other
refund amounts and to not oppose Columbia Transmission's recovery
from such customers of approximately $250 million in certain
costs to be filed with the FERC. Discussions on the proposed
plan are at a preliminary stage and Columbia Transmission is in
the process of providing additional information necessary to
evaluate the proposal. However, at this stage, various aspects
of the proposal appear unacceptable to the official committee of
customers.
In addition, the United States Court of Appeals for the District
of Columbia Circuit recently granted an appeal filed by
Mountaineer and others which challenged Columbia Transmission's
right to recover through FERC-approved rates over $120 million in
take-or-pay costs from its customers. Once the court's decision
becomes final, the case will be remanded to the FERC for further
proceedings to determine the level of refunds owed Columbia
Transmission's customers. The refund amount determined may have
a significant bearing on Columbia Transmission's proposed plan of
reorganization and any negotiated resolution thereof.
Mountaineer is vigorously opposing Columbia Transmission's
efforts to recover costs related to its Chapter 11 bankruptcy
proceedings. The outcome of these proceedings could materially
affect Mountaineer's prices to its customers. Mountaineer is
reviewing its options, including the level of Columbia
Transmission's role in providing service to Mountaineer in the
future. Mountaineer's management continues to be actively
involved in this process in order to minimize any adverse impact
on the interests of Mountaineer or its customers.
Regulation and Rates
Mountaineer is subject to the jurisdiction of the PSCWV as to
various phases of its operations, including base and purchased
gas adjustment rates and accounting and service standards.
Mountaineer's management continually reviews the adequacy of
Mountaineer's rates and files requests for rate increases when it
is deemed necessary and appropriate. In addition, FERC
regulations apply to various phases of Mountaineer's business,
including the rates charged by interstate pipeline suppliers.<PAGE>
<PAGE> 6
On October 29, 1993, the PSCWV issued an order (the October 1993
Order), effective November 1, 1993, regarding Mountaineer's
request in January 1993 for increased base rates. The October
1993 Order, among other matters, provided for a 10.1% return on
equity and rate increases which would generate additional annual
revenues of approximately $3,400,000 under normal operating
conditions. In its original filing, Mountaineer requested a
return on equity of 12.3% and rate increases that would result in
increased annual revenues of $7,500,000. On November 8, 1993,
Mountaineer filed a petition for reconsideration of several
issues contained in the October 1993 Order, including the granted
rate of return on equity and the rate recovery mechanism of the
cost of postretirement benefits other than pensions (OPEB). On
March 30, 1994, the PSCWV issued a final order in this rate case
(the March 1994 Final Order) after reconsidering several issues
raised by various parties to the rate case. In the March 1994
Final Order, the PSCWV granted an increase in the authorized
return on equity to 10.55% and established a tracking mechanism
for certain OPEB costs. The March 1994 Final Order also put
Mountaineer on notice that in its next rate case, any savings
generated by Mountaineer's participation in a consolidated tax
return would be passed through to Mountaineer's ratepayers unless
persuasive legal or accounting arguments are presented to the
PSCWV to convince them to act otherwise. Management is unable to
determine what impact the consolidated tax savings issue will
have on Mountaineer's future results of operations.
The PSCWV does not guarantee Mountaineer a rate of return on its
common equity; rather, it establishes rates which afford
Mountaineer an "opportunity" to earn a certain rate of return
under normal weather conditions, subject to the effectiveness of
Mountaineer's operations. During the years ended June 30, 1994,
1993 and 1992, Mountaineer earned approximately $7.3 million,
$4.8 million and $5.3 million, representing a 12.1%, 9.1% and
11.0% return on common equity, respectively.
Mountaineer may pay dividends to Allegheny without regulation by
the PSCWV; however, Mountaineer's rates established by the PSCWV
are designed to permit a certain after-tax return on common
equity and the payment of dividends could have a negative impact
on Mountaineer's future applications for rate increases with the
PSCWV. Mountaineer's payment of dividends is restricted by the
terms of its outstanding debt obligations (see Note 4 of the
accompanying consolidated financial statements). No dividends
were paid during the years ended June 30, 1994, 1993 and 1992.
Under the most restrictive terms of its debt obligations,
Mountaineer would be permitted to pay dividends of approximately
$11.7 million as of June 30, 1994.
Competition
Natural gas competes with other forms of energy available to
customers, primarily on the basis of rates. 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<PAGE>
<PAGE> 7
fuels and other forms of energy may affect the demand for natural
gas in areas served by Mountaineer.
Mountaineer is also subject to competition from interstate and
intrastate pipeline companies, producers and regulated or
unregulated utilities which 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.
In order to improve its competitive position, Mountaineer
transports gas for certain industrial, commercial and residential
customers who purchase natural gas directly from other sources.
Mountaineer's margin for such transportation services is
generally the same as that generated by gas sales to these
customers.
Employees
Mountaineer has entered into six different collective bargaining
agreements covering several employee locations throughout the
state of West Virginia. These agreements expire at various times
during the period of January 1995 through August 1997. As of
June 30, 1994, Mountaineer had 548 employees, of which 318
employees were subject to such collective bargaining agreements.
Mountaineer currently considers relations with its employees to
be satisfactory.
NATURAL GAS MARKETING ACTIVITIES
G.A.S. was formed in July 1987 to market Allegheny's production
of natural gas. In fiscal 1994, wells operated by Allegheny
supplied approximately 48% of G.A.S.'s gas supply needs, and the
balance was purchased from producers and wholesalers in West
Virginia and the continental United States. G.A.S. markets
natural gas directly to industrial, commercial and municipal
customers in West Virginia and arranges suitable transportation
to the customers' premises. G.A.S. has a policy of purchasing
gas only to the extent of anticipated customer requirements as it
maintains none of its own storage facilities.
Contracts with G.A.S.'s customers for non-Allegheny gas supplies
are typically for a limited duration, generally twelve months,
may contain provisions for monthly price adjustments and do not
include minimum or maximum usage requirements, although the
provisions of specific agreements may vary. Contracts involving
gas purchased from Allegheny differ in that they may contain
fixed daily volumes and either fixed or adjustable prices.
G.A.S. competes with other marketing firms on the basis of price
and the ability to arrange suitable transportation to the
customers' premises.
MGS acquired the West Virginia assets of Hallwood in March 1993,
and began operating such assets effective April 1, 1993. These
operations included the assumption of several sales contracts
with large volume customers. Natural gas supplies for these<PAGE>
<PAGE> 8
customers are purchased through agreements with producers and
wholesalers on a month to month basis.
EXPLORATION, DEVELOPMENTAL DRILLING AND PRODUCTION ACTIVITIES
Allegheny
Field Services
Allegheny (not including subsidiaries discussed below) has
conducted developmental drilling on properties for its own
account and through limited partnerships and joint ventures;
however, no drilling activity has been performed since fiscal
1992. Historically, during drilling operations, Allegheny
managed all drilling activities on the properties and furnished,
directly or through subcontractors, all necessary drilling,
service and equipment requirements. Allegheny acts as the
operator for producing wells it has drilled and completed, for
which it earns a fee in addition to reimbursement of certain
direct operating expenses for wells drilled with limited
partnerships and joint ventures.
Developmental Drilling
Allegheny has historically been engaged in developmental drilling
of natural gas wells in West Virginia, principally in the
Appalachian Basin. Allegheny has drilled no exploratory wells in
West Virginia in the last three fiscal years. In addition,
Allegheny has not engaged in any developmental drilling
activities since fiscal 1992. (Exploratory wells are those
drilled in an unproved area, to find a new reservoir in a
previously productive area, or to extend a known reservoir.
Development wells are those drilled within the proved area of a
reservoir to a known productive depth.) The extent of the
Company's future drilling activities will depend upon, among
other factors, the market prices of oil and gas, the Company's
available funds, the Company's ability to raise funds in the
capital markets and the Company's ability to attract industry
partners. While the Company's plans are subject to change,
management does not currently anticipate that the Company will
undertake any new exploration or development drilling during
fiscal 1995.
Allegheny obtains and investigates prospects through its own
staff and/or in conjunction with third parties and acquires
drilling and development rights which it considers to be of
interest.
The table below summarizes Allegheny's drilling activity for the
years indicated. There is no correlation between the number of
productive wells completed during any period and the aggregate
reserves attributable thereto. The drilled wells represent the
total wells drilled by Allegheny in West Virginia during the past
three fiscal years all of which were drilled in conjunction with
a drilling program with a major insurance company.<PAGE>
<PAGE> 9
<TABLE>
<CAPTION>
Development Wells Drilled
Total Productive Oil Productive Gas Dry
Gross Net Gross Net Gross Net Gross Net
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Fiscal Year ended
June 30, 1992 4 0.34 --- --- 4 0.34 --- ---
Fiscal Year ended
June 30, 1993 --- --- --- --- --- --- --- ---
Fiscal Year ended
June 30, 1994 --- --- --- --- --- --- --- ---
/TABLE
<PAGE>
<PAGE> 10
The term "gross" as it applies to wells, refers to the aggregate
number of wells in which Allegheny owns a direct or indirect
working interest. The term "net" refers to Allegheny's aggregate
direct or indirect working interest in gross wells.
As of June 30, 1994, Allegheny had a direct or indirect ownership
interest in a total of 612 gross producing gas or combination gas
and oil wells, which in the aggregate currently produce
approximately 10,700 Mcf of natural gas and 45 barrels of oil per
day. Allegheny's weighted average net revenue interest in the
volumes produced was approximately 27%.
MGS
During April 1993, MGS began operating the natural gas producing
properties acquired from Hallwood. The acquisition included
interests in 392 natural gas producing wells and 19,600 acres of
undeveloped leaseholds. No additional wells were drilled by MGS
in fiscal 1994. In July 1994, MGS began its fiscal 1995 drilling
program which anticipates the drilling and completion of five
developmental wells. MGS intends to drill additional gas wells
for its own account over the next three years. Production from
these wells will be sold to Mountaineer at prices approved by the
PSCWV.
As of June 30, 1994, MGS had a direct ownership interest in 392
gross producing gas wells, which in the aggregate currently
produce approximately 4,500 Mcf of natural gas per day. MGS's
weighted average net revenue interest in the volumes produced is
approximately 66%.
New Zealand
In July 1991, the Company formed AWENZ for the purpose of holding
its 59.5% interest in two petroleum prospecting licenses covering
approximately 2.6 million gross acres located in the North
Island, New Zealand, both onshore and offshore. The petroleum
prospecting licenses are for a period of five years, beginning
February 1991, permit the conduct of seismic testing and mapping
and the performance of geological and geophysical analysis and
the drilling of several exploratory wells. AWENZ and its partner
must maintain a work schedule defined in the licensing agreement
to retain their interests in each of the licenses. The Company
and its partner have been granted an extension of the time period
allowed for the completion of certain geological and geophysical
work required under the licenses. If the Company and its partner
discover oil and gas reserves, they may elect to apply for a
petroleum mining license from the Minister of Energy of New
Zealand to develop certain selected parts of the acreage the
prospecting licenses cover.
AWENZ and its partner share the costs incurred under these
licenses during the initial exploratory stage proportionally
based on their ownership interests. As of June 30, 1994, the
Company had invested approximately US $943,000 in this
arrangement. In order to obtain the petroleum prospecting
licenses, AWENZ and its partner posted a performance bond of NZ<PAGE>
<PAGE> 11
$500,000 (US $297,500 as of June 30, 1994), which is a normal
requirement of the Minister of Energy. Should AWENZ and its
partner not perform their commitments as required by the
licenses, the government of New Zealand could elect to call the
bonds, which would require the payment by AWENZ of 59.5% of such
amount. To the best of management's knowledge, all such
commitments currently required by the licenses have been
performed.
AWENZ and its partner are continuing to conduct and evaluate
geological and geophysical seismic testing to determine the
future potential, if any, for petroleum production from these
regions. Management will continue to monitor and assess the
potential of the Company's investment in this prospect.
General
The Company is investigating other areas of West Virginia and
elsewhere for acquisitions and drilling prospects to establish,
expand or improve oil and gas production.
Employees
As of June 30, 1994, there were approximately 30 employees
involved in producing activities for Allegheny, none of whom were
subject to a collective bargaining agreement. The Company
considers relations with these employees to be satisfactory. MGS
employs supervisory and clerical personnel; however,substantially
all drilling and producing operations are currently performed by
third parties on a contract basis.
Acreage
The following table sets forth the approximate gross and net
acres of undeveloped and developed oil and gas properties (all of
which are located in West Virginia) in which Allegheny and MGS
had a direct or indirect working interest as of June 30, 1994:
<TABLE>
<CAPTION>
Undeveloped Developed
Gross Net Gross Net
<S> <C> <C> <C> <C>
Allegheny 4,100 4,100 50,200 15,300
MGS 23,900 19,600 63,800 46,400
------- ------- ------- -------
28,000 23,700 114,000 61,700
======= ======= ======= =======
</TABLE>
The term "gross" as it applies to acreage, refers to the
aggregate acreage in which Allegheny and MGS own a direct or
indirect working interest. The term "net" refers to aggregate
direct or indirect working interest in gross acres.
As of June 30, 1994, a substantial portion of Allegheny's<PAGE>
<PAGE> 12
undeveloped gross and net acres cannot be developed until certain
releases are obtained from certain governmental agencies.
Production
The following table shows for the period indicated, the average
sales price, production (lifting) costs per unit of oil and gas
and net quantities of oil and gas sold (with oil production
converted to Mcf's on the basis of one barrel of oil equivalent
to six Mcf's of gas):
<TABLE>
<CAPTION>
Fiscal Year Ended June 30,
1994 1993 1992
<S> <C> <C> <C>
Average sales price of
natural gas (per Mcf) $ 2.43 $ 2.29 $ 2.13
Average sales price of
oil (per Bbl) $ 13.96 $ 18.77 $ 18.46
Average production cost
(per Eq Mcf) $ .57 $ .42 $ .83
Volumes sold, net (Eq Mcf) 3,053,801 1,547,559 1,863,387
</TABLE>
The average sales price of natural gas increased in fiscal 1994
due to the increased market prices experienced throughout the
natural gas industry. The increase in average production costs
and volumes sold in fiscal 1994 was primarily attributable to
MGS's operations being in place for all of fiscal 1994 versus
only three months in fiscal 1993.
The average sales price of natural gas increased in fiscal 1993
as a result of market conditions experienced throughout the
industry. Average production costs decreased significantly in
fiscal 1993 as a result of the Company's wholly-owned subsidiary,
TEX-HEX Corp., ceasing all production activities in April 1992
and the effects of a full year of a cost reduction program
implemented in fiscal 1992 by Allegheny.
Substantially all production of natural gas from Allegheny's
properties is sold to either G.A.S. or Mountaineer.
Substantially all production of natural gas from MGS's properties
is sold to Mountaineer.
Financing of Exploration and Developmental Drilling Activities
Allegheny's past exploration and drilling expenditures have been
predominantly funded from internally generated capital, joint
ventures, industry partners and limited partnerships. While the
Company's plans are subject to change, management does not
currently anticipate that Allegheny will undertake any new<PAGE>
<PAGE> 13
exploration or development drilling during fiscal 1995. The
amount of Allegheny's future expenditures will depend on, among
other factors, the market prices of oil and gas, Allegheny's
available funds, its ability to raise funds in the capital
markets, and its ability to attract industry partners.
In July 1994, MGS began its fiscal year 1995 drilling program
which anticipates the drilling and completion of five
developmental wells. MGS intends to drill additional natural gas
wells for its own account over the next three years. Financing
for this drilling activity is expected to be raised from
internally generated sources. These expenditures are not
expected to exceed $1.0 million in fiscal 1995. Future MGS
production will be sold to Mountaineer at prices approved by the
PSCWV.
Competition
The oil and gas industry is intensely competitive in all phases,
including the exploration for new production and reserves,
obtaining equipment and labor necessary to conduct drilling
activities and the acquisition of developed and undeveloped oil
and gas properties on favorable terms. Competition comes from
major oil and gas companies as well as independent operators.
There is also competition among the oil and gas industry and
other industries in supplying the energy and fuel requirements of
industrial, commercial, and individual consumers. Also, domestic
sources of oil and gas are subject to competition from foreign
sources. The Company competes in all of its activities with many
other companies having far greater financial and other resources.
In addition, the Company competes with other sponsors of public
and private drilling partnerships and joint ventures for
investors.
Regulation
The Company's operations are affected in varying degrees by
political developments and Federal and state laws and
regulations. In particular, oil and gas production operations
and economics are affected by environmental, tax and other laws
relating to the petroleum industry, by changes in such laws, and
in administrative rules and regulations and in the interpretation
and application thereof.
In some areas where the Company conducts activities, there are
statutory provisions regulating oil and gas drilling and
production. Such statutes and regulations promulgated thereunder
require permits for drilling operations, drilling bonds and
reports to be filed concerning operations on production from oil
and gas wells.
Environmental Laws
The Company's activities are subject to existing Federal and
state laws and regulations governing environmental quality and
pollution control. Such laws and regulations may substantially
increase the costs of exploring for, developing or producing oil<PAGE>
<PAGE> 14
and gas and may prevent or delay the commencement or continuation
of a given operation. In the opinion of management, the
Company's operations comply with all applicable environmental
laws and regulations.
Federal Tax Laws
The Company's operations are significantly affected by certain
capital recovery and tax credit provisions of the Internal
Revenue Code (IRC), as amended, applicable to the oil and gas
industry. Current law permits the Company to deduct currently,
rather than capitalize, a portion of any intangible drilling
costs (IDC) incurred or borne by it. In addition, the IRC also
contains a provision benefiting certain producers of fuel from
non-conventional sources (the Section 29 credit), including
Devonian Shale formations. The current maximum Section 29 credit
is $5.68 per barrel of oil or equivalent ($.9793 per dekatherm of
natural gas) of qualified fuels. The Omnibus Budget
Reconciliation Act of 1990 (OBRA) extended the tax credit to
production from wells drilled through January 1, 1993 and
produced prior to January 1, 2003. OBRA also reinstated the
eligibility of production from tight sands formations for a
credit of $3.00 per barrel of oil or equivalent ($.5172 per
dekatherm of natural gas). The Company's ability to utilize
Section 29 credits generated is dependent upon its current
Federal tax liability. To the extent the credits generated
exceed the Company's current Federal tax liability, no carryback
or carryforward of benefits is permitted. (See Note 6 to the
accompanying consolidated financial statements).
The Company is also impacted by the alternative minimum tax (AMT)
rules of the IRC. AMT is calculated based on taxable income
under the regular tax provisions of the IRC adjusted for certain
preference items, principally depreciation, utilizing a 20% tax
rate. The Company is required to pay the higher of the amount
calculated utilizing the AMT rules or that calculated under the
regular provisions of the IRC. To the extent the AMT liability
exceeds the regular liability, a carryforward is permitted to
future tax years.
In August 1993, the Revenue Reconciliation Act of 1993 (RRA 1993)
was enacted into law. RRA 1993, among other changes, increased
the top marginal tax rate for corporations with taxable incomes
in excess of $10 million from 34 to 35 percent effective January
1, 1993, reduced or eliminated the ability to deduct certain
business expenses and eliminated certain preference items in the
calculation of the AMT effective January 1, 1994. Management
does not believe that RRA 1993 will have a material adverse
effect on the Company's operations or financial position for the
foreseeable future.
Executive Officers of Allegheny
The names, ages and positions of the executive officers and
significant employees of Allegheny are as follows:
Name Age Position Held <PAGE>
<PAGE> 15
John G. McMillian 68 Chairman of the
Board, President and
Chief Executive
Officer
W. Merwyn Pittman 62 Vice President,
Chief Financial
Officer and
Treasurer
Richard L. Grant 39 Secretary
Bradford C. Witmer 32 Controller
Corporate executive officers serve at the pleasure of the Board
of Directors.
The principal occupations for the past five years (and, in some
instances, for prior years) of each of the executive officers and
significant employees of the Company are as follows:
John G. McMillian - Mr. McMillian was elected Chairman of
the Board, and has served as Chairman, President and Chief
Executive Officer of the Company since July 1987. Mr.
McMillian owned and operated Burger Boat Company, Inc., a
yacht construction and repair company, from 1986 to 1989
and served as Chairman and Chief Executive Officer of
Northwest Energy Corporation from 1973 until 1983. He was
also a creator and principal U.S. sponsor of the Trans-
Alaska Natural Gas Transportation System, a 4,800 mile
pipeline that may someday deliver Alaska's vast gas
reserves to the lower 48 states. Prior to that, he was an
independent oil man with operations in the United States
and Canada. Mr. McMillian is also a director of Sun Bank,
Miami, N.A. and Marker International. He is the Chairman
of the Company's Executive Committee.
W. Merwyn Pittman - Mr. Pittman was appointed Vice
President, Chief Financial Officer and Treasurer in
October 1992. He also serves as Gas Access Systems'
President. From 1984-1992, Mr. Pittman was an oil and gas
consultant. Prior to that time, Mr. Pittman was employed
by Northwest Energy Corporation as Controller (1978-1981)
and Vice President of Administration (1982-1984).
Richard L. Grant - See "Executive Officers and Significant
Employees of Mountaineer Gas Company" below.
Bradford C. Witmer - Mr. Witmer joined Allegheny in
February 1990 as its Controller and also serves as the
Secretary of Gas Access Systems. Prior to that time, Mr.
Witmer was a manager in the Accounting and Financial
Services Division of Arthur Andersen & Co. where he was
employed since 1984. Mr. Witmer is a Certified Public
Accountant.
Executive Officers and Significant Employees of Mountaineer Gas
Company<PAGE>
<PAGE> 16
The names, ages, and positions of the executive officers and
significant employees of Mountaineer are as follows:
Name Age Position Held
Richard L. Grant 39 President
Michael S. Fletcher 45 Senior Vice
President, Chief
Financial Officer
and Secretary
Charles E. Hieronimus 64 Vice President of
Operations
Karen M. Macon 33 Vice President of
Marketing and
Regulatory Affairs
Deana L. Cooper 37 General Counsel
Roland C. Baer, Jr. 57 Treasurer
Dennis N. Emery 43 Controller
The principal occupations for the past five years (and, in some
instances, for prior years) of the executive officers and
significant employees of Mountaineer are as follows:
Richard L. Grant - Mr. Grant was appointed President of
Mountaineer in September 1988 and Secretary of Allegheny
in 1991. Mr. Grant joined Mountaineer as its Executive
Vice President in March 1986 with responsibility for
marketing, engineering, regulatory affairs and gas supply.
He was previously corporate counsel for Cincinnati Gas &
Electric Company for all natural gas matters and Federal
Energy Regulatory Commission proceedings. Mr. Grant is an
attorney and a licensed professional engineer. He is also
a director of AWENZ.
Michael S. Fletcher - Mr. Fletcher was appointed to the
position of Senior Vice President and Chief Financial
Officer of Mountaineer in October 1987. Prior to that
time, Mr. Fletcher was a partner of Arthur Andersen & Co.,
and was employed by that firm for 15 years. Mr. Fletcher
is also a Certified Public Accountant. He also serves as
Secretary of Mountaineer.
Charles E. Hieronimus - Mr. Hieronimus became Vice
President of Operations of Mountaineer in January 1989.
Mr. Hieronimus has served Mountaineer in various
capacities since 1949.
Karen M. Macon - Ms. Macon was appointed Vice President of
Marketing and Regulatory Affairs of Mountaineer in January
1991. Ms. Macon came to Mountaineer in February 1987 from
the Public Service Commission of West Virginia. Ms. Macon
is also a Certified Public Accountant.
Deana L. Cooper - Ms. Cooper was appointed General Counsel
of Mountaineer in February 1993. She joined Mountaineer
as a senior attorney in July 1990. Prior to joining
Mountaineer, Ms. Cooper was in private practice.<PAGE>
<PAGE> 17
Roland C. Baer, Jr. - Mr. Baer became Treasurer of
Mountaineer in January 1989. Mr. Baer has served
Mountaineer in various capacities since 1981.
Dennis N. Emery - Mr. Emery was appointed Controller of
Mountaineer in October 1988. Prior to that time, Mr.
Emery was associated with Arthur Andersen & Co. for nine
years where he served in several audit and administrative
positions. From 1982 to 1986, Mr. Emery served as
Financial Vice President of First Continental Life &
Accident Insurance Company, a Texas based life insurance
company.
Item 2. Properties
Utility Properties
Mountaineer owns and operates a gas distribution system
consisting of approximately 3,600 miles of underground
distribution mains, ranging in size from one inch to twenty
inches in diameter, together with service lines, and metering and
regulating equipment. The mains are located on easements or
private rights-of-way. In addition, Mountaineer owns equipment,
garages, offices, shops and various metering and regulating
buildings in its service area.
Mountaineer's investment in its distribution system is considered
suitable and adequate to deliver gas supplies to its consumers.
Mountaineer, as is typical within the industry, provides for an
ongoing maintenance and replacement program.
Transmission Facilities
MGS owns and operates approximately 274 miles of a natural gas
transmission system located in West Virginia. This transmission
system ranges in size from two to ten inches in diameter and is
located on easements or private rights-of-way.
Oil and Gas Field Offices
Allegheny's drilling and production operations are directed from
its offices in Charleston, West Virginia, with field operations
facilities in Chelyan, West Virginia.
MGS's producing operations are directed from its offices in
Charleston, West Virginia.
Reserves
Allegheny's oil and gas reserves as of June 30, 1994 have been
estimated by the independent petroleum engineering firms of
Wright & Company, Inc. and Forrest A. Garb & Associates, Inc.
MGS's gas reserves have been estimated by the firm of Wright &
Company, Inc.
The following table presents estimates of net proved reserves of
oil and gas (all of which are developed) for the periods<PAGE>
<PAGE> 18
indicated:
<TABLE>
Net Proved Developed Oil and Gas Reserves <F1>
<CAPTION>
Oil (Bbls) Gas (Mcf)
Allegheny Allegheny MGS
<S> <C> <C> <C>
Balance, June 30, 1991 <F2> 136,000 19,432,000 ---
Revisions of previous
estimates (15,000) (3,350,000) ---
Extensions, discoveries
and other additions --- 159,000 ---
Production (62,000) (1,489,000) ---
Sales of reserves in
place (17,000) (11,000) ---
---------- ---------- ----------
Balance, June 30, 1992 <F2> 42,000 14,741,000 ---
Revisions of previous
estimates 2,000 (360,000) ---
Production (5,000) (1,247,000) (271,000)
Purchases of reserves
in place --- --- 13,484,000
---------- ---------- ----------
Balance June 30, 1993 <F2> 39,000 13,134,000 13,213,000
Revisions of previous
estimates (6,000) 2,101,000 1,824,000
Production (5,000) (1,119,000) (1,906,000)
Purchases of reserves
in place --- 60,000 ---
Sales of reserves in
place --- (639,000) ---
---------- ---------- ----------
Balance, June 30, 1994 28,000 13,537,000 13,131,000
========== ========== ==========
<FN>
<F1> The estimates include only those amounts considered to be
proved reserves and do not include additional amounts that
may result from extensions of currently proved areas or
amounts that may result from new discoveries in the future.
Proved developed reserves are those reserves that are
expected to be recovered through existing wells with
existing equipment and operating methods.
<F2> Independent petroleum engineers providing the estimates for
these years are indicated in the Company's Annual Report on
Form 10-K for such years.
</FN>
/TABLE
<PAGE>
<PAGE> 19
In fiscal 1992, the Company changed the method by which it
computes its net proved reserves of oil and gas attributable to
the Company's interest in producing properties in which other
third parties participate. Beginning in fiscal 1992, the Company
has determined the economic life of such reserves based, in part,
upon operating costs that include general and administrative
expenses charged to such properties. Prior to fiscal 1992, the
Company excluded such expenses when determining economic life.
This change reduced the economic life, which, in turn, reduced
the estimated reserves. This change resulted in a reduction of
approximately 2,400,000 Mcf in natural gas reserves and 16,000
Bbl in oil reserves, which is reflected in the above table within
the fiscal 1992 revision of previous estimates of reserves.
Pursuant to regulations of the Department of Energy, Allegheny
filed with the U.S. Department of Energy Form EIA 23 -- Annual
Report of Proved Domestic Gas Reserves for the previous fiscal
year. The reserve information furnished to the U.S. Department
of Energy is consistent with the reserve information set forth
above. Allegheny has not filed oil or gas reserve information
with any other federal or foreign governmental agency during the
past year.
Item 3. Legal Matters
Cameron Gas Company and C. Richard Coleman, et al. vs. Allegheny
& Western Energy Corporation, Mountaineer Gas Company and Gas
Access Systems, Inc. was filed on December 31, 1992, in the
Circuit Court of Marshall County, West Virginia. Plaintiffs
allege unlawful and/or tortious conduct and violations of the
Racketeer Influenced and Corrupt Organizations Act (RICO) and the
West Virginia Anti-Trust Act, arising out of the termination of a
gas sales agreement and seek $30 million compensatory damages and
$90 million punitive damages. Upon the petition of the Company,
the case was removed to the United States District Court for the
Northern district of West Virginia. On February 19, 1993, the
Company filed responsive dispositive pleadings to the complaint,
including a motion to dismiss. By Order issued March 31, 1994,
and clarified by Order issued April 18, 1994, the West Virginia
anti-trust claim against Allegheny & Western Energy Corporation,
Mountaineer Gas Company and Gas Access Systems, Inc. was
dismissed with prejudice. In addition, the RICO claim was
dismissed against Allegheny & Western Energy Corporation with
prejudice. On April 14, 1994, Mountaineer filed a general denial
to plaintiffs' complaint and a counterclaim seeking at least
$150,000 in compensatory and $2.0 million in punitive damages for
the willful withholding by Cameron of monies collected by Cameron
as agent for certain of the Company's customers and intended to
be paid to the Company for services rendered by the Company. In
response to the April 18, 1994 Order, the plaintiffs filed an
amended complaint to which the Company has filed responsive
pleadings, including a motion to dismiss, and a counterclaim.
The pleadings remain pending before the Court for disposition.
Discovery has commenced. No trial date has been set. The
Company believes Cameron's claims are without merit and plans to
vigorously defend this matter and does not believe that this
matter is reasonably likely to have a material adverse effect on<PAGE>
<PAGE> 20
the financial position and results of operations of the Company.
The Company has been named as a defendant in various other legal
actions which arise primarily in the ordinary course of business.
In management's opinion, the outcome of such actions will not
have a material effect on the financial position and results of
operations of the Company.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of security holders during
the fourth quarter of the fiscal year covered by this report.
PART II
Item 5. Market for the Registrant's Common Stock and Related
Security Holder Matters
The Company's common stock is traded over-the-counter under the
NASDAQ symbol ALGH, on the NASDAQ National Market System. As of
June 30, 1994, there were approximately 2,400 holders of record
of the Company's common stock.
The reported high and low bid prices of the Company's common
stock as reported by NASDAQ for each quarter for the periods
indicated through June 30, 1994, are as follows:
<TABLE>
<CAPTION>
High Low
<S> <C> <C>
Fiscal 1993
July 1 - September 30, 1992 $ 6-5/8 $ 5-1/8
October 1 - December 31, 1992 7-1/8 6-1/4
January 1 - March 31, 1993 8-21/32 6-1/2
April 1 - June 30, 1993 9-3/4 7-3/4
Fiscal 1994
July 1 - September 30, 1993 $ 10-3/4 $ 7-5/8
October 1 - December 31, 1993 8-5/8 6-3/8
January 1 - March 31, 1994 8-7/8 6-5/8
April 1 - June 30, 1994 9-1/8 7-1/4
</TABLE>
The over-the-counter market quotations reflect inter-dealer
prices, without retail mark-up, mark-down or commission and may
not necessarily represent actual transactions.
DIVIDENDS
On October 6, 1988, the Company announced that it would
discontinue the payment of cash dividends on its common stock for
the foreseeable future. The dividend policy of the Company is<PAGE>
<PAGE> 21
reviewed each quarter and is subject to change by the Company;
however, under the terms of the Company's Term Credit and
Revolving Credit Agreement, signed on September 24, 1990, the
Company may not declare dividends in excess of 25% of cumulative
consolidated net income after June 30, 1990. (See Note 4 to the
accompanying consolidated financial statements.)<PAGE>
<PAGE> 22
<TABLE>
Item 6. Selected Financial Data <F1>
<CAPTION>
Allegheny & Western Energy Corporation and Subsidiaries
Fiscal Year Ended June 30,
INCOME STATEMENT
DATA 1994 1993 1992 1991 1990
<S> <C> <C> <C> <C> <C>
Total revenues $204,475,534 $185,534,169 $182,255,636 $187,454,769 $188,360,509
Total costs
and expenses 195,168,095 180,550,254 178,384,872 192,634,343 187,553,186
------------ ------------ ------------ ------------ ------------
Income (loss)
before taxes on
income and
cumulative
effect of change
in accounting
principle 9,307,439 4,983,915 3,870,764 (5,179,574) 807,323
Provision (benefit)
for income taxes 1,867,859 1,237,933 196,296 (2,651,138) (2,176,781)
------------ ------------ ------------ ------------ ------------
Income (loss)
before cumulative
effect of change
in accounting
principle 7,439,580 3,745,982 3,674,468 (2,528,436) 2,984,104
Cumulative effect
prior to July 1,
1993 of change
in method of
accounting for
income taxes 1,562,156 --- --- --- ---
------------ ------------ ------------ ------------ ------------
Net income (loss) $ 9,001,736 $ 3,745,982 $ 3,674,468 $ (2,528,436) $ 2,984,104
============ ============ ============ ============
Per share:
Income (loss)
before cumulative
effect of change
in accounting
principle $ .97 $ .47 $ .45 $ (.31) $ .37
Cumulative effect
prior to July 1,
1993 of change
in method of
accounting for <PAGE>
<PAGE> 23
income taxes .20 --- --- --- ---
------------ ------------ ------------ ------------ ------------
Net income (loss) $ 1.17 $ .47 $ .45 $ (.31) $ .37
============ ============ ============ ============ ============
Cash dividends
per share $ --- $ --- $ --- $ --- $ ---
============ ============ ============ ============ ============
Weighted average
number of
common shares
outstanding 7,673,268 8,013,970 8,083,188 8,083,188 8,083,188
============ ============ ============ ============ ============
Allegheny & Western Energy Corporation and Subsidiaries
d
BALANCE SHEET DATA June 30, June 30, June 30, June 30, June 30,
1994 1993 1992 1991 1990
Total assets $216,609,128 $195,680,299 $197,247,258 $180,383,633 $190,725,728
Long-term debt,
less current
maturities $ 25,680,000 $ 32,430,000 $ 39,180,000 $ 45,930,000 $ 49,104,636
Stockholders'
equity $101,659,969 $ 96,042,741 $ 94,010,900 $ 90,336,432 $ 92,864,868
<FN>
<F1> This information should be read in conjunction with the consolidated financial
statements (Item 8) and management's discussion and analysis of financial condition
and results of operations (Item 7) appearing elsewhere herein.
</FN>
/TABLE
<PAGE>
<PAGE> 24
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations
RESULTS OF OPERATIONS - FISCAL 1994 COMPARISON TO FISCAL 1993
Gas Distribution and Marketing Operations
Gas distribution revenues are derived from Allegheny's wholly-
owned subsidiaries, Mountaineer Gas Company (Mountaineer), a
regulated utility, Gas Access Systems, Inc. (G.A.S.), a gas
marketing company, as well as from Mountaineer's wholly-owned
subsidiary, Mountaineer Gas Services, Inc. (MGS), a producer and
marketer of natural gas. Total gas distribution and marketing
revenues for such subsidiaries increased by approximately $17.0
million during fiscal 1994.
Net gas distribution revenues for Mountaineer increased $9.8
million during fiscal 1994. During this period, Mountaineer
recorded a $17 million charge to revenues relating to
Mountaineer's passthrough to its customers of refunds received
from Mountaineer's pipeline suppliers. This $17 million charge
was offset by a corresponding decrease in cost of gas
distributed. The increased revenues were primarily related to
increased volumes of gas sold due to colder weather conditions in
its service area and, to a lesser extent, increased base and
purchased gas adjustment rates which became effective November
1, 1993. This increase was partially offset by small commercial
customers obtaining transportation services in lieu of purchasing
gas supplies from Mountaineer. (See table of Mountaineer's
operating revenues and related volumes contained in Item 1.)
Gas distribution revenues of G.A.S. increased approximately $1.6
million during fiscal 1994. This increase was attributable to
improved sales prices due to industry market conditions and
higher sales volumes due to colder weather in G.A.S.'s service
area.
MGS began operating the assets purchased from Hallwood on April
1, 1993. These assets included the assumption of several sales
contracts with large volume customers. The sales revenues
generated by these contracts increased approximately $5.6
million during fiscal 1994 due primarily to MGS's operations
being in place for all of fiscal 1994 versus only three months
of fiscal 1993.
Oil and Gas Operations
Revenues relating to oil and gas operations are derived from the
activities of Allegheny and MGS and, prior to fiscal 1993,
Allegheny's wholly-owned Texas subsidiary, TEX-HEX. Allegheny's
and MGS's operations are located in the Appalachian Basin of West
Virginia. TEX-HEX's operations were located in south Texas.
Oil and gas sales increased approximately $2.3 million during
fiscal 1994. Oil and gas sales of MGS increased approximately
$2.4 million during fiscal 1994 due primarily to MGS's
operations being in place for all of fiscal 1994 versus only<PAGE>
<PAGE> 25
three months of fiscal 1993. Oil and gas sales of Allegheny
decreased approximately $.1 million during fiscal 1994 as reduced
production volumes were virtually offset by higher average sales
prices.
Field Services
Field service revenues include amounts charged for the
administration and operation of producing properties, the
operation of pipeline systems and amounts charged for management
of drilling operations.
Field service revenues of Allegheny decreased approximately $.1
million during fiscal 1994 as a result of a reduction in gas
transportation revenues due to lower throughput volumes.
Investment and Other Income
Investment income is earned primarily from investments in short-
term repurchase agreements, bond funds, commercial paper and
United States Treasury obligations.
Investment and other income decreased approximately $.3 million
during fiscal 1994. This decrease was attributable to reduced
cash available for investment by Mountaineer due to capital
expenditure and working capital requirements and reduced cash
available for investment by Allegheny due to purchases of
treasury stock pursuant to its previously announced stock
repurchase program.
OPERATING COSTS AND EXPENSES
Cost of Gas Distributed/Marketed
Cost of gas distributed/marketed includes the cost of gas
recovered by Mountaineer from its customers as permitted in its
purchased gas adjustment clause provided for by state regulatory
provisions and the cost of gas purchased by G.A.S. and MGS for
resale to their respective customers. Total costs of gas
distributed/marketed by Allegheny's direct and indirect
subsidiaries increased approximately $9.3 million during fiscal
1994.
Costs of gas distributed by Mountaineer increased approximately
$2.7 million from fiscal 1993 to fiscal 1994. During this
period, Mountaineer recorded a $17 million charge to cost of gas
distributed relating to Mountaineer's passthrough to its
customers of refunds received from Mountaineer's pipeline
suppliers. This $17 million charge was offset by a corresponding
charge to gas distribution revenues. The increase was primarily
a result of increased volumes of gas sold due to colder weather
conditions in Mountaineer's service area and increased purchased
gas adjustment rates which became effective November 1, 1993.
Gas costs of G.A.S. increased approximately $1.4 million from
fiscal 1993 to fiscal 1994. This increase resulted from
increased volumes of gas sold due to colder weather conditions in<PAGE>
<PAGE> 26
G.A.S.'s service area and higher market prices as a result of
industry market conditions.
MGS purchased gas costs increased approximately $5.2 million
during fiscal 1994 due primarily to MGS's operations being in
place for all of fiscal 1994 versus only three months of fiscal
1993.
Exploration, Lease Operating and Production Expenses
Exploration, lease operating and production expenses include
costs incurred by Allegheny and MGS and formerly by TEX-HEX in
conducting field operations for producing properties and in
exploring for potential new sources of oil and gas reserves.
Exploration, lease operating and production expenses increased
approximately $.9 million from fiscal 1993 to fiscal 1994. MGS's
lease operating and production expenses increased approximately
$1.1 million during fiscal 1994 due primarily to MGS's
operations being in place for all of fiscal 1994 versus only
three months of fiscal 1993. Allegheny's expenses decreased
approximately $.2 million during fiscal 1994 as a result of
decreases in various categories of production expenses.
Distribution, General and Administrative Expenses
Distribution, general and administrative expenses increased
approximately $3.9 million during fiscal 1994 as compared to
fiscal 1993. This was primarily the result of increased expenses
of Mountaineer associated with normal increases in employee labor
and employee benefit costs. Additionally, approximately $.6
million of the increase is attributable to the adoption of the
Financial Accounting Standards Board's Statement of Financial
Accounting Standards (SFAS) No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions". See Note 8 to the
accompanying consolidated financial statements.
Depletion, Depreciation and Amortization
Depletion, depreciation and amortization expenses increased
approximately $.5 million during fiscal 1994. This increase was
primarily a result of depreciation on fiscal 1994 utility plant
additions of Mountaineer and increased depletion recorded by MGS
for fiscal 1994 due to MGS's operations being in place for all of
fiscal 1994 compared to only three months of fiscal 1993.
Interest Expense
Total interest expense remained unchanged during fiscal 1994 as
Mountaineer's higher average outstanding short-term borrowings
during fiscal 1994 were offset by a reduction in long-term debt
outstanding during fiscal 1994. Mountaineer's increase in short-
term borrowings were due to working capital and capital
expenditure requirements.
Income Taxes
The effective income tax rate was 20.1% for fiscal 1994 and 24.8%<PAGE>
<PAGE> 27
for fiscal 1993. The recorded income tax provision reflects the
40% net statutory rate for Federal and state purposes, offset
primarily by Federal tax credits permitted for fuels produced
from a non-conventional source and the benefit from book
amortization of an acquisition adjustment. The decrease in the
effective rate for fiscal 1994 reflects increased estimated
utilization of Federal tax credits based on anticipated levels of
Federal taxable income.
Cumulative Effect of Change in Accounting Principle
Effective July 1, 1993, the Company changed its method of
accounting for income taxes as required by SFAS No. 109,
"Accounting for Income Taxes". As permitted by SFAS No. 109, the
Company recognized the cumulative effect prior to July 1, 1993 of
the change in the method of accounting for income taxes in the
period of adoption. Accordingly, the Company reflected a credit
of $1,562,000 in the first quarter of fiscal 1994. This amount
was primarily the result of reduced currently enacted tax rates
compared to those in effect at the time deferred taxes were
recognized for certain differences between financial reporting
and tax bases of assets and liabilities.
RESULTS OF OPERATIONS - FISCAL 1993 COMPARISON TO FISCAL 1992
Gas Distribution and Marketing Operations
Total gas distribution and marketing revenues increased by
approximately $4.7 million during fiscal 1993. Gas distribution
revenues for Mountaineer increased $1.8 million during fiscal
1993. This increase was caused primarily by the recording in
fiscal 1992 of a reduction in revenues to reflect the cumulative
effect of reduced take-or-pay billings to certain classes of
customers totalling $3.8 million pursuant to a final order issued
by the Public Service Commission of West Virginia (March 1992
Final Order) in March 1992. This adjustment to revenues was
offset by a corresponding credit to purchased gas costs. This
increase was partially offset by decreased volumes of gas sold as
a result of smaller commercial customers switching to
transportation service from gas sales service during fiscal 1993.
(See table of Mountaineer's operating revenues and related
volumes contained in Item 1.)
Gas distribution revenues of G.A.S. increased approximately $.7
million during fiscal 1993. This increase was attributable to
improved sales prices as a result of industry market conditions.
This increase was partially offset by lower volumes sold
resulting primarily from a decision to not renew several
marginally profitable large-volume sales contracts during fiscal
1992.
MGS began operating the assets purchased from Hallwood on April
1, 1993. These assets included the assumption of several sales
contracts with large volume customers. These contracts generated
sales revenues of approximately $1.9 million during the three
months ended June 30, 1993.<PAGE>
<PAGE> 28
Oil and Gas Operations
Oil and gas sales decreased approximately $.6 million during
fiscal 1993. This decrease is primarily attributable to the
cessation by TEX-HEX of all oil and gas producing operations in
April 1992. TEX-HEX had oil and gas sales of $1.1 million in
fiscal 1992. Oil and gas sales of Allegheny decreased $.2
million during fiscal 1993 as a result of normal production
declines partially offset by improved average sales prices. The
above decreases were partially offset by $.7 million in oil and
gas sales by MGS which began operations in April 1993.
Field Services
Field service revenues decreased approximately $.3 million during
fiscal 1993. These decreases resulted primarily from the
discontinuance of TEX-HEX's operations and a reduction in
Allegheny's gas transportation revenues resulting from lower
throughput volumes.
Investment and Other Income
Investment and other income decreased approximately $.5 million
during fiscal 1993. This decrease was mainly attributable to the
recording in fiscal 1992 of a non-recurring $.3 million credit
relating to carrying costs associated with the recovery of take-
or-pay charges which Mountaineer was permitted to recover
pursuant to the March 1992 Final Order. In addition, Mountaineer
had reduced levels of cash available for investment due to
capital expenditure and working capital requirements.
OPERATING COSTS AND EXPENSES
Cost of Gas Distributed/Marketed
Total costs of gas distributed/marketed increased approximately
$2.6 million during fiscal 1993. Costs of gas distributed by
Mountaineer decreased approximately $.6 million from fiscal 1992
to fiscal 1993. This decrease was due to smaller commercial
customers switching to transportation service from gas sales
service and the elimination of the recovery of take-or-
pay/contract reformation costs for several customer classes.
These decreases were partially offset by the cumulative effect of
reduced take-or-pay billings to certain classes of customers
totalling $3.8 million which were recorded in March and April of
1992 as a result of the March 1992 Final Order.
Gas costs of G.A.S. increased approximately $1.0 million from
fiscal 1992 to fiscal 1993. This increase resulted primarily
from higher market prices due to industry market conditions.
This increase was partially offset by overall lower sales volumes
resulting from a decision to not renew several marginally
profitable large-volume sales contracts in fiscal 1992.
MGS incurred purchased gas costs of $2.1 million during its three
months of operations in fiscal 1993.<PAGE>
<PAGE> 29
Exploration, Lease Operating and Production Expenses
Exploration, lease operating and production expenses decreased
approximately $1.1 million from fiscal 1992 to fiscal 1993. This
reduction is primarily the result of TEX-HEX ceasing all field
operations in April 1992. In addition, Allegheny's expenses
decreased approximately $.5 million during fiscal 1993 as a
result of reductions in its West Virginia field operations
workforce in February 1992 and decreases in various other
categories of production expenses. These decreases were
partially offset by MGS's lease operating and production expenses
of $.4 million incurred during its three months of operations.
Distribution, General and Administrative Expenses
Distribution, general and administrative expenses increased
approximately $.3 million during fiscal 1993 as compared to
fiscal 1992. This was primarily the result of increased expenses
of Mountaineer associated with normal increases in employee labor
costs. These increases were partially offset by the closure of
TEX-HEX's Houston, Texas office which incurred approximately $.8
million of expenses during fiscal 1992.
Depletion, Depreciation and Amortization
Depletion, depreciation and amortization expenses decreased
approximately $.3 million during fiscal 1993. This decrease was
primarily the result of the sale of substantially all of TEX-
HEX's assets during the fourth quarter of fiscal 1992 and lower
volumes produced by Allegheny. This decrease was partially
offset by depreciation on fiscal 1993 utility plant additions and
depletion recorded by MGS during its three months of operations.
Interest Expense
Total interest expense increased $.7 million in fiscal 1993.
This increase was primarily the result of Mountaineer having
higher average outstanding borrowings during fiscal 1993 as a
result of capital expenditure and working capital requirements.
These increases were partially offset by lower interest rates in
effect during fiscal 1993.
Income Taxes
The effective income tax rate was 24.8% for fiscal 1993 and 5.1%
for fiscal 1992. The recorded income tax provision reflects the
40% net statutory rate for Federal and state purposes, offset
primarily by Federal tax credits permitted for fuels produced
from a non-conventional source and the benefit from the book
amortization of an acquisition adjustment. The increase in the
effective rate for fiscal 1993 reflects reduced estimated
utilization of Federal tax credits based on anticipated levels of
Federal taxable income.
LIQUIDITY AND CAPITAL RESOURCES
Short-Term Borrowings and Lines-of-Credit<PAGE>
<PAGE> 30
Mountaineer had unsecured short-term line-of-credit agreements
with banks totaling $57.5 million as of June 30, 1994.
Borrowings on these lines-of-credit are anticipated to be used
primarily to finance gas purchases and provide working capital
during Mountaineer's peak sales period. As of June 30, 1994,
$18,703,000 was outstanding under these lines-of-credit. In
addition, Mountaineer has an additional $15 million revolving
line-of-credit facility which is available for borrowing until
December 31, 1996.
Allegheny has a revolving credit facility with two banks
totalling $5 million. The $5 million revolving credit facility
is anticipated to be used primarily to finance working capital
needs (see Notes 4 and 5 to the accompanying consolidated
financial statements). No borrowings were made under this
facility in fiscal 1994.
Mountaineer and Allegheny's lines-of-credit are typically in
effect for a period of one year and are renewed on a year-to-year
basis.
Working Capital
Working capital ratios are a measure of a company's ability to
meet its short-term obligations. The following table shows the
Company's consolidated working capital as of the dates shown:
<TABLE>
<CAPTION>
June 30, June 30, June 30,
1994 1993 1992
<S> <C> <C> <C>
Working capital $(10,979,850) $ (3,003,194) $ 18,805,084
Working capital ratio 0.83 to 1 0.94 to 1 1.40 to 1
</TABLE>
The deficiency in working capital at June 30, 1994 is
attributable to Mountaineer's requirement of significant working
capital funds to finance the acquisition of the West Virginia
assets of Hallwood by MGS in fiscal 1993 and to fund fiscal 1994
capital expenditures. Management believes it has sufficient
lines-of-credit in place to meet maturities of long-term debt and
working capital requirements.
Capital Expenditures
Capital expenditures were approximately $13.3 million and $22.3
million for the fiscal years ended June 30, 1994 and 1993.
Substantially all of the Company's fiscal 1994 capital
expenditures were attributable to the Company's gas distribution
operations. Such expenditures were financed primarily by<PAGE>
<PAGE> 31
internally generated funds and short-term borrowings.
Fiscal 1995 Expenditures
The extent of Allegheny's drilling activities in fiscal 1995, if
any, will depend upon, among other factors, the market price of
natural gas, Allegheny's available funds, Allegheny's ability to
raise funds in the capital markets and Allegheny's ability to
attract industry partners. While Allegheny's plans are subject
to change in light of the foregoing, management does not
currently anticipate that Allegheny will undertake any new
exploration or development drilling during fiscal 1995.
Allegheny is continuing to seek attractive acquisition candidates
in order to expand its operations; however it is impossible to
determine what expenditures may be required to fund these
activities, if successful.
Utility construction expenditures are estimated to be
approximately $13.7 million.
MGS's natural gas drilling expenditures are expected to be $1.0
million.
Management believes that the Company has sufficient internally
generated funds, working capital resources and lines-of-credit to
meet these anticipated capital expenditures.
Dividend Restrictions
Mountaineer's outstanding debt obligations restrict the amount of
dividends that Mountaineer can pay to the Company (see Note 4 to
the accompanying consolidated financial statements). As of June
30, 1994, under the most restrictive terms of its debt
obligations, Mountaineer would be permitted to pay dividends of
$11.7 million to the Company. The limitations on Mountaineer's
ability to pay dividends are not expected to have a significant
impact on the Company's ability to meet its cash requirements.
Seasonality of Business
Mountaineer's retail gas distribution sales are highly seasonal
and fluctuate significantly dependent upon weather conditions
experienced in Mountaineer's service area. Typically, the
weather conditions result in higher operating revenues and net
income from October through March and lower operating revenues
and either net losses or reduced net income from April through
September. Weather conditions also have a significant impact on
Mountaineer's cash flow requirements. Typically, cash
expenditure requirements are greatest during May through January
in preparation for and during the winter heating season due to
gas purchase requirements. Cash inflows are at their highest
levels typically from January through April due to heating
requirements of Mountaineer's customers. Mountaineer utilizes
lines-of-credit and internally generated funds to meet its
seasonal capital requirements.
OTHER<PAGE>
<PAGE> 32
Impact of Inflation
Fluctuations in prices and costs are primarily a matter of supply
and demand with respect to oil and gas operations and, to a much
lesser degree, inflation. The inflationary impact on gas
distribution operations is considered in periodic rate cases. On
October 29, 1993, the PSCWV issued the October 1993 Order, which
was effective November 1, 1993, regarding Mountaineer's request
in January 1993 for increased base rates. The October 1993
Order, among other matters, provided for a 10.1% return on equity
and rate increases which would generate additional annual
revenues of approximately $3,400,000 under normal operating
conditions. In its original filing, Mountaineer requested a
return on equity of 12.3% and rate increases that would result in
increased annual revenues of $7,500,000. On November 8, 1993,
Mountaineer filed a petition for reconsideration of several
issues contained in the October 1993 Order, including the granted
rate of return on equity and the rate recovery mechanism of OPEB
costs. On March 30, 1994, the PSCWV issued the March 1994 Final
Order in this rate case, after reconsidering several issues
raised by various parties to the rate case. In the March 1994
Final Order the PSCWV granted an increase in the authorized
return on equity to 10.55% and established a tracking mechanism
for certain OPEB costs.
Statement of Financial Accounting Standards No. 109, "Accounting
for Income Taxes"
In February 1992, the Financial Accounting Standards Board (FASB)
issued Statement of Financial Accounting Standards (SFAS) No.
109, "Accounting for Income Taxes." The Company adopted the
provisions of SFAS No. 109 effective July 1, 1993 and elected not
to restate the financial statements of prior years. The adoption
of SFAS No. 109 required the Company to convert from the deferred
method to the liability method to recognize deferred taxes.
Under the liability method, deferred tax assets and liabilities
are determined based on differences between financial reporting
and tax bases of assets and liabilities and are measured using
the enacted tax rates and laws that will be in effect when the
differences are expected to reverse. Deferred tax assets and
liabilities are adjusted for future changes in tax rates. Under
the deferred method, deferred tax expense was based on items of
income and expense that were reported in different years in the
financial statements and tax returns and were measured at the tax
rate in effect in the year the difference originated. As
permitted by SFAS No. 109, the Company elected not to restate the
financial statements of any prior years, but to record the
cumulative effect of the change in accounting for income taxes in
the year of adoption. The recording of the cumulative effect of
this change in accounting for income taxes did not impact pre-tax
income from continuing operations; however, net income increased
approximately $1,562,000, or $.20 per share. The increase in net
income was primarily the result of reduced currently enacted tax
rates compared to those in effect at the time the deferred taxes
were previously recognized. The adoption of SFAS No. 109 by
Mountaineer resulted in an increase in accumulated deferred
income taxes which was offset by a corresponding increase in a<PAGE>
<PAGE> 33
regulatory asset account, which resulted from the recording of
certain deferred taxes which were not previously recognized due
to state ratemaking practices. This amount (approximately
$8,539,000 at June 30, 1994) has been reflected in other assets.
Statement of Financial Accounting Standards No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions"
Effective July 1, 1993, Mountaineer adopted SFAS No. 106,
"Employers Accounting for Postretirement Benefits Other Than
Pensions" (OPEB). SFAS No. 106 significantly changes the
accounting, measurement and disclosure practices with respect to
OPEB's. SFAS No. 106 requires that the expected cost of OPEB's
be charged to expense during the period of an employee's service
rather than expensing such costs as claims are incurred. Under
Mountaineer's medical and life insurance plan for retired
employees, the attribution period is equivalent to the 10-year
period prior to the employee reaching eligible retirement age.
As permitted by SFAS No. 106, Mountaineer has elected to amortize
the accumulated postretirement benefit obligation existing at the
date of adoption ("transition obligation") over a 20-year period.
Prior to fiscal 1994, Mountaineer recognized postretirement
health care and life insurance benefits in the year the benefits
were paid. The cost of retirees' benefits paid in fiscal 1994,
1993 and 1992 was approximately $297,000, $525,000 and $347,000,
respectively. Retiree benefits recognized by Mountaineer
pursuant to the requirements of SFAS No. 106 were $1,117,000 in
fiscal 1994.
As part of the October 1993 Order, the PSCWV ruled that the
permitted rate recovery mechanism for OPEB's will be a modified
accrual method (see Note 8 to the accompanying consolidated
financial statements). The modified accrual method allows for
the recovery of current service costs on an accrual basis and
recovery of the transition obligation on a cash basis.
Accounting for the transition obligation on a cash method is not
an acceptable accounting method under generally accepted
accounting principles. Mountaineer is recording its other
postretirement benefit expense in accordance with SFAS No. 106,
which is in excess of the permitted rate recovery as a result of
the PSCWV's ruling. Mountaineer currently estimates that the
amount of SFAS No. 106 expense (net of those amounts expected to
be capitalized) in excess of the modified accrual basis would be
approximately $300,000 in fiscal 1995 and would accumulate to
approximately $3,000,000 over the remaining nineteen year
amortization period for transition costs. These amounts will be
recovered through rates in later years when the cash basis of
prior service costs exceeds the accrual basis of such costs.
Statement of Financial Accounting Standards No. 112, "Employers'
Accounting for Postemployment Benefits"
In November 1992, the FASB issued SFAS No. 112, "Employers
Accounting for Postemployment Benefits." This statement requires
employers to recognize any obligation which exists to provide
benefits to former or inactive employees after employment, but
before retirement. Such benefits include, but are not limited to,<PAGE>
<PAGE> 34
salary continuations, supplemental unemployment, severance
disability (including workers' compensation), job training,
counseling and continuation of benefits such as health care and
life insurance. Currently, the Company provides only for
workers' compensation benefits which would qualify as
postemployment benefits under this standard.
The Company will adopt this statement in fiscal 1995. The
adoption of SFAS No. 112 is not expected to have a material
impact on the Company's results of operations.
Item 8.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Consolidated Financial Statements - Allegheny &
Western Energy Corporation and Subsidiaries
Report of Independent Public Accountants 26
Consolidated Balance Sheets as of June 30, 1994
and 1993 27
Consolidated Statements of Income for the Years
Ended June 30, 1994, 1993 and 1992 29
Consolidated Statements of Changes in
Stockholders' Equity for the Years Ended
June 30, 1994, 1993 and 1992 30
Consolidated Statements of Cash Flows for the
Years Ended June 30, 1994, 1993 and 1992 31
Notes to Consolidated Financial Statements 32
Report of Independent Public Accountants
To the Directors and Stockholders of
Allegheny & Western Energy Corporation:
We have audited the accompanying consolidated balance sheets of
ALLEGHENY & WESTERN ENERGY CORPORATION (a West Virginia
corporation) and subsidiaries as of June 30, 1994 and 1993 and
the related consolidated statements of income, changes in
stockholders' equity and cash flows for each of the three years
in the period ended June 30, 1994. These consolidated financial
statements and the schedules referred to below are the
responsibility of the Company's management. Our responsibility<PAGE>
<PAGE> 35
is to express an opinion on these consolidated financial
statements and 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, the consolidated financial statements referred to
above present fairly, in all material respects, the financial
position of Allegheny & Western Energy Corporation and
subsidiaries as of June 30, 1994 and 1993, and the results of
their operations and their cash flows for each of the three years
in the period ended June 30, 1994, in conformity with generally
accepted accounting principles.
As discussed in Notes 6 and 8, effective July 1, 1993, the
Company changed its method of accounting for income taxes and
other postretirement benefits pursuant to standards promulgated
by the Financial Accounting Standards Board.
Our audits were made for the purpose of forming an opinion on the
basic consolidated financial statements taken as a whole. The
schedules listed under Item 14(a)(2) are presented for purposes
of complying with the Securities and Exchange Commission's rules
and are not a required part of the basic consolidated financial
statements. These schedules have been subjected to the auditing
procedures applied in our audits of the basic consolidated
financial statements and, in our opinion, fairly state, in all
material respects, the financial data required to be set forth
therein in relation to the basic consolidated financial
statements taken as a whole.
Arthur Andersen LLP
Houston, Texas,
August 24, 1994.
<TABLE>
ALLEGHENY & WESTERN ENERGY CORPORATION
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
CAPTION
<PAGE>
<PAGE> 36
June 30, June 30,
ASSETS 1994 1993
<S> <C> <C>
CURRENT ASSETS:
Cash and equivalents $ 5,610,788 $ 10,931,400
Short-term investments 3,142,062 ---
Accounts receivable (less
allowance for doubtful
accounts of $1,429,308 and
$1,307,204, respectively) 23,538,907 21,976,189
Inventory 16,468,135 5,097,310
Prepayments 1,287,853 5,789,961
Deferred income taxes 3,020,686 2,726,462
Other 51,376 55,341
------------- -------------
Total current assets 53,119,807 46,576,663
------------- -------------
PROPERTY, PLANT AND EQUIPMENT,
at cost:
Utility plant 149,245,869 137,737,323
Oil and gas properties
(successful efforts method) 51,773,293 56,654,989
Transmission plant 4,970,215 4,736,819
Other 7,532,881 7,295,024
------------- -------------
213,522,258 206,424,155
Less-accumulated depletion,
depreciation and amortization 65,765,042 62,105,412
------------- -------------
Property, plant and
equipment, net 147,757,216 144,318,743
------------- -------------
OTHER ASSETS 15,732,105 4,784,893
------------- -------------
Total assets $ 216,609,128 $ 195,680,299
============= =============
<FN>
The accompanying notes are an integral part of these consolidated
balance sheets.
</FN>
</TABLE>
<TABLE>
ALLEGHENY & WESTERN ENERGY CORPORATION
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS<PAGE>
<PAGE> 37
<CAPTION>
June 30, June 30,
LIABILITIES AND STOCKHOLDERS'
EQUITY 1994 1993
<S> <C> <C>
CURRENT LIABILITIES:
Current maturities of long-term
debt $ 6,750,000 $ 6,750,000
Short-term borrowings 18,702,900 7,638,700
Accounts payable 19,126,454 20,716,857
Overrecovered gas costs 6,034,251 6,497,686
Accrued taxes 5,018,121 2,101,709
Accrued liabilities and other 8,467,931 5,753,377
------------- -------------
Total current liabilities 64,099,657 49,458,329
NONCURRENT LIABILITIES:
Long-term debt, net of current
maturities 25,680,000 32,430,000
Deferred income taxes 19,419,268 13,841,450
Other 5,750,234 3,907,779
------------- -------------
Total liabilities 114,949,159 99,637,558
------------- -------------
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY:
Preferred stock, without par
value; authorized 5,000,000
shares; no shares issued or
outstanding --- ---
Common stock $.01 par value;
authorized 20,000,000 shares;
8,108,802 shares issued,
7,479,360 and 7,867,338 shares
outstanding, respectively 81,088 81,088
Additional paid-in capital 36,787,791 36,787,791
Retained earnings 70,073,501 61,071,765
------------- -------------
106,942,380 97,940,644
Less-treasury stock, at cost,
629,442 and 241,464 shares,
respectively 5,282,411 1,897,903
------------- -------------
Total stockholders' equity 101,659,969 96,042,741
------------- -------------
Total liabilities and
stockholders' equity $ 216,609,128 $ 195,680,299
============= =============
<FN>
The accompanying notes are an integral part of these consolidated
balance sheets.
</FN>
/TABLE
<PAGE>
<PAGE> 38<PAGE>
<PAGE> 39
<TABLE>
ALLEGHENY & WESTERN ENERGY CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
<CAPTION>
Year Ended Year Ended Year Ended
June 30, June 30, June 30,
1994 1993 1992
<S> <C> <C> <C>
REVENUES:
Gas distribution and marketing $ 196,510,996 $ 179,488,735 $ 174,813,007
Oil and gas sales 5,775,365 3,486,195 4,114,711
Field services 2,026,088 2,122,441 2,431,213
Investment and other income 163,085 436,798 896,705
------------- ------------- -------------
204,475,534 185,534,169 182,255,636
------------- ------------- -------------
COSTS AND EXPENSES:
Cost of gas distributed/marketed 128,878,520 119,622,794 117,032,132
Exploration, lease operating and
production 3,753,732 2,819,447 3,962,525
Distribution, general and administrative 49,585,607 45,646,986 45,375,383
Depletion, depreciation and amortization 8,660,537 8,156,757 8,443,839
Interest 4,289,699 4,304,270 3,570,993
------------- ------------- -------------
195,168,095 180,550,254 178,384,872
------------- ------------- -------------
Income before income taxes and
cumulative effect of change in
accounting principle 9,307,439 4,983,915 3,870,764
Provision for income taxes (Note 6) 1,867,859 1,237,933 196,296
------------- ------------- -------------
Income before cumulative effect of
change in accounting principle 7,439,580 3,745,982 3,674,468
Cumulative effect prior to July 1, 1993
of change in method of accounting for
income taxes (Note 6) 1,562,156 --- ---
------------- ------------- -------------
Net income $ 9,001,736 $ 3,745,982 $ 3,674,468
============= ============= =============
Per share:
Income before cumulative effect of
change in accounting principle $ .97 $ .47 $ .45
Cumulative effect prior to July 1, 1993
of change in method of accounting for
income taxes (Note 6) .20 --- ---
------------- ------------- -------------
Net income $ 1.17 $ .47 $ .45
============= ============= =============
Weighted average number of common shares<PAGE>
<PAGE> 40
outstanding 7,673,268 8,013,970 8,083,188
============= ============= =============
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
</FN>
</TABLE>
<TABLE>
ALLEGHENY & WESTERN ENERGY CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
<CAPTION>
Common Stock
Additional
Number Paid-in Retained Treasury
of Shares Amount Capital Earnings Stock
<S> <C> <C> <C> <C> <C>
Balance, June 30, 1991 8,108,802 $ 81,088 $ 36,787,791 $ 53,651,315 $ (183,762)
Net income --- --- --- 3,674,468 ---
------------ ------------ ------------ ------------ -----------
Balance, June 30, 1992 8,108,802 81,088 36,787,791 57,325,783 (183,762)
Net income --- --- --- 3,745,982 ---
Acquisition of
treasury stock
(215,850 shares) --- --- --- --- (1,714,141)
------------ ------------ ------------ ------------ -----------
Balance, June 30, 1993 8,108,802 81,088 36,787,791 61,071,765 (1,897,903)
Net income --- --- --- 9,001,736 ---
Acquisition of
treasury stock
(387,978 shares) --- --- --- --- (3,384,508)
------------ ------------ ------------ ------------ -----------
Balance, June 30, 1994 8,108,802 $ 81,088 $ 36,787,791 $ 70,073,501 $(5,282,411)
============ ============ ============ ============ ===========
<FN>
The accompanying notes are an integral part of these consolidated financial statements.<PAGE>
<PAGE> 41
</FN>
</TABLE>
<TABLE>
ALLEGHENY & WESTERN ENERGY CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<CAPTION>
Year Ended Year Ended Year Ended
June 30, June 30, June 30,
1994 1993 1992
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 9,001,736 $ 3,745,982 $ 3,674,468
------------- ------------- ------------
Adjustments to reconcile net income
to net cash provided by operating
activities:
Cumulative effect prior to July 1,
1993 of adopting SFAS No. 109
(Note 6) (1,562,156) --- ---
Depletion, depreciation and
amortization 10,902,198 10,302,928 10,656,139
Provision for losses on accounts
receivable 1,104,508 836,000 1,183,773
Deferred income taxes (760,800) 478,620 (2,171,708)
Other non-cash items, net (1,912,135) (2,728,196) (935,940)
Changes in current assets and
liabilities:
(Increase) in accounts receivable (2,667,226) (3,440,960) (2,182,417)
Decrease (increase) in inventory (11,370,825) 756,479 (1,918,627)
(Decrease) increase in
overrecovered gas costs (463,435) (9,296,843) 11,510,942
Increase (decrease) in accounts
payable (1,590,403) 1,768,930 1,926,094
Increase in other assets and
liabilities 9,446,125 2,762,573 4,584,260
------------- ------------- ------------
Total adjustments 1,125,851 1,439,531 22,652,516
------------- ------------- ------------
Net cash provided by operating
activities 10,127,587 5,185,513 26,326,984
------------- ------------- ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (13,270,283) (15,479,628) (9,533,924)
Short-term investments at cost (3,107,608) --- ---
Acquisition of assets --- (6,854,639) ---
Proceeds from sale of TEX-HEX assets --- --- 400,000
------------- ------------- ------------
Net cash used in investing
activities (16,377,891) (22,334,267) (9,133,924)<PAGE>
------------- ------------- ------------
<PAGE> 42
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on long-term debt (6,750,000) (21,750,000) (1,500,000)
Issuance of long-term debt --- 15,000,000 ---
Net proceeds from short-term borrowings 11,064,200 7,638,700 ---
Purchases of treasury stock (3,384,508) (1,714,141) ---
------------- ------------- ------------
Net cash provided by (used in)
financing activities 929,692 (825,441) (1,500,000)
------------- ------------- ------------
NET (DECREASE) INCREASE IN
CASH AND EQUIVALENTS (5,320,612) (17,974,195) 15,693,060
CASH AND EQUIVALENTS AT
BEGINNING OF YEAR 10,931,400 28,905,595 13,212,535
------------- ------------- ------------
CASH AND EQUIVALENTS AT END OF YEAR $ 5,610,788 $ 10,931,400 $ 28,905,595
============= ============= ============
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the year for:
Interest (net of amounts capitalized) $ 4,292,983 $ 4,279,647 $ 3,551,532
============= ============= ============
Income taxes $ 700,000 $ 1,030,000 $ 2,920,000
============= ============= ============
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
</FN>
/TABLE
<PAGE>
<PAGE> 43
ALLEGHENY & WESTERN ENERGY CORPORATION
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION
Allegheny & Western Energy Corporation (Allegheny or the Company)
and its subsidiaries are engaged in the exploration, production,
distribution and marketing of natural gas. The exploration and
production of natural gas is performed in the Appalachian Basin
of West Virginia. The Company's past exploration and production
activities have been conducted for its own account and through
joint ventures with third parties and limited partnerships.
Allegheny has performed no drilling activities since fiscal 1992.
Beginning in fiscal 1990, principally all of Allegheny's gas
production was sold to either Mountaineer Gas Company
(Mountaineer) or Gas Access Systems, Inc. (G.A.S.), both wholly-
owned subsidiaries.
Mountaineer is a regulated gas distribution utility servicing
approximately 200,000 residential, commercial, industrial and
wholesale customers in the State of West Virginia. Mountaineer
was acquired by Allegheny on June 21, 1984 from The Columbia Gas
System, Inc. During fiscal year 1993, Mountaineer formed a
wholly-owned subsidiary, Mountaineer Gas Services, Inc. (MGS),
for the purpose of owning and operating the producing properties
and transmission plant assets acquired from Hallwood Energy
Partners, L.P. and Hallwood Consolidated Resources Corporation
(Hallwood) (see Note 3).
The Company markets natural gas directly to industrial,
commercial and municipal customers through its non-regulated
subsidiary, G.A.S. G.A.S. was created in July 1987 and markets
the production of Allegheny as well as supplies of natural gas
purchased from various producers and wholesalers in the
Appalachian Basin of West Virginia and the continental United
States.
In November 1989, the Company formed a wholly-owned Texas
subsidiary, TEX-HEX Corp. (TEX-HEX). TEX-HEX performed
exploration and production activities in south Texas, primarily
utilizing horizontal drilling techniques. Effective April 1,
1992, TEX-HEX sold all its producing properties. All of TEX-
HEX's operations ceased effective June 1992.
In November 1990, Allegheny entered into an agreement with a
third party whereby Allegheny acquired a 50% interest in
petroleum prospecting licenses, which were granted in February
1991 and became effective in August 1991, covering approximately
2.6 million acres in the North Island, New Zealand including
acreage both onshore and offshore. The Company formed a New
Zealand subsidiary, A&W Exploration New Zealand, Limited (AWENZ),
which now holds the Company's interests in the petroleum<PAGE>
<PAGE> 44
prospecting licenses. During fiscal 1992, AWENZ acquired an
additional 9.5% interest in the prospecting licenses. As of June
30, 1994, the Company had invested approximately $943,000 in this
arrangement, all of which has been charged to expense.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The consolidated financial statements include the accounts of
Allegheny and all its subsidiaries. All significant intercompany
items have been eliminated except those relating to sales of
natural gas to Mountaineer by Allegheny and MGS. During the
years ended June 30, 1994, 1993 and 1992, the Company received
approximately $140,000, $211,000 and $427,000, respectively, for
their interests in this gas production. MGS made sales of
approximately $4,222,000 and $959,000 to Mountaineer during
fiscal 1994 and 1993, respectively. Prices at which natural gas
is sold by affiliates to Mountaineer is regulated and approved by
the Public Service Commission of West Virginia (PSCWV).
Basis of Accounts
Mountaineer and MGS maintain their accounts in conformity with
generally accepted accounting principles for regulated entities
which is in accordance with the accounting requirements and
ratemaking practices prescribed by the PSCWV.
Revenue Recognition
Oil and gas production, including royalties and overrides, is
recognized as income as it is extracted and sold from properties.
Income from field services is recognized as the related services
are performed.
Utility revenues 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. Accounts receivable
include $1,701,000, and $1,644,000 of gas delivered but unbilled
as of June 30, 1994 and 1993, respectively. Mountaineer is
subject to a purchased gas adjustment clause and records gas cost
as an expense as it is recovered through billings to customers.
The differences between actual gas costs and those recovered are
deferred. PSCWV regulations provide for annual proceedings
concerning gas purchases and cost recovery.
Revenues of G.A.S. are based on volumes delivered at the end of
each month. Gas purchases are accrued at prices negotiated with
vendors and matched with the corresponding gas sales.
Short-Term Investments
Short-term investments consist of United States Treasury
obligations and are stated at amortized cost which approximates
market. It is the Company's intent to hold short-term
investments until maturity.<PAGE>
<PAGE> 45
Property, Plant and Equipment and Related Depletion,
Depreciation, and Amortization
Utility Plant - Property, plant and equipment of Mountaineer is
stated at original cost, reduced by a purchase accounting
adjustment for regulatory purposes, and includes overheads for
payroll related costs, administrative and general expenses, as
well as an allowance for funds used during construction of
approximately $42,700 and $66,700 in fiscal 1994 and 1993,
respectively. The provision for depreciation is computed based
on a composite straight-line method. The average composite
depreciation rates were 3.72%, 3.68% and 3.62% for fiscal 1994,
1993 and 1992, respectively.
A purchase accounting adjustment of approximately $15,616,000 is
being amortized by Mountaineer over the estimated remaining
useful lives of the related property. The amortization period
ends in 1998.
Oil and Gas Property - The Company accounts for its natural gas
exploration and production activities under the successful
efforts method of accounting.
Oil and gas lease acquisition costs are capitalized when
incurred. Unproved properties are assessed on a property-by-
property basis and any impairment in value is recognized. If the
unproved properties are determined to be productive, the
appropriate related costs are transferred to proved oil and gas
properties. Lease rentals are expensed as incurred.
Oil and gas exploration costs, other than the costs of drilling
exploratory wells, are charged to expense as incurred. The costs
of drilling exploratory wells are capitalized pending
determination of whether proved reserves are discovered. If
proved reserves are not discovered, such drilling costs are
expensed. The costs of all development wells and related
equipment used in the production of crude oil and natural gas are
capitalized.
The Company amortizes capitalized costs, including gas gathering
systems, using a unit-of-production method based on proved oil
and gas reserves as estimated by independent petroleum engineers.
Depreciation on gas transmission plant is computed on a straight-
line method over thirty years. Depreciation of other property,
plant and equipment is computed using principally the straight-
line method over estimated useful lives of three to thirty years.
The Company charges the cost of maintenance and repairs to
expense as incurred. Betterments are added to property at cost.
Utility plant retirements are credited to property, plant and
equipment at cost and charged to accumulated depreciation, net of
cost of removal and salvage. No gain or loss is recognized on
utility plant retirements.
Income Taxes
Effective July 1, 1993, the Company adopted the Financial<PAGE>
<PAGE> 46
Accounting Standards Board (FASB) Statement of Financial
Accounting Standards (SFAS) No. 109, "Accounting for Income
Taxes." As permitted by SFAS No. 109, the Company elected not to
restate the financial statements of prior years. SFAS No. 109
requires the Company to utilize the liability method to recognize
deferred taxes. Under this method, deferred tax assets and
liabilities are determined based on differences between financial
reporting and tax bases of assets and liabilities and the
differences are measured at enacted tax rates and laws that will
be in effect when the differences are expected to reverse.
Deferred tax assets and liabilities are adjusted for future
changes in tax rates. Prior to the adoption of SFAS No. 109,
deferred tax expense was based on items of income and expense
that were reported in different years in the financial statements
and tax returns and were measured at the tax rate in effect in
the year the difference originated. The cumulative effect of
adopting SFAS No. 109 on the Company and its nonregulated
subsidiaries was to increase net income approximately $1,562,000
($.20 per share) in the first quarter of fiscal 1994. The
increase in net income was primarily the result of reduced
currently enacted tax rates compared to those in effect at the
time the deferred taxes were previously recognized. The adoption
of SFAS No. 109 by Mountaineer resulted in an increase in
accumulated deferred income taxes which was offset by a
corresponding increase in a regulatory asset account for which
deferred taxes had not previously been recognized due to state
ratemaking practices. (See Note 6.)
Benefits of the Federal income tax credit for fuel produced from
a non-conventional source are recognized in the consolidated
financial statements in the period earned to the extent utilized.
Inventory
Mountaineer maintains gas in storage under a firm storage service
agreement with an interstate pipeline. Gas in storage was
approximately $14,787,000 and $3,420,000 at June 30, 1994 and
1993, respectively, and is carried at cost on a first-in, first-
out basis.
Oil and gas materials and supplies are stated at the lower of
cost (first-in, first-out) or market. Utility materials and
supplies are stated at average cost and include overheads for
certain payroll, general and administrative expenses.
Prepayments
Prepayments as of June 30, 1993, consisted primarily of advance
payments for delivery of natural gas supplies to Mountaineer
during the winter peak usage period. Such payments are no longer
required as a result of the implementation of the Federal Energy
Regulatory Commission's (FERC) Order No. 636. (See Note 19.)
Prepayments are charged to expense in the period the related
goods or services are rendered.
Net Income Per Common Share<PAGE>
<PAGE> 47
Net income per common share is computed based upon the weighted
average number of common shares outstanding.
Weighted average shares for fiscal 1994 and 1993 reflect the
reduction in shares outstanding resulting from the purchase of
additional treasury shares. The Board of Directors has
authorized the purchase of up to 1,000,000 treasury shares.
Subsequent to June 30, 1994, no additional treasury shares have
been acquired by the Company.
Cash Flows Presentation
For purposes of the consolidated statements of cash flows, the
Company considers all highly liquid investments purchased with an
initial maturity of three months or less to be cash equivalents.
Reclassifications
Certain previously reported amounts have been reclassified to
conform to the 1994 presentation.
(3) ACQUISITION
On March 5, 1993, MGS purchased certain assets of Hallwood
consisting primarily of natural gas producing properties and
natural gas gathering and transmission pipelines, all of which
are located in West Virginia. MGS began operating such assets
effective April 1, 1993.
The total acquisition cost of approximately $10 million includes
cash expenditures of approximately $7 million and has been
accounted for under the purchase method of accounting. The
purchase price has been allocated to the natural gas properties
and gathering systems and transmission facilities acquired based
on their estimated fair values. The acquisition and purchase
price allocation was approved by the PSCWV. Substantially all
natural gas produced by MGS is sold to Mountaineer based on
prices approved by the PSCWV.
(4) LONG-TERM DEBT
Long-term debt obligations of the Company at June 30, 1994 and
1993 were as follows:
<TABLE>
<CAPTION>
Fiscal
Year
Maturity
Dates 1994 1993
<S> <C> <C> <C>
Term Credit Agreement<PAGE>
<PAGE> 48
<F1> 1995-1996 $ 4,375,000 $ 5,875,000
Revolving Credit Note
<F2> 1996 --- ---
Pension fund notes <F3> 1998-2007 15,000,000 15,000,000
Notes payable to
insurance companies
<F4> 1995-2002 13,055,000 18,305,000
------------ ------------
32,430,000 39,180,000
Less: current
maturities 6,750,000 6,750,000
------------ ------------
$ 25,680,000 $ 32,430,000
============ ============
<FN>
<F1> The Company has a debt agreement which includes a
$10,000,000 Term Credit and a $5,000,000 Revolving Credit
facility. Interest rates under the Term Credit facility are
either a base rate which approximates the prime rate plus
1/8% per annum or a certificate of deposit rate plus 1-3/4%
per annum. The Term Credit note is required to be repaid in
consecutive quarterly installments of $375,000 and a
twentieth and final payment of $2,875,000 at the time of
maturity, September 30, 1995. The interest rate on the Term
Credit Facility was 6.27% at June 30, 1994.
The Term Credit and Revolving Credit facilities are
collateralized by all of the outstanding stock of
Mountaineer and G.A.S. and a lien on certain intercompany
notes. The agreement places certain restrictions on the
ability of the Company to sell its assets, requires the
maintenance of certain financial covenants and restricts the
amount of dividends which the Company can declare to twenty-
five percent of consolidated net income earned after June
30, 1990. As of June 30, 1994, the maximum amount of
dividends which can be declared by the Company is
approximately $3,473,000. The financial covenants include a
minimum adjusted consolidated current ratio, minimum
consolidated net worth, minimum ratio of consolidated income
before interest and taxes to consolidated interest on funded
debt and a ceiling on consolidated funded debt. As of June
30, 1994, the Company is in compliance with all required
financial covenants.
<F2> Mountaineer has a $15,000,000 Revolving Credit Note
(Revolving Note) with a bank. The Revolving Note provides
that borrowings would not be required to be repaid until
December 31, 1996. Mountaineer had no outstanding balance
on the revolving note as of June 30, 1994. The interest
rate is the lower of an adjusted certificate of deposit rate
or a base rate. The base rate is equal to the greater of
the prime rate of interest or the Federal fund rate plus
1/2%.
The Revolving Note requires Mountaineer to maintain certain
financial conditions, including a minimum tangible net
worth, restrictions on funded debt and restrictions on the
amount of dividends which can be declared. As of June 30,
1994, Mountaineer is in compliance with all required<PAGE>
<PAGE> 49
financial covenants.
<F3> In July 1992, Mountaineer completed a private placement with
a pension fund of $15,000,000 of unsecured senior notes due
in 2007. The terms of the agreement provide that principal
is to be repaid annually beginning in 1998. The proceeds
were used for general corporate purposes and to repay the
existing Revolving Credit Note. The interest rate on the
pension fund notes is 8.71% and is due semi-annually. The
financial covenants are similar to the terms of the notes
payable to the insurance companies.
<F4> The notes payable to insurance companies require (a) annual
principal payments beginning June 30, 1993, through June 30,
2002, at which time the notes are due in full and (b)
interest at 9.75% due semi-annually. These notes require
Mountaineer to maintain a certain minimum tangible net worth
and restrict the amount of dividends that Mountaineer can
declare to the Company.
As of June 30, 1994, Mountaineer had approximately $11.7
million available for declaration of dividends under the
terms of its debt agreements.
</FN>
</TABLE>
The combined scheduled annual maturities of long-term debt are as
follows:
<TABLE>
<CAPTION>
Notes
Payable to
Term Credit Pension Insurance
Fiscal Agreement Fund Notes Companies
Year <F1> <F3> <F4> Total
<S> <C> <C> <C> <C>
1995 $ 1,500,000 $ --- $ 5,250,000 $ 6,750,000
1996 2,875,000 --- 4,750,000 7,625,000
1997 --- --- 1,150,000 1,150,000
1998 --- 1,500,000 500,000 2,000,000
1999 --- 1,500,000 500,000 2,000,000
Thereafter --- 12,000,000 905,000 12,905,000
----------- ----------- ----------- -----------
$ 4,375,000 $15,000,000 $13,055,000 $32,430,000
=========== =========== =========== ===========
</TABLE>
(5) SHORT-TERM BORROWINGS AND LINES-OF-CREDIT
Mountaineer had unsecured short-term bank lines-of-credit
totaling $57.5 million, $30 million and $22.5 million in fiscal
1994, 1993 and 1992, respectively. During fiscal 1994, the<PAGE>
<PAGE> 50
maximum outstanding daily balance was $37,220,700 and the average
daily balance was $17,156,300. The weighted average interest
rate was 3.44% on the balance outstanding in fiscal 1994. During
fiscal 1993, the maximum outstanding daily balance was $9,243,800
and the average daily balance was $1,407,000. The weighted
average interest rate was 3.40% on the balance outstanding in
fiscal 1993. During fiscal 1992, the maximum outstanding daily
balance was $44,000 and the average daily balance was $400. The
weighted average interest rate was 5.3% on the balance
outstanding in fiscal 1992. There was $18,702,900 and
$7,638,700 outstanding on these lines-of-credit at June 30, 1994
and 1993, respectively. The interest rate on these borrowings at
June 30, 1994 and 1993 was 4.8% and 3.3%, respectively. There
were no outstanding borrowings on these lines-of-credit at June
30, 1992.
Allegheny has $5,000,000 available under the Revolving Credit
Agreement entered into in September 1990. The interest rate is
either a base rate which approximates the prime rate or a
certificate of deposit rate plus 1-1/2% per annum. No borrowings
were made on this facility in fiscal 1994, 1993 or 1992.
(6) TAXES ON INCOME
Effective July 1, 1993, the Company prospectively adopted SFAS
No. 109. SFAS No. 109 requires the Company to utilize the
liability method to recognize deferred taxes. Under this method,
deferred tax assets and liabilities are based on differences
between financial reporting and tax bases of assets and
liabilities and the differences are measured at enacted tax rates
and laws that will be in effect when the differences are expected
to reverse. Deferred tax assets and liabilities are adjusted for
future changes in tax rates. Prior to the adoption of SFAS No.
109, deferred taxes were measured using tax rates for the year in
which timing differences arose and were not adjusted for changes
in tax rates.
The cumulative effect of adopting SFAS No. 109 on the Company and
its nonregulated subsidiaries as of July 1, 1993, was to increase
net income approximately $1,562,000 ($.20 per share) in the first
quarter of fiscal 1994. The increase in net income was primarily
the result of reduced currently enacted tax rates compared to
those in effect at the time the deferred taxes were recognized.
Pre-tax income from continuing operations of the Company and its
nonregulated subsidiaries was not affected by the change in the
method of accounting for income taxes. The adoption of SFAS No.
109 by Mountaineer resulted in an increase in accumulated
deferred income taxes which was offset by a corresponding
increase in a regulatory asset to account for certain temporary
differences for which deferred taxes had not previously been
recognized due to state ratemaking practices. This amount
(approximately $8,539,000 at June 30, 1994) has been reflected in
other assets in the accompanying balance sheets.
Significant components of the Company's deferred tax assets and
liabilities as of June 30, 1994 are as follows:<PAGE>
<PAGE> 51
<TABLE>
<CAPTION>
Deferred Deferred
income taxes - income taxes -
noncurrent current
<S> <C> <C>
Deferred tax assets:
Alternative minimum tax
credit carryforwards $ 3,759,000 $ ---
Overrecovered gas costs --- 2,116,000
Foreign subsidiary losses 70,000 ---
Allowance for doubtful
accounts --- 508,000
Other 143,000 1,141,000
-------------- --------------
Total assets 3,972,000 3,765,000
Deferred tax liabilities:
Excess of tax over book
depreciation and fixed
asset basis differences (22,858,000) ---
Deferred charges (533,000) (173,000)
Partnership income
recognition --- (174,000)
Other --- (397,000)
-------------- --------------
Total liabilities (23,391,000) (744,000)
-------------- --------------
Total deferred income tax
asset (liability) $ (19,419,000) $ 3,021,000
============== ==============
</TABLE>
Components of taxes on income are as follows:
<TABLE>
<CAPTION>
Fiscal Year Ended June 30,
1994 1993 1992
<S> <C> <C> <C>
Federal income taxes:
Current $ 1,900,000 $ 840,000 $ 2,500,000
Deferred (1,031,100) 125,100 (2,353,300)
Investment tax credits,
net --- --- (40,800)
----------- ----------- -----------
868,900 965,100 105,900
----------- ----------- -----------
State and local income
taxes:
Current 728,700 131,300 840,400
Deferred 270,300 141,500 (750,000)
----------- ----------- -----------
999,000 272,800 90,400
----------- ----------- -----------
Total income tax provision $ 1,867,900 $ 1,237,900 $ 196,300
=========== =========== ===========<PAGE>
<PAGE> 52
</TABLE>
A reconciliation of the Federal statutory rate to taxes on income
is as follows:
<TABLE>
<CAPTION>
Fiscal Year Ended June 30,
1994 1993 1992
<S> <C> <C> <C>
Tax at Federal statutory
rate $ 3,164,500 $ 1,694,500 $ 1,316,100
State taxes, net of
Federal benefits 417,400 141,200 58,000
Nonconventional fuel tax
credits and other
credits, including
amortization (986,600) (403,700) (1,168,700)
Reversal of deferred income
taxes due to rate
differential (29,700) (30,100) (66,800)
Taxes related to regulatory
treatment of timing
differences (53,700) 232,800 263,300
Acquisition adjustment
amortization (508,700) (508,700) (508,700)
Adjustments to prior year
provision (183,400) 64,800 291,100
Other, net 48,100 47,100 12,000
----------- ----------- -----------
Total income tax
provision $ 1,867,900 $ 1,237,900 $ 196,300
=========== =========== ===========
Effective tax rate 20.1% 24.8% 5.1%
=========== =========== ===========
</TABLE>
In August 1993, the Revenue Reconciliation Act of 1993 was
enacted into law which, among other changes, increased the top
marginal tax rate for corporations with taxable incomes in excess
of $10 million to 35%. The Company does not currently anticipate
that it will be subject to the increased marginal rate.
(7) RETIREMENT PLANS
The Retirement Income Plan for the Company (the Plan) covers all
qualified employees 21 years of age and over. Employees become
fully vested upon completion of five years of credited service,
as defined by the Plan. Retirement income is based on credited
years of service and level of compensation. The Plan is subject
to the provisions of the Employee Retirement Income Security Act
of 1974 (ERISA). The determination of contributions is made in
consultation with an actuary and is based upon anticipated<PAGE>
<PAGE> 53
earnings of the Plan, mortality and turnover experience, the
funded status of the Plan and anticipated future compensation
levels. The Company's funding policy is to be in compliance with
ERISA guidelines and to make annual contributions to the Plan to
assure that all employees' benefits will be fully provided for by
the time they retire. Funds contributed to the Plan have been
invested primarily in government securities and corporate bonds
and equity securities of large, well-established corporations.
The following table sets forth the Plan's funded status and
amounts recognized in the Company's consolidated balance sheets
at June 30, 1994 and 1993:
<TABLE>
<CAPTION>
(Dollars in Thousands)
1994 1993
<S> <C> <C>
Actuarial Present Value of Benefit
Obligations:
Accumulated benefit obligation,
including vested benefits of $(22,560)
and $(21,790) at June 30, 1994 and
1993, respectively $ (24,244) $ (23,430)
========== ==========
Projected benefit obligation for
service rendered to date $ (27,297) $ (26,089)
Plan assets at fair value 20,212 20,902
---------- ----------
Projected benefit obligation in excess
of plan assets (7,085) (5,187)
Unrecognized net loss from past
experience 4,658 2,428
Unrecognized prior service cost 453 510
Unrecognized net obligation at June 30,
1987, recognized over 15 years 1,759 1,978
Adjustment required to recognize minimum
liability (3,817) (2,257)
---------- ----------
Accrued pension cost $ (4,032) $ (2,528)
========== ==========
</TABLE>
Net pension cost for fiscal years ended June 30, 1994, 1993 and
1992 included the following components:
<TABLE>
<CAPTION>
(Dollars in Thousands)
1994 1993 1992 <PAGE>
<PAGE> 54
<S> <C> <C> <C>
Service cost $ 589 $ 529 $ 565
Interest cost 2,030 1,961 1,947
Actual return on plan assets 122 (2,255) (1,960)
Net amortization and deferral (1,513) 970 651
--------- --------- ---------
Net periodic pension cost $ 1,228 $ 1,205 $ 1,203
========= ========= =========
</TABLE>
The expected long-term rate of return used in the calculations
was 8.25% for fiscal 1994 and 1993 and 9% for fiscal 1992. The
weighted average discount rate used in the calculations was 8.0%
for fiscal 1994, 1993 and 1992.
The Company has a Key Executives' Supplemental Retirement Benefit
Plan (the "SERP") for its key executive employees. The SERP
provides for the payment of compensation for varying periods of
time upon an executive employee reaching a specified retirement
age or becoming permanently disabled while employed by the
Company or its subsidiaries. The Company funds the SERP through
the purchase of individual life insurance contracts of which the
Company is the sole beneficiary, and the specific level of
compensation will be dependent upon the performance of the life
insurance contracts. In addition, the Company will provide
benefits to the employee's beneficiary should the employee die
while employed by the Company or its subsidiaries. Benefits to
be paid upon retirement will not vest unless the employee
continues to be employed by the Company or its subsidiaries
through the specified retirement age. Should a change in control
(as defined in the SERP) of the Company occur, the employee will
become entitled to a portion of his retirement benefit for each
year of participation in the SERP, except for certain executives
having employment contracts, who will be entitled to full
retirement benefits. This portion is based upon the number of
years of participation in the SERP in proportion to the total
number of years until retirement for such employee from the time
he or she became a participant in the SERP. The Board of
Directors, in its sole discretion, may terminate the SERP at any
time, in whole or in part. The costs associated with the SERP
are being accrued over the respective executive employee's
remaining years of service to retirement.
(8) POSTRETIREMENT MEDICAL AND LIFE INSURANCE BENEFITS
Mountaineer provides certain medical and life insurance benefits
for retired employees. Substantially all of Mountaineer's
employees may become eligible for these benefits if they choose
to retire early after reaching age 55 while working for
Mountaineer. The medical benefits are provided until age 65 at
which time these employees become eligible for Medicare and
medical benefits from Mountaineer are no longer provided. Life
insurance benefits of approximately two times annual salary are
provided while an employee is active and working at Mountaineer.
On the date of an employee's retirement and on the date the<PAGE>
<PAGE> 55
employee reaches age 70, life insurance benefits decrease to
approximately 80% and 40% of annual salary, respectively. These
benefits are provided to retirees who meet the service
requirements of ten continuous years of service prior to
retirement at age 55 or five continuous years of service prior to
retirement at age 65.
Effective July 1, 1993, Mountaineer adopted SFAS No. 106,
"Employers Accounting for Postretirement Benefits Other Than
Pensions" (OPEB). SFAS No. 106 significantly changes the
accounting, measurement and disclosure practices with respect to
OPEB's. SFAS No. 106 requires that the expected cost of OPEB's
be charged to expense during the period of an employee's service
rather than expensing such costs as claims are incurred. Under
the plan, the attribution period is equivalent to the 10-year
period prior to the employee reaching eligible retirement age.
As permitted by SFAS No. 106, Mountaineer has elected to amortize
the accumulated postretirement benefit obligation existing at the
date of adoption ("transition obligation") over a 20-year period.
Prior to fiscal 1994, Mountaineer recognized postretirement
health care and life insurance benefits in the year the benefits
were paid. The cost of retirees' benefits paid in fiscal 1994,
1993 and 1992 was approximately $297,000, $525,000 and $347,000,
respectively. Retiree benefits recognized by Mountaineer
pursuant to the requirements of SFAS No. 106 were $1,117,000 in
fiscal 1994.
The following table sets forth the plan's funded status, as
determined by an independent actuary, as of July 1, 1993 and June
30, 1994:
<TABLE>
<CAPTION>
June 30, July 1,
1994 1993
(Dollars in thousands)
<S> <C> <C>
Accumulated postretirement benefit
obligation:
Retirees $ 2,656 $ 2,871
Active participants 3,849 3,305
---------- ----------
Total accumulated postretirement
benefit obligation 6,505 6,176
Plan assets at fair value --- ---
---------- ----------
Accumulated postretirement benefit
obligation in excess of plan
assets 6,505 6,176
Unrecognized actuarial gain 202 ---
Unrecognized transition obligation (5,866) (6,176)
---------- ----------
Accrued postretirement benefit
liability $ 841 $ ---
========== ==========
/TABLE
<PAGE>
<PAGE> 56
Net periodic postretirement benefit cost for the fiscal year
ended June 30, 1994, as determined by an independent actuary,
includes the following components (in thousands of dollars):
<TABLE>
<CAPTION>
<S> <C>
Service cost-benefits attributed to
service during the period $ 307
Interest cost on the accumulated
postretirement benefit obligation 500
Amortization of the transition
obligation 310
----------
Net periodic postretirement benefit
cost $ 1,117
==========
</TABLE>
The assumed health care cost trend rate used in measuring the
accumulated postretirement benefit obligation was 11% in 1994,
declining gradually to 5.5% in 2005 and remaining at that level
thereafter. The health care cost trend rate assumption has a
significant effect on the amounts reported. To illustrate,
increasing the assumed health care cost trend rates by one
percent in each year would increase the aggregated service and
interest cost by $49,000 and accumulated postretirement benefit
obligation as of June 30, 1994 by $218,000. The weighted average
discount rate used in determining the accumulated postretirement
benefit obligation was 8%. The average assumed annual rate of
salary increase for the life insurance benefit plan was 5%.
As part of a PSCWV rate order dated October 29, 1993, the PSCWV
ruled that the permitted rate recovery mechanism for OPEB's will
be a modified accrual method. The modified accrual method allows
for the recovery of current service costs on an accrual basis and
recovery of the transition obligation on a cash basis.
Accounting for the transition obligation on a cash method is not
an acceptable accounting method under generally accepted
accounting principles. Mountaineer is recording its other
postretirement benefit expense in accordance with SFAS No. 106,
which is in excess of the permitted rate recovery as a result of
the PSCWV's ruling. Mountaineer currently estimates that the
amount of SFAS No. 106 expense (net of those amounts expected to
be capitalized) in excess of the modified accrual basis would be
approximately $300,000 in fiscal 1995 and would accumulate to
approximately $3,000,000 over the remaining nineteen year
amortization period for transition costs. These amounts will be
recovered through rates in later years when the cash basis of
prior service costs exceeds the accrual basis of such costs.
(9) LEASING ARRANGEMENTS
The Company, primarily through its subsidiary, Mountaineer,
leases buildings, office space, and equipment under various
short-term and long-term agreements. Total expense for leases<PAGE>
<PAGE> 57
for the fiscal years ended June 30, 1994, 1993 and 1992 was
$852,000, $935,000 and $1,048,000, respectively. At June 30,
1994, the net minimum annual rental commitments for all
noncancellable leases were as follows:
<TABLE>
<CAPTION>
Fiscal Year Ending
June 30, Amount
<S> <C>
1995 $ 723,000
1996 415,000
1997 369,000
1998 368,000
1999 360,000
Thereafter 647,000
-----------
$ 2,882,000
===========
</TABLE>
(10) STOCK OPTION PLAN
The Company's 1987 Stock Option Plan (the 1987 Plan), as amended,
provides that a combined total of 1,500,000 incentive and non-
qualified options to purchase shares of the Company's common
stock may be granted to certain key employees by the Board of
Directors. Incentive options must be granted with an exercise
price equal to the fair market value of a share of common stock
on the date of grant. Non-qualified options may be granted at
prices determined by the Board of Directors. Options granted
expire five to ten years from date of grant and may include
vesting provisions; however, in the event of a change in control
of the Company (as defined in the 1987 Plan), options granted
vest immediately. The 1987 Plan also provides that employees may
be granted stock appreciation rights (SAR's) at the discretion of
the Board of Directors. No SAR's have been granted under the
1987 Plan.
Information relative to the stock option plan for the fiscal
years ended June 30, 1994, 1993, and 1992 is as follows:
<TABLE>
<CAPTION>
Average
Number Exercise
of Price
Shares Per Share
<S> <C> <C>
Outstanding at June 30, 1991 1,150,300 $ 8.17
Granted --- <PAGE>
<PAGE> 58
Expired (47,100) 8.30
----------
Outstanding at June 30, 1992 1,103,200 8.16
Granted ---
Expired (15,000) 8.25
----------
Outstanding at June 30, 1993 1,088,200 8.16
Granted 15,000 7.50
Expired (18,300) 8.25
----------
Outstanding at June 30, 1994 1,084,900 $ 8.16
==========
Exercisable 1,084,900
==========
Options available for grant 415,100
==========
</TABLE>
The options outstanding as of June 30, 1994 expire at various
dates through 2000.
(11) COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION,
EXPLORATION, AND DEVELOPMENT ACTIVITIES (UNAUDITED)
Costs incurred by the Company in oil and gas property
acquisition, exploration, and development activities are
presented below:
<TABLE>
<CAPTION>
Fiscal Year Ended June 30,
1994 1993 1992
<S> <C> <C> <C>
Property acquisition
costs $ 6,000 $ 5,491,000 $ 120,000
Exploration costs 173,000 337,000 326,000
Development costs --- --- 200,000
----------- ----------- -----------
$ 179,000 $ 5,828,000 $ 646,000
=========== =========== ===========
</TABLE>
Property acquisition costs include costs incurred to purchase,
lease, or otherwise acquire a property. During fiscal 1993,
these costs included the natural gas producing properties
acquired from Hallwood (see Note 3). Exploration costs include
the costs of geological and geophysical activity, carrying and
retaining undeveloped property, dry holes, leasehold impairment
allowances, and drilling and equipping exploratory wells.
Development costs include costs incurred to gain access to and
prepare development well locations for drilling, to drill and
equip development wells, and to provide facilities to extract,<PAGE>
<PAGE> 59
treat, gather, and store oil and gas.
(12) OIL AND GAS CAPITALIZED COSTS (UNAUDITED)
Aggregate capitalized costs for the Company related to oil and
gas property acquisition, exploration and development activities,
with applicable accumulated depletion, depreciation, and
amortization are presented below:
<TABLE>
<CAPTION>
Fiscal Year Ended June 30,
1994 1993
<S> <C> <C>
Proved developed properties, being
amortized $ 51,773,293 $ 56,654,989
Less-accumulated depletion,
depreciation, and amortization -
proved properties 21,338,959 22,657,617
------------ ------------
Net proved properties 30,434,334 33,997,372
------------ ------------
Total net capitalized costs $ 30,434,334 $ 33,997,372
============ ============
</TABLE>
Unproved properties include costs to acquire acreage which has
not been allocated to producing properties. Proved developed
properties include the capitalized costs of producing properties,
well support equipment and the Company's gas gathering systems,
which primarily transport natural gas production from Company
operated wells.
(13) RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED)
The results of operations for oil and gas producing activities
are presented below:
<TABLE>
<CAPTION>
Fiscal Year Ended June 30,
1994 1993 1992
<S> <C> <C> <C>
Revenue from oil and gas
producing activities:
Sales to unaffiliated
parties $ 50,000 $ 78,000 $ 1,199,000
Sales to affiliates 5,725,000 3,408,000 2,916,000
----------- ----------- -----------
5,775,000 3,486,000 4,115,000
----------- ----------- -----------<PAGE>
<PAGE> 60
Expenses:
Production costs 1,753,000 662,000 1,541,000
Exploration expenses 173,000 337,000 326,000
Depletion, depreciation,
and amortization 2,160,000 2,253,000 3,230,000
----------- ----------- -----------
4,086,000 3,252,000 5,097,000
----------- ----------- -----------
Income (loss) from oil
and gas producing
activities before
income tax benefit 1,689,000 234,000 (982,000)
Income tax benefit 312,000 310,000 1,520,000
----------- ----------- -----------
Net income from oil and
gas producing activities $ 2,001,000 $ 544,000 $ 538,000
=========== =========== ===========
</TABLE>
The increase in revenues from oil and gas producing activities is
due primarily to MGS's natural gas sales being in place for all
of fiscal 1994 versus only three months of fiscal 1993.
Production costs include those costs incurred to operate and
maintain productive wells and related equipment and include costs
such as labor, repairs and maintenance, materials, supplies, fuel
consumed, insurance and production taxes. In addition,
production costs include certain administrative expenses which
the Company determines are directly related to oil and gas
operations, and are net of well tending fees which are included
in field service revenues in the accompanying consolidated income
statements. The increase in production costs in fiscal 1994 is
due primarily to MGS's operations being in place for all of
fiscal 1994 versus only three months of fiscal 1993. The
reduction in production expenses in fiscal 1993 reflects the
discontinuance of TEX-HEX operations and the efforts to reduce
field operations expenses at Allegheny.
Exploration expenses include the costs of geological and
geophysical activity, carrying and retaining undeveloped
property, dry holes and leasehold impairment allowances.
Depletion, depreciation, and amortization expense includes costs
associated with capitalized acquisition, exploration, and
development costs, and the depreciation applicable to support
equipment.
The income tax benefit is computed at the statutory Federal and
state income tax rate and is reduced to the extent of permanent
differences, which have been recognized in the Company's tax
provision, including the utilization of Federal tax credits
permitted for fuel produced from a non-conventional source.
(14) NET PROVED OIL AND GAS RESERVES (UNAUDITED)
Estimates of net proved oil and gas reserves (all of which are
developed) of the Company, all of which are within the United
States, are as follows:<PAGE>
<PAGE> 61
<TABLE>
<CAPTION>
Oil (Bbls) Gas (Mcf)
<S> <C> <C>
Balance, June 30, 1991 136,000 19,432,000
Revisions of previous estimates (15,000) (3,350,000)
Extensions, discoveries and
other additions --- 159,000
Production (62,000) (1,489,000)
Sales of reserves in place (17,000) (11,000)
------------- -------------
Balance, June 30, 1992 42,000 14,741,000
Revisions of previous estimates 2,000 (360,000)
Production (5,000) (1,518,000)
Purchases of reserves in place --- 13,484,000
------------- -------------
Balance, June 30, 1993 39,000 26,347,000
Revisions of previous estimates (6,000) 3,925,000
Production (5,000) (3,025,000)
Purchases of reserves in place --- 60,000
Sales of reserves in place --- (639,000)
------------- -------------
Balance, June 30, 1994 28,000 26,668,000
============= =============
</TABLE>
These estimates are based primarily on the reports of independent
petroleum engineers. The estimates include only those amounts
considered to be proved reserves and do not include additional
amounts that may result from extensions of currently proved areas
or amounts that may result from new discoveries in the future.
Proved developed reserves are those reserves that are expected to
be recovered through existing wells with existing equipment and
operating methods.
In fiscal 1992, the Company changed the method by which it
computes its net proved reserves of oil and gas attributable to
the Company's interest in producing properties in which other
third parties participate. Beginning in fiscal 1992, the Company
determines the economic life of such reserves based, in part,
upon operating costs that include general and administrative
expenses charged to such properties. Prior to fiscal 1992, the
Company excluded such expenses when determining economic life.
The impact of this change reduced the economic life, which, in
turn, reduced the estimated reserves. This change resulted in a
reduction of approximately 2,400,000 Mcf in natural gas reserves
and 16,000 Bbl in oil reserves, which is reflected in the above
table within the fiscal 1992 revision of previous estimates.<PAGE>
<PAGE> 62
(15) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
AND CHANGES THEREIN RELATING TO PROVED OIL AND GAS
RESERVES (UNAUDITED)
Summarized in the table below is information for the Company with
respect to the standardized measure of discounted future net cash
flows relating to proved oil and gas reserves. Future cash
inflows are derived by applying current oil and gas prices to
estimated future production. Future production costs, likewise,
are derived based on current costs, assuming continuation of
existing economic conditions. Future income tax expenses are
computed at the Company's anticipated statutory tax rate in
effect at the end of each fiscal year to the future pre-tax net
cash flows, less the tax basis of the properties, and gives
effect to permanent differences and tax credits related to the
properties. The future income tax expense reflected below
excludes the benefit of the Federal tax credit available from
production of fuel from non-conventional sources. Utilization of
the tax credit is permitted to the extent the Company is in a
regular tax-paying position. Future income tax expense may be
lower to the extent the tax credit is utilized.
<TABLE>
<CAPTION>
Fiscal Year Ended June 30,
1994 1993 1992
(Dollars in Thousands)
<S> <C> <C> <C>
Future cash inflows $ 67,870 $ 64,746 $ 32,535
Future production costs (29,399) (27,785) (9,201)
Future income tax expense (7,694) (7,392) (4,667)
-------- -------- --------
Future net cash flows 30,777 29,569 18,667
10% annual discount for
estimated timing of cash
flows 14,861 14,019 8,751
-------- -------- --------
Standardized measure of
discounted future net cash
flows $ 15,916 $ 15,550 $ 9,916
======== ======== ========
</TABLE>
The following table summarizes the principal sources of changes
in the standardized measure of discounted future net cash flows:
<TABLE>
<CAPTION>
Fiscal Year Ended June 30,
1994 1993 1992
(Dollars in Thousands)<PAGE>
<PAGE> 63
<S> <C> <C> <C>
Sales and transfers of oil and
gas produced, net of
production costs $ (4,022) $ (2,824) $ (2,578)
Net changes in prices and
production costs 324 (977) (982)
Extensions and discoveries,
less related costs --- --- 122
Purchases of reserves in place 45 9,981 ---
Changes in quantity estimates 2,932 (257) (2,637)
Accretion of discount 1,944 1,240 1,631
Net change in income taxes (474) (1,700) 784
Other (383) 171 524
-------- -------- --------
$ 366 $ 5,634 $ (3,136)
======== ======== ========
</TABLE>
It is necessary to emphasize that the data presented above should
not be viewed as representing the expected cash flow from, or
current value of, existing proved reserves since the computations
are based on a large number of estimates and arbitrary
assumptions. Reserve quantities cannot be measured with
precision and their estimation requires many judgmental
determinations and frequent revisions. The required projection
of production and related expenditures over time requires further
assumptions with respect to pipeline availability, rates of
demand, and governmental control, among other factors.
Furthermore, actual future prices and costs are likely to be
substantially different from the current prices and costs
utilized in the computation of reported amounts. In addition,
the reported data are applicable only to oil and gas reserves
classified as proved; no amounts are included with respect to
additional reserves that may become proved in the future. Any
analysis or evaluation of the reported amounts should give
specific recognition to the computational methods utilized and
the limitations inherent therein.
(16) FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair values of financial instruments as of June 30
are as follows:
<TABLE>
<CAPTION>
1994 1993
Carrying Fair Carrying Fair
Amount Value Amount Value
(Dollars in Thousands)
<S> <C> <C> <C> <C>
Assets:<PAGE>
<PAGE> 64
Cash & equivalents $ 5,611 $ 5,611 $ 10,931 $ 10,931
Short-term investments 3,142 3,141 --- ---
Accounts receivable 23,539 23,539 21,976 21,976
Liabilities:
Short-term borrowings 18,703 18,703 7,639 7,639
Long-term debt (including
current maturities) 32,430 33,483 39,180 43,477
</TABLE>
The following methods and assumptions were used to estimate the
fair value of each class of financial instrument for which it is
practicable to estimate fair value:
Cash and equivalents, accounts receivable and short-term
borrowings: The carrying amounts approximate fair value due
to the nature and short-term maturity of these instruments.
Short-term investments: Fair value is based on quoted market
prices.
Long-term debt: Fair value is estimated using discounted cash
flow analyses based on current incremental borrowing rates
for similar types of borrowing arrangements.
(17) RELATED PARTY TRANSACTIONS
The Company's field services revenue includes revenue from
partnerships and joint ventures in which the Company is the
general partner or operator.
Certain officers and directors of the Company and their relatives
and other related parties participate as limited partners in
certain partnerships in which the Company is the general partner.
(18) QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly consolidated financial results are as
follows:
<TABLE>
<CAPTION>
Fiscal Quarter First Second Third Fourth
(Dollars in thousands except per share amounts)
1994
<S> <C> <C> <C> <C>
Revenues $ 22,806 $ 69,609 $ 97,070 $ 14,991
Income (loss) before
income taxes and
cumulative effect of<PAGE>
<PAGE> 65
change in accounting
principle (2,546) 4,119 8,517 (782)
Income (loss) before
cumulative effect of
change in accounting
principle (1,682) 2,862 6,085 175
Cumulative effect prior
to July 1, 1993 of
change in method of
accounting for income
taxes (Note 6) 1,562 --- --- ---
Net income (loss) (120) 2,862 6,085 175
Per share:
Income (loss) before
cumulative effect of
change in accounting
principle $ (.22) $ .37 $ .79 $ .02
Cumulative effect
prior to July 1, 1993
of change in method
of accounting for
income taxes
(Note 6) .20 --- --- ---
Net income (loss)
per share (.02) .37 .79 .02
1993
Revenues $ 19,108 $ 57,481 $ 77,476 $ 31,469
Net income (loss)
before taxes (2,256) 3,489 5,697 (1,946)
Net income (loss) (1,579) 2,442 3,988 (1,105)
Net income (loss)
per share $ (.20) $ .30 $ .50 $ (.14)
</TABLE>
In the fourth quarter of fiscal 1994, Mountaineer recorded a $17
million charge to revenues relating to Mountaineer's passthrough
to its customers of refunds received from Mountaineer's pipeline
suppliers. This charge was offset by a corresponding reduction in
cost of gas distributed, resulting in no impact on the Company's
profitability.
Mountaineer's natural gas distribution operations are
significantly affected by weather-related heating requirements.
Therefore, results for interim periods are not comparable and are
not necessarily indicative of what may be expected for a full
year.
The Company records an interim provision (benefit) for income
taxes based upon its estimated annual effective rate.
Differences between net statutory rates and effective rates are
caused primarily by book amortization of an acquisition
adjustment, Federal nonconventional fuel credits and the
treatment of certain temporary differences for ratemaking<PAGE>
<PAGE> 66
purposes.
(19) COMMITMENTS AND CONTINGENCIES
Gas Transmission Matters
In 1992, the FERC issued Order No. 636 et. seq., (the 636
Orders). The 636 Orders required substantial restructuring of
the service obligations of interstate pipelines. Among other
things, the 636 Orders mandated "unbundling" of existing pipeline
gas sales services and replaced existing statutory abandonment
procedures, as applied to firm transportation contracts of more
than one year, with a right-of-first-refusal mechanism.
Mandatory unbundling required pipelines to sell separately the
various components of their previous gas sales services
(gathering, transportation and storage services, and gas supply).
To address concerns raised by utilities about reliability of
service to their service territories, the 636 Orders required
pipelines to offer a no-notice transportation service in which
firm transporters can receive delivery of gas up to their
contractual capacity level on any day without prior scheduling.
In addition, the 636 Orders provided for a mechanism for
pipelines to recover prudently incurred transition costs
associated with the restructuring process.
All of Mountaineer's pipeline suppliers have filed their
restructuring plans with the FERC. The FERC has reviewed these
plans; however, there are several issues which remain subject to
further action by either the FERC or reviewing courts, including
the ultimate sharing of transition costs, the level of no-notice
protection and the impact on service reliability, and rate design
implementation. Mountaineer's largest pipeline supplier,
Columbia Transmission Corporation (Columbia Transmission),
received orders from the FERC which approved its proposed
restructuring filing with certain modifications. One of the FERC
modifications prohibited Columbia Transmission from recovering
contract rejection claims it may incur in its bankruptcy
proceeding as part of its transition costs. Columbia
Transmission and others have filed for appellate review of this
disallowance. In addition, Columbia Transmission filed a revised
compliance plan with the FERC on October 22, 1993, which was
placed into effect on November 1, 1993, subject to further
modification.
As a consequence of the November 1, 1993 restructuring,
Mountaineer has replaced the bundled firm sales service it
previously received from Columbia Transmission with gas purchase
arrangements negotiated with unregulated suppliers and firm
transportation and storage agreements with Columbia Transmission.
Interim supply arrangements are in place, negotiations for long-
term supplies are underway and the Company is reviewing its
current level of firm service contracts to determine if
additional capacity is necessary to provide reliable service to
its customers. Unresolved issues include whether the new
unbundled transportation and storage services provided by
Columbia Transmission, and the replacement natural gas supplies
provided by others, will result in the same degree of service<PAGE>
<PAGE> 67
reliability as the bundled firm sales service Columbia
Transmission has provided to Mountaineer in the past. Because of
these issues and others, Mountaineer has petitioned for appellate
review of both the 636 Orders and the orders approving the
implementation of Columbia Transmission's restructuring pursuant
to the 636 Orders. Mountaineer's management continues to
actively participate in Columbia Transmission's compliance
filings in order to protect Mountaineer's interests, ensure the
continued reliability of service to its customers and minimize
future transition costs.
Until Mountaineer's pipeline suppliers' rate filings to implement
restructuring, including subsequent filings to recover
transition costs, are fully approved by the FERC, the ultimate
amount of the costs associated with restructuring cannot be
ascertained. However, Mountaineer's management anticipates that
the amount of restructuring costs that will be passed through to
Mountaineer will be significant. Mountaineer will attempt to
obtain approval from the PSCWV to recover any such approved
restructuring costs from its customers. On the basis of previous
state regulatory proceedings involving the recovery of gas
purchase costs and take-or-pay obligations, Mountaineer believes
that the costs passed through from its pipeline suppliers will be
recovered from ratepayers, although there can be no assurance
that this will be the case.
On July 31, 1991, Columbia Transmission and The Columbia Gas
System, Inc. (the Columbia Companies) filed for protection under
Chapter 11 of the Bankruptcy Code. The Columbia Companies stated
that the primary basis for their filing was the failure of
Columbia Transmission to acquire natural gas through existing
producer contracts under terms and conditions, including price,
which would permit Columbia Transmission to compete in the
marketplace. Columbia Transmission's filing could affect its
relationship with Mountaineer. Although Mountaineer only
purchased 1% of its gas supplies from Columbia Transmission
during fiscal 1994, Mountaineer relies upon Columbia Transmission
for the delivery of a majority of Mountaineer's gas supplies.
On January 18, 1994, Columbia Transmission filed a proposed plan
of reorganization in the bankruptcy proceedings, but requested
the Bankruptcy Court to defer all further proceedings on such
plan pending further discussions with Columbia Transmission's
major creditors and official committees, including the official
committee of customers which Mountaineer chairs. The plan, if
ultimately approved by the Bankruptcy Court and accepted by
Columbia Transmission's customers, would inter alia, (i) pay
Columbia Transmission's customers 100% of certain refund amounts
ordered by the FERC, but at a lower interest rate than provided
by the FERC, (ii) pay Columbia Transmission's customers 90% of
certain other refunds ordered by the FERC, and (iii) require any
customer accepting the plan to waive its entitlement to all other
refund amounts and to not oppose Columbia Transmission's recovery
from such customers of approximately $250 million in certain
costs to be filed with the FERC. Discussions on the proposed
plan are at a preliminary stage and Columbia Transmission is in
the process of providing additional information necessary to<PAGE>
<PAGE> 68
evaluate the proposal. However, at this stage, various aspects
of the proposal appear unacceptable to the official committee of
customers.
In addition, the United States Court of Appeals of the District
of Columbia Circuit recently granted an appeal filed by
Mountaineer and others which challenged Columbia Transmission's
right to recover through FERC-approved rates over $120 million in
take-or-pay costs from its customers. Once the court s decision
becomes final, the case will be remanded to the FERC for further
proceedings to determine the level of refunds owed Columbia
Transmission's customers. The refund amount determined may have
a significant bearing on Columbia Transmission's proposed plan of
reorganization and any negotiated resolution thereof.
Mountaineer is vigorously opposing Columbia Transmission's
efforts to recover costs related to its Chapter 11 bankruptcy
proceedings. The outcome of these proceedings could materially
affect Mountaineer's prices to its customers. Mountaineer is
reviewing its options, including the level of Columbia
Transmission's role in providing service to Mountaineer in the
future. Mountaineer's management continues to be actively
involved in this process in order to minimize any adverse impact
on the interests of Mountaineer or its customers.
Legal Matters
Cameron Gas Company and C. Richard Coleman, et al. vs. Allegheny
& Western Energy Corporation, Mountaineer Gas Company and Gas
Access Systems, Inc. was filed on December 31, 1992, in the
Circuit Court of Marshall County, West Virginia. Plaintiffs
allege unlawful and/or tortious conduct and violations of the
Racketeer Influenced and Corrupt Organizations Act (RICO) and the
West Virginia Anti-Trust Act, arising out of the termination of a
gas sales agreement and seek $30 million compensatory damages and
$90 million punitive damages. Upon the petition of the Company,
the case was removed to the United States District Court for the
Northern District of West Virginia. On February 19, 1993, the
Company filed responsive dispositive pleadings to the complaint,
including a motion to dismiss. By Order issued March 31, 1994,
and clarified by Order issued April 18, 1994, the West Virginia
anti-trust claim against Allegheny & Western Energy Corporation,
Mountaineer Gas Company and Gas Access Systems, Inc. was
dismissed with prejudice. In addition, the RICO claim was
dismissed against Allegheny & Western Energy Corporation with
prejudice. On April 14, 1994, Mountaineer filed a general denial
to plaintiffs' complaint and a counterclaim seeking at least
$150,000 in compensatory and $2.0 million in punitive damages for
the willful withholding by Cameron of monies collected by Cameron
as agent for certain of the Company's customers and intended to
be paid to the Company for services rendered by the Company. In
response to the April 18, 1994 Order, the plaintiffs filed an
amended complaint to which the Company has filed responsive
pleadings, including a motion to dismiss, and a counterclaim.
The pleadings remain pending before the Court for disposition.
Discovery has commenced. No trial date has been set. The
Company believes Cameron's claims are without merit and plans to<PAGE>
<PAGE> 69
vigorously defend this matter and does not believe that this
matter is reasonably likely to have a material adverse effect on
the financial position and results of operations of the Company.
The Company has been named as a defendant in various other legal
actions which arise primarily in the ordinary course of business.
In management's opinion, these outstanding claims are unlikely to
result in a material adverse effect on the Company's financial
position and results of operations.
Performance Bonds
To acquire the petroleum prospecting licenses in New Zealand,
AWENZ and its partner posted a performance bond of NZ $500,000
(US $297,500 as of June 30, 1994), which is a normal requirement
of the Minister of Energy. Should AWENZ and its partner not
perform their commitments as required by the license, the
government of New Zealand could elect to call the bonds, which
would require the payment by AWENZ of 59.5% of such amount. To
the best of management's knowledge, all such commitments
currently required by the licenses have been performed.
Rate Matters
On March 30, 1994, the PSCWV issued a final order which put
Mountaineer on notice that in its next rate case, any savings
generated by Mountaineer's participation in a consolidated tax
return would be passed through to Mountaineer's ratepayers unless
persuasive legal or accounting arguments are presented to the
PSCWV to convince them to act otherwise. Management is unable to
determine what impact the consolidated tax savings issue will
have on Mountaineer's future results of operations.
(20) ACCOUNTING PRONOUNCEMENTS NOT EFFECTIVE
In November 1992, the FASB issued SFAS No. 112 "Employers
Accounting for Postemployment Benefits." This statement requires
employers to recognize any obligation which exists to provide
benefits to former or inactive employees after employment, but
before retirement. Such benefits include, but are not limited to,
salary continuations, supplemental unemployment, severance
disability (including workers' compensation), job training,
counseling and continuation of benefits such as health care and
life insurance. Currently, the Company provides only for
workers' compensation benefits which would qualify as
postemployment benefits under this standard.
The Company will adopt this statement in fiscal 1995. The
adoption of SFAS No. 112 is not expected to have a material
impact on the Company's results of operations.
Item 9. Disagreements on Accounting and Financial Disclosure
None
PART III<PAGE>
<PAGE> 70
Item 10. Directors and Executive Officers of the Registrant
Information concerning the directors of the Company is hereby
incorporated by reference to the Company's definitive proxy
statement filed with the Commission pursuant to Regulation 14A
within 120 days after the close of the Company's fiscal year.
Information concerning the executive officers of the Company is
contained in Item 1 of this report.
Item 11. Executive Compensation
This information is hereby incorporated by reference to the
Company's definitive proxy statement filed with the Commission
pursuant to Regulation 14A within 120 days after the close of the
Company's fiscal year.
Item 12. Security Ownership of Certain Beneficial Owners and
Management
This information is hereby incorporated by reference to the
Company's definitive proxy statement filed with the Commission
pursuant to Regulation 14A within 120 days after the close of the
Company's fiscal year.
Item 13. Certain Relationships and Related Transactions
This information is hereby incorporated by reference to the
Company's definitive proxy statement filed with the Commission
pursuant to Regulation 14A within 120 days after the close of the
Company's fiscal year.
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K
(a) (1) Financial Statements:
See Index to Consolidated Financial Statements on page
25.
(2) The following financial statement schedules for the years
ended June 30, 1994, 1993 and 1992 are submitted herewith:
Schedule V - Property, Plant and Equipment
Schedule VI - Accumulated Depletion, Depreciation and
Amortization of Property, Plant and
Equipment
Schedule VIII - Valuation and Qualifying Accounts
Schedule X - Supplementary Income Statement
Information<PAGE>
<PAGE> 71
All other schedules are omitted because they are not
required, inapplicable, or the information is included
in the consolidated financial statements or notes
thereto.
(3) Exhibits:
See Exhibit Index for list of exhibits filed with this
report.
(b) Reports on Form 8-K:
None<PAGE>
<PAGE> 72
<TABLE>
ALLEGHENY & WESTERN ENERGY CORPORATION
AND SUBSIDIARIES
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT
<CAPTION>
Column A Column B Column C Column D Column E Column F
Other
Balance at Changes Balance at
Beginning Additions Add (Deduct) End of
Description of Period at Cost Retirements Describe Period
<S> <C> <C> <C> <C> <C>
Year ended June
30, 1994:
Utility plant $ 137,737,323 $12,831,730 $2,819,353 $ 1,496,169 <F1> $ 149,245,869
Oil and gas
properties 43,538,030 6,000 4,333,017 (98,585) <F2> 39,112,428
Gas gathering
systems 13,116,959 --- 456,094 --- 12,660,865
Transmission
plant 4,736,819 66,144 --- 167,252 <F2> 4,970,215
Other 7,295,024 366,409 128,552 --- 7,532,881
------------- ----------- ---------- ----------- -------------
$ 206,424,155 $13,270,283 $7,737,016 $ 1,564,836 $ 213,522,258
============= =========== ========== =========== =============
Year ended June
30, 1993:
Utility plant $ 122,879,794 $14,970,212 $1,609,334 $ 1,496,651 <F3> $ 137,737,323
Oil and gas
properties 38,598,014 3,991,137 451,588 1,400,467 <F4> 43,538,030
Gas gathering
systems 13,116,959 --- --- --- 13,116,959
Transmission
plant --- 3,236,819 --- 1,500,000 <F5> 4,736,819
Other 7,665,465 136,099 506,540 --- 7,295,024
------------- ----------- ---------- ----------- -------------
$ 182,260,232 $22,334,267 $2,567,462 $ 4,397,118 $ 206,424,155
============= =========== ========== =========== =============
Year ended June
30, 1992:
Utility plant $ 113,939,621 $ 8,769,714 $1,325,710 $ 1,496,169 <F1> $ 122,879,794
Oil and gas
properties 43,263,578 496,710 37,545 (5,124,729) <F6> 38,598,014
Gas gathering
systems 13,116,959 --- --- --- 13,116,959
Other 8,047,302 267,500 596,337 (53,000) <F7> 7,665,465
------------- ----------- ---------- ----------- -------------
$ 178,367,460 $ 9,533,924 $1,959,592 $(3,681,560) $ 182,260,232
============= =========== ========== =========== =============
<FN>
<F1> Negative goodwill amortization.
<F2> Includes reclassification relating to purchase price allocation and other
miscellaneous items.
<F3> Includes $1,496,169 of negative goodwill amortization and $482 of miscellaneous
adjustments.
<F4> Includes $1,500,000 of purchase price allocation related to gas contract reserves<PAGE>
<PAGE> 73
and $(99,533) of miscellaneous adjustments.
<F5> Purchase price allocation related to gas contract reserves.
<F6> Includes ($5,061,505) related to the sale of TEX-HEX properties and $(63,224) of
miscellaneous adjustments.
<F7> Write-down of certain office equipment to net realizable value.
</FN>
</TABLE>
<TABLE>
ALLEGHENY & WESTERN ENERGY CORPORATION
AND SUBSIDIARIES
SCHEDULE VI - ACCUMULATED DEPLETION, DEPRECIATION, AND
AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT
<CAPTION>
Column A Column B Column C Column D Column E Column F
Additions Other
Balance at Charged to Changes Balance at
Beginning Cost and Add (Deduct) End of
Description of Period Expenses Retirements Describe Period
<S> <C> <C> <C> <C> <C>
Year ended June
30, 1994:
Utility plant $ 37,429,316 $ 7,335,388 $2,819,352 $ (222,954) <F1> $ 41,722,398
Oil and gas
properties 18,587,927 2,078,770 3,894,371 --- 16,772,326
Gas gathering
systems 4,069,690 675,251 178,308 --- 4,566,633
Transmission
plant 39,782 164,414 --- --- 204,196
Other 1,978,697 648,375 127,583 --- 2,499,489
------------- ----------- ---------- ----------- -------------
$ 62,105,412 $10,902,198 $7,019,614 $ (222,954) $ 65,765,042
============= =========== ========== =========== =============
Year ended June
30, 1993:
Utility plant $ 32,370,857 $ 6,823,322 $1,609,333 $ (155,530) <F2> $ 37,429,316
Oil and gas
properties 16,863,717 2,148,797 424,587 --- 18,587,927
Gas gathering
systems 3,266,761 802,929 --- --- 4,069,690
Transmission
plant --- 39,782 --- --- 39,782
Other 1,904,380 488,098 413,781 --- 1,978,697
------------- ----------- ---------- ----------- -------------
$ 54,405,715 $10,302,928 $2,447,701 $ (155,530) $ 62,105,412
============= =========== ========== =========== =============
Year ended June
30, 1992:
Utility plant $ 27,473,149 $ 6,358,365 $1,325,710 $ (134,947) <F3> $ 32,370,857
Oil and gas
properties 18,389,849 2,978,035 --- (4,504,167) <F4> 16,863,717
Gas gathering<PAGE>
<PAGE> 74
systems 2,526,306 740,455 --- --- 3,266,761
Other 1,782,254 579,284 457,158 --- 1,904,380
------------- ----------- ---------- ----------- -------------
$ 50,171,558 $10,656,139 $1,782,868 $(4,639,114) $ 54,405,715
============= =========== ========== =========== =============
<FN>
<F1> Consists of ($308,720) of cost of removal and $85,766 of net salvage value.
<F2> Consists of ($230,573) of cost of removal and $75,043 of net salvage.
<F3> Consists of ($239,970) of cost of removal and $105,023 of net salvage.
<F4> This amount represents the reduction in accumulated depletion, depreciation and
amortization related to the sale of TEX-HEX properties.
</FN>
</TABLE>
<TABLE>
ALLEGHENY & WESTERN ENERGY CORPORATION
AND SUBSIDIARIES
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS
<CAPTION>
Additions
Balance at Charged to Deductions Balance at
Beginning Results of from End of
Description of Period Operations Other Reserves Period
<S> <C> <C> <C> <C> <C>
Reflected as
reductions to the
related assets:
Accumulated
provision for
uncollectible
accounts
(deduction from
accounts
receivable-trade)
June 30, 1994 $1,307,204 $1,104,508 $351,737 <F1> $1,334,141 <F2> $1,429,308
June 30, 1993 1,660,500 836,000 249,471 <F1> 1,438,767 <F2> 1,307,204
June 30, 1992 1,488,423 1,183,773 262,119 <F1> 1,273,815 <F2> 1,660,500
<FN>
<F1> Collection of accounts previously written off.
<F2> Uncollectible accounts written off.<PAGE>
<PAGE> 75
</FN>
/TABLE
<PAGE>
<PAGE> 76
<TABLE>
ALLEGHENY & WESTERN ENERGY CORPORATION
AND SUBSIDIARIES
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
<CAPTION>
Year Ended Year Ended Year Ended
June 30, 1994 June 30, 1993 June 30, 1992
<S> <C> <C> <C>
Maintenance and
repairs $ 4,012,571 $ 4,074,204 $ 3,958,383
Taxes, other than
income taxes
(primarily
business and
occupational
taxes) $ 14,429,458 $ 13,413,379 $ 13,123,764
</TABLE>
All other required captions are less than one percent of sales.<PAGE>
<PAGE> 77
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Company has duly caused this
report to be signed on its behalf by the undersigned, thereunto
duly authorized.
ALLEGHENY & WESTERN ENERGY
CORPORATION
(Registrant)
/s/ John G. McMillian
John G. McMillian
Chairman of the Board of
Directors, President and Chief
Executive Officer
Date: September 27, 1994
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the Company and in the capacities and on the dates
indicated:
/s/ John G. McMillian /s/ W. Merwyn Pittman
John G. McMillian W. Merwyn Pittman
Director, Chairman of the Board Vice President, Chief
of Directors, President and Financial Officer and
Chief Executive Officer Treasurer
/s/ Michael S. Berman /s/ Henry Tauber
Michael S. Berman Henry Tauber
Director Director
/s/ Sidney S. Lindley /s/ Jack H. Vaughn
Sidney S. Lindley Jack H. Vaughn
Director Director
/s/ Rush Moody, Jr. /s/ Harold M. Wit
Rush Moody, Jr. Harold M. Wit
Director Director<PAGE>
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
________________________________________________
ANNUAL REPORT
ON
FORM 10-K
FOR THE
FISCAL YEAR ENDED
JUNE 30, 1994
________________________________________________
ALLEGHENY & WESTERN ENERGY CORPORATION
_____________________
EXHIBITS
_____________________<PAGE>
Exhibit Index
Exhibit
Number Exhibit Reference
3.1 Articles of Incorporation of Allegheny Incorporated
and Western Energy Corporation dated by reference
June 4, 1984. to Exhibit D
to Form 8-K
dated July 3,
1984.
3.2 Amendment to Articles of Incorporation Incorporated
of Allegheny & Western Energy Corporation, reference to
dated August 2, 1990. Exhibit 3.2
to Form 10-K
for the year
ended June
30, 1990.
3.3 Bylaws of Allegheny & Western Energy Filed
Corporation herewith
10.1 Appalachian Basin Pipeline Agreement. Incorporated
by reference
to Exhibit
10.1.2 to
Amendment
No.1 to Form
S-1
Registration
Statement No.
2-71252.
10.2 Columbia Gas Transmission Corporation Incorporated
Gas Purchase Contract containing typical by reference
"take or pay" contract provisions. to Exhibit
10.4 to Form
S-1
Registration
Statement No.
2-71252.
10.3 Revolving Credit and Term Loan Agreement, Incorporated
dated as of June 13, 1989, between the by reference
registrant and the First National Bank to Exhibit
of Boston. 10.3 to Form
10-K for the
year ended
June 30,
1989.
10.4 Revolving Credit and Term Loan Agreement, Incorporated
dated as of June 13, 1989, between by reference
Mountaineer Gas Company and the First to Exhibit
National Bank of Boston. 10.5 to Form
10-K for the
year ended
June 30,
1989.<PAGE>
10.5 Note Agreement, dated June 30, 1987, Incorporated
between Mountaineer and Connecticut by reference
General Life Insurance Company, Horace to Exhibit
Mann Life Insurance Company, INA Life 10.5 to Form
Insurance Company of New York and Life 10-K for the
Insurance Company of North America. year ended
June 30,
1990.
10.6 Participation Agreement, dated March 8, Incorporated
1990, among TEX-HEX Corporation, Louran by reference
Oil & Gas, Inc., AHI Drilling, Inc., to Exhibit
SHIGO, Inc., Rush Moody, Jr., Peter W. 10.6 to Form
Stevens, John Bielun, Andrew R. Fair, 10-K for the
Jonathan Conrad and Richard Grant. year ended
June 30,
1990.
10.7 Credit Agreement, dated September 24, Incorporated
24, 1990, among Allegheny & Western by reference
Energy Corporation, Pittsburgh National to Exhibit
Bank, and One Valley Bank, N.A. and 10.7 to Form
Pittsburgh National Bank as Agent. 10-K for the
year ended
June 30,
1990.
10.8 1987 Stock Option Plan (including form Incorporated
of Stock Option Agreement). by reference
to Exhibit
10.8 to Form
10-K for the
year ended
June 30,
1990.
10.9 Credit Agreement, dated June 27, 1991, Incorporated
between Mountaineer Gas Company and by reference
Pittsburgh National Bank. to Exhibit
10.9 to Form
10-K for the
year ended
June 30,
1991.
10.10 Credit Agreement, dated June 27, 1991, Incorporated
between Mountaineer Gas Company and by reference
Pittsburgh National Bank. to Exhibit
10.10 to Form
10-K for the
year ended
June 30,
1991.
10.11 Agreements for Gas Purchase and Transpor- Incorporated
tation Service between Mountaineer Gas by reference
Company and Columbia Gas Transmission to Exhibit
Corp. 10.11 to Form
10-K for the
year ended<PAGE>
June 30,
1991.
10.12 Second Amendment, dated October 31, 1991, Incorporated
to Credit Agreement, dated September 21, by reference
1990 among Allegheny & Western Energy to Exhibit
Corporation, Pittsburgh National Bank and 10.12 to Form
One Valley Bank, N.A. and Pittsburgh 10-Q for the
National Bank as agent. National Bank as quarter ended
agent. September 30,
1991.
10.13 Third Amendment dated November 30, 1991, Incorporated
to Credit Agreement, dated September 24, by reference
1990, among Allegheny & Western Energy to Exhibit
Corporation, Pittsburgh National Bank 10.13 to Form
and One Valley Bank, N.A. and Pittsburgh 10-Q for the
National Bank as agent. quarter ended
December 31,
1991.
10.14 Note Purchase Agreement, dated July 15, Incorporated
1992, between Mountaineer Gas Company and by reference
Teachers Insurance and Annuity Association to Exhibit
of America. 10.14 to Form
10-K for the
year ended
June 30,
1992.
10.15 Employment Agreement, dated June 13, 1990 Incorporated
between Mr. Grant and Mountaineer Gas by reference
Company. to Exhibit
10.15 to Form
10-K for the
year ended
June 30,
1992.
10.16 Employment Agreement, dated June 13, 1990 Incorporated
between Mr. Fletcher and Mountaineer by reference
Gas Company. to Exhibit
10.16 to Form
10-K for the
year ended
June 30,
1992.
10.17 Consulting Agreement, dated March 1, 1992 Incorporated
between Mr. Lindley and the Company. by reference
to Exhibit
10.17 to Form
10-K for the
year ended
June 30,
1992.
10.18 Fourth Amendment, dated October 31, 1992, Incorporated
to Credit Agreement, dated September 24, by reference<PAGE>
1990, among Allegheny & Western Energy to Exhibit
Corporation, Pittsburgh National Bank and 10.18 to Form
One Valley Bank, N.A. and Pittsburgh 10-Q for the
National Bank as agent. quarter ended
March 31,
1993.
10.19 Fifth Amendment, dated November 30, 1992, Incorporated
to Credit Agreement dated September 24, by reference
1990, among Allegheny & Western Energy to Exhibit
and One Valley Bank, N.A. and Pittsburgh 10-Q for the
National Bank as agent. quarter ended
March 31,
1993.
10.20 Purchase and Sales Agreement, dated Incorporated
July 21, 1992 among Hallwood Energy by reference
Partners, L.P. et. al and Mountaineer to Exhibit
Gas Company. 10.20 to Form
10-Q for the
quarter ended
March 31,
1993.
10.21 Sixth Amendment, dated September 28, Incorporated
1993, to Credit Agreement, dated by reference
September 24, 1990, among Allegheny to Exhibit
and Western Energy Corporation, 10.21 to Form
Pittsburgh National Bank and One 10-Q for the
Valley Bank, N.A. and Pittsburgh quarter ended
National Bank as agent. September 30,
1993.
10.22 Seventh Amendment, dated October 31, Incorporated
1993, to Credit Agreement, dated by reference
September 24, 1990, among Allegheny to Exhibit
and Western Energy Corporation, 10.22 to Form
Pittsburgh National Bank and One 10-Q for the
Valley Bank, N.A. and Pittsburgh quarter ended
National Bank as agent. December 31,
1993.
10.23 Employment Agreements with Richard Incorporated
L. Grant, Michael S. Fletcher and W. by reference
Merwyn Pittman, individually. to Exhibit
10.23 to Form
10-Q for the
quarter ended
December 31,
1993.
10.24 Supplemental Retirement Benefit Plan Incorporated
Agreements between John G. McMillian, by reference
Richard L. Grant, Michael S. Fletcher to Exhibit
and W. Merwyn Pittman, individually, and 10.24 to Form
Allegheny & Western Energy Corporation. 10-Q for the
quarter ended
December 31,
1993.<PAGE>
21.1 Subsidiaries of the Company. Filed
herewith
27.1 Financial Data Schedule Filed
herewith<PAGE>
EXHIBIT
NUMBER DESCRIPTION
3.3 Bylaws of Allegheny & Western Energy Corporation<PAGE>
<PAGE> 1
AMENDED AND RESTATED
BYLAWS
OF
ALLEGHENY & WESTERN ENERGY CORPORATION
Article I. Offices.
The principal office of the Corporation shall be
located at 300 Capitol Street, Suite 1600, the City of
Charleston, County of Kanawha, and the State of West Virginia.
The Corporation may have such other offices, either within or
without the State of West Virginia, as the board of directors may
designate or as the business of the Corporation may require from
time to time.
Article II. Shareholders.
Section 1. Annual Meeting. The annual meeting of the
shareholders shall be held on the second Thursday in the month of
December, in each year, beginning with the year 1993, at 9:30
A.M., or such other date and/or time as may be determined by the
board of directors, for the purpose of electing directors and for
the transaction of such other business as may come before the
meeting.
Section 2. Special Meetings. Special meetings of the
shareholders, for any purpose or purposes, unless otherwise
prescribed by statute, may be called by the president or by the
board of directors, and shall be called by the president at the
request of the holders of not less than l0% of all the<PAGE>
<PAGE> 2
outstanding shares of the Corporation entitled to vote at the
meeting.
Section 3. Place of Meeting. The board of directors
may designate any place, either within or without the State of
West Virginia, as the place of meeting for any annual meeting or
for any special meeting called by the board of directors. A
waiver of notice signed by all shareholders entitled to vote at a
meeting may designate any place, either within or without the
State of West Virginia, as the place for the holding of such
meeting. If no designation is made, or if a special meeting be
otherwise called, the place of meeting shall be the principal
office of the Corporation in the State of West Virginia.
Section 4. Notice of Meeting. Written or printed
notice stating the place, day, and hour of the meeting and, in
case of a special meeting, the purpose or purposes for which the
meeting is called, shall be delivered not less than ten nor more
than fifty days before the date of the meeting, either personally
or by mail, by or at the direction of the president, or the
secretary, or the officer or persons calling the meeting, to each
shareholder of record entitled to vote at such meeting. If
mailed, such notice shall be deemed to be delivered when
deposited in the United States mail, addressed to the shareholder
at his address as it appears on the stock transfer books of the
Corporation, with postage thereon prepaid.
Section 5. Closing of Transfer Books or Fixing of
Record Date. For the purpose of determining shareholders
entitled to notice of or to vote at any meeting of shareholders
or any adjournment thereof, or shareholders entitled to receive<PAGE>
<PAGE> 3
payment of any dividend, or in order to make a determination of
shareholders for any other proper purpose, the board of directors
of the Corporation may provide that the stock transfer books
shall be closed for a stated period but not to exceed, in any
case, 50 days. If the stock transfer books shall be closed for
the purpose of determining shareholders entitled to notice of or
to vote at a meeting of shareholders, such books shall be closed
for at least ten days immediately preceding such meeting. In
lieu of closing the stock transfer books, the board of directors
may fix in advance a date as the record date for any such
determination of shareholders, such date in any case to be not
more than 50 days and, in case of a meeting of shareholders, not
less than ten days prior to the date on which the particular
action, requiring such determination of shareholders, is to be
taken. If the stock transfer books are not closed and no record
date is fixed for the determination of shareholders entitled to
notice of or to vote at a meeting of shareholders, or
shareholders entitled to receive payment of a dividend, the date
on which notice of the meeting is mailed or the date on which the
resolution of the board of directors declaring such dividend is
adopted, as the case may be, shall be the record date for such
determination of shareholders. When a determination of
shareholders entitled to vote at any meeting of shareholders has
been made as provided in this section, such determination shall
apply to any adjournment thereof.
Section 6. Voting Record. The officer or agent
having charge of the stock transfer books for shares of the
Corporation shall make a complete record of the shareholders
entitled to vote at such meeting, or any adjournment thereof,<PAGE>
<PAGE> 4
arranged in alphabetical order, with the address of and the
number of shares held by each, which list shall be kept on file
at the office of the Corporation and shall be subject to
inspection by any shareholder at any time during usual business
hours. Such list shall also be produced and kept open at the
time and place of the meeting and shall be subject to the
inspection of any shareholder during the whole time of the
meeting. The original stock transfer book shall be prima facie
evidence as to who are the shareholders entitled to examine such
list or transfer books or to vote at any meeting of shareholders.
Section 7. Quorum. A majority of the outstanding
shares of the Corporation entitled to vote, represented in person
or by proxy, shall constitute a quorum at a meeting of
shareholders. If less than a majority of the outstanding shares
are represented at a meeting, a majority of the shares so
represented may adjourn the meeting from time to time without
further notice. At any reconvening of such previously adjourned
meeting at which a quorum shall be present or represented, any
business may be transacted which might have been transacted at
the meeting as originally notified. The shareholders present at
a duly organized meeting may continue to transact business until
adjournment, notwithstanding the withdrawal of enough
shareholders to leave less than a quorum.
Section 8. Proxies. At all meetings of shareholders,
a shareholder may vote by proxy executed in writing by the
shareholder or by his duly authorized attorney in fact. Such
proxy shall be filed with the secretary of the Corporation before
or at the time of the meeting. No proxy shall be valid after<PAGE>
<PAGE> 5
eleven months from the date of its execution, unless otherwise
provided in the proxy.
Section 9. Voting of Shares. Subject to the
provisions of Section 11 of this Article II, each outstanding
share entitled to vote shall be entitled to one vote upon each
matter submitted to a vote at a meeting of shareholders.
Section 10. Voting of Shares by Certain Holders.
Shares standing in the name of another Corporation, domestic or
foreign, may be voted by such officer, agent or proxy as the
bylaws of such other Corporation may prescribe or, in the absence
of such provision, as the board of directors of such other
Corporation may determine.
Shares held by an administrator, executor, guardian,
committee, curator, or conservator may be voted by him, either in
person or by proxy, without a transfer of such shares into his
name. Shares standing in the name of a trustee may be voted by
him, either in person or by proxy, but no trustee shall be
entitled to vote shares held by him without a transfer of such
shares into his name.
Shares standing in the name of a receiver may be voted
by such receiver, and shares held by or under the control of a
receiver may be voted by such receiver without the transfer
thereof into his name if authority so to do be contained in an
appropriate order of the court by which such receiver was
appointed.
A shareholder whose shares are pledged shall be
entitled to vote such shares until the shares have been
transferred into the name of the pledgee, and thereafter the<PAGE>
<PAGE> 6
pledgee shall be entitled to vote the shares so transferred.
On and after the date on which written notice of
redemption of redeemable shares has been mailed to the holders
thereof and a sum sufficient to redeem such shares has been
deposited with a bank or trust company with irrevocable
instruction and authority to pay the redemption price to the
holders thereof upon surrender of certificates therefor, such
shares shall not be entitled to vote on any matter and shall not
be deemed to be outstanding shares.
Section 11. Cumulative Voting. At each election for
directors every shareholder entitled to vote at such election
shall have the right to vote, in person or by proxy, the number
of shares owned by him for as many persons as there are directors
to be elected and for whose election he has a right to vote, or
to cumulate his votes by giving one candidate as many votes as
the number of such directors multiplied by the number of his
shares shall equal, or by distributing such votes on the same
principle among any number of candidates.
Section 12. Meeting by Electronic Communication. One
or more shareholders may participate in a meeting of the
shareholders by means of conference telephone or similar
electronic communications equipment by means of which all persons
participating in the meeting can hear each other. Whenever a
vote of the shareholders is required or permitted in connection
with any corporate action this vote may be taken orally during
this conference. The agreement thus reached shall have like
effect and validity as though the action were duly taken by the
action of the shareholders at a meeting of shareholders if the<PAGE>
<PAGE> 7
agreement is reduced to writing and approved by the shareholders
at the next regular meeting of the shareholders after the
conference.
Section 13. Informal Action. Whenever the vote of
shareholders or members at a meeting thereof is required or
permitted to be taken in connection with any corporate action,
the meeting and vote of the shareholders or members may be
dispensed with if all of the shareholders or members who would
have been entitled to vote upon the action agree in writing to
the corporate action being taken. The agreement shall have like
effect and validity as though the action were duly taken by the
unanimous action of all shareholders or members entitled to vote
at a meeting of the shareholders or members duly called and
legally held.
Article III. Board of Directors.
Section 1. General Powers. The business and affairs
of the Corporation shall be managed by its board of directors.
Section 2. Number, Election, Tenure and Quali-
fications. The number of directors of the Corporation shall be
seven (7) or such other number not to exceed fourteen (14) as the
board of directors may establish by resolution. The director or
directors shall hold office until the next annual meeting of
shareholders and until his or their successor or successors has
or shall have been elected and qualified. Directors need not be
residents of the State of West Virginia or a shareholder of the
Corporation.<PAGE>
<PAGE> 8
Section 3. Regular Meetings. A regular meeting of
the board of directors shall be held without other notice than
this bylaw immediately after, and at the same place as, the
annual meeting of shareholders. The board of directors may
provide, by resolution, the time and place, either within or
without the State of West Virginia for the holding of additional
regular meetings without other notice than such resolution.
Section 4. Special Meetings. Special meetings of the
board of directors may be held at any time by the call of the
president or any two (2) directors. The person or persons
authorized to call special meetings of the board of directors may
fix any place, either within or without the State of West
Virginia, as the place for holding any special meeting of the
board of directors called by them.
Section 5. Notice. Notice of any special meeting
shall be given by written notice delivered personally, by mail,
or by telegram to each director at his business address as
appearing in the records of the Corporation. Notice shall be
deemed to be delivered when received at the address of the
director and must be given at least two (2) days prior to the
meeting. The presence of any director at a meeting shall
constitute a waiver of notice of such meeting as to that
director, except when a director attends a meeting for the
express purpose of objecting to the transaction of any business
because the meeting is not lawfully called or convened. Neither
the business to be transacted at, nor the purpose of, any regular
or special meeting of the board of directors need be specified in
the notice or waiver of notice of such meeting except that such<PAGE>
<PAGE> 9
notice must set forth the nature of the business intended to be
transacted if such business is (a) amending the bylaws or
(b) authorizing the sale of all or substantially all of the
assets of the Corporation.
Section 6. Quorum. A majority of the number of
directors fixed by Section 2 of this Article III shall constitute
a quorum of the transaction of business at any meeting of the
board of directors, but if less than such majority is present at
a meeting, a majority of the directors present may adjourn the
meeting from time to time without further notice.
Section 7. Manner of Acting. The act of the majority
of the directors present at a meeting at which a quorum is
present shall be the act of the board of directors; provided,
however, that in the event any matter should come before the
board of directors as to which one of the directors has or may
have a conflict of interest, said director shall abstain from
voting thereon, and the remaining director or directors, as the
case may be, shall have full and complete authority to consider
and vote upon such matter, and such vote shall be binding upon
the Corporation.
Section 8. Vacancies. Any vacancy occurring in the
board of directors may be filled by the affirmative vote of a
majority of the remaining directors though less than a quorum of
the board of directors. A director elected to fill a vacancy
shall be elected for the unexpired term of his predecessor in
office. Any directorship to be filled by reason of an increase
in the number of directors may be filled by the board of
directors at their regular meeting or at a special meeting called<PAGE>
<PAGE> 10
for that purpose, for a term of office continuing only until the
next election of directors.
Section 9. Compensation. By resolution of the board
of directors, the directors may be paid their expenses, if any,
of attendance at each meeting of the board of directors, and may
be paid a fixed sum for attendance at each meeting of the board
of directors or a stated salary as director. No such payment
shall preclude any director from serving the Corporation in any
other capacity and receiving compensation therefor.
Section 10. Presumption of Assent. A director of the
Corporation who is present at a meeting of the board of directors
at which action on any corporate matter is taken shall be
presumed to have assented to the action taken unless his dissent
shall be entered in the minutes of the meeting or unless he shall
file his written dissent to such action with the person acting as
the secretary of the meeting before the adjournment thereof or
shall forward such dissent by registered mail to the secretary of
the Corporation immediately after the adjournment of the meeting.
Such right to dissent shall not apply to a director who voted in
favor of such action.
Section 11. Meeting by Electronic Communication. One
or more directors may participate in a meeting of the directors
by means of conference telephone or similar electronic
communications equipment by means of which all persons
participating in the meeting can hear each other. Whenever a
vote of the directors is required or permitted in connection with
any corporate action this vote may be taken orally during this
conference. The agreement thus reached shall have like effect<PAGE>
<PAGE> 11
and validity as though the action were duly taken by the action
of the directors at a meeting of directors if the agreement is
reduced to writing and approved by the directors at the next
regular meeting of the directors after the conference.
Section 12. Informal Action. Whenever the vote of
directors at a meeting thereof is required or permitted to be
taken in connection with any corporate action, the meeting and
vote of the directors may be dispensed with if all the directors
agree in writing to the corporate action being taken. The
agreement shall have like effect and validity as though the
actions were duly taken by the unanimous action of all directors
at a meeting of the directors duly called and legally held.
Article IV. Committees.
Section 1. Executive Committee. The board of
directors may, in its discretion, by resolution adopted by a
majority of the whole board, constitute a general executive
committee for the board, appoint the members thereof, who shall
be board members, and specify its authority and responsibility.
Members of said committee shall serve at the pleasure of the
board. The executive committee shall have such powers and shall
perform such duties as the board may delegate to it in writing
from time to time, including the immediate oversight and
management of the business affairs of the Corporation, except
that the committee shall have no power to declare dividends or to
adopt, amend, or repeal the bylaws of the Corporation.
The executive committee shall be organized and shall
perform its functions as directed by the board and shall report
periodically to the board. The committee shall act by a majority<PAGE>
<PAGE> 12
of the members thereof, and any action duly taken by the
executive committee within the course and scope of its authority
shall be binding on the Corporation.
The executive committee may be abolished at any time
by the vote of a majority of the board of directors at any
meeting of the board, and during the course of the committee's
existence, the membership thereof may be increased or decreased
and the authority and duties of the committee changed by the
board of directors as it may deem appropriate.
The Chairman of the Executive Committee shall be appointed
from time to time by the Board of Directors, and the Secretary of
the Corporation shall act as Secretary thereof. In the absence
from any meeting of the Executive Committee of its Chairman, the
President of the Corporation, if then present, shall act as
Chairman of the meeting, and in the absence of the President, the
Committee shall appoint a Chairman of the meeting. In the
absence from any meeting of the Executive Committee of its
Secretary, the Executive Committee shall appoint a Secretary of
the meeting.
Section 2. Other Committees. The board of directors,
at its discretion, may constitute and appoint special committees,
in addition to the executive committee, to assist in the
supervision, management, and control of the affairs of the
Corporation, with responsibilities and powers appropriate to the
nature of the several committees and as provided by the board of
directors in the resolution of appointment or in subsequent
resolutions and directives. The membersof each committee so
constituted and appointed by the board shall serve at the
pleasure of the board of Directors.<PAGE>
<PAGE> 13
In addition to such obligations and functions as may
be expressly provided for by the board of directors, each
committee so constituted and appointed by the board shall from
time to time report to and advise the board on corporate affairs
within its particular area of responsibility and interest.
Article V. Officers.
Section 1. Number. The officers of the Corporation
shall be President, Secretary, and Treasurer, each of whom shall
be elected by the board of directors. Such other officers and
assistant officers, such as Vice President and Chairman of the
Board, as may be deemed necessary, may be elected or appointed by
the board of directors. Any two or more offices may be held by
the same person, except the offices of president and secretary.
Section 2. Election and Term of Office. The officers
of the Corporation to be elected by the board of directors shall
be elected annually by the board of directors at the first
meeting of the board of directors held after each annual meeting
of the shareholders. If the election of officers shall not be
held at such meeting, such election shall be held as soon
thereafter as conveniently may be. Each officer shall hold
office until his successor shall have been duly elected and shall
have qualified or until his death or until he shall resign or
shall have been removed in the manner hereinafter provided.
Section 3. Removal. Any officer or agent elected or
appointed by the board of directors may be removed by the board
of directors whenever in its judgment the best interests of the
Corporation would be served thereby. Election or appointment of<PAGE>
<PAGE> 14
an officer or agent shall not of itself create contract rights.
Section 4. Vacancies. A vacancy in any office
because of death, resignation, removal, disqualification or
otherwise, may be filled by the board of directors for the
unexpired portion of the term.
Section 5. Chairman of the Board. The chairman of
the board shall preside at all meetings of the board of directors
and of the shareholders at which he shall be present. He shall
have and may exercise such powers and perform such other duties
as are, from time to time, assigned to him by the board and as
may be provided by law.
Section 6. President. The president shall be the
principal executive officer of the Corporation and, subject to
the control of the board of directors, shall in general supervise
and control all of the business and affairs of the Corporation.
He may sign, individually, or with the secretary or any other
proper officer of the Corporation thereunto authorized by the
board of directors, certificates for shares of the Corporation,
any deeds, mortgages, bonds, contracts, or other instruments for
the Corporation, except in cases where the signing and execution
thereof shall be expressly delegated by the board of directors or
by these by-laws to some other officer or agent of the
Corporation, or shall be required by law to be otherwise signed
or executed; and in general shall perform all duties incident to
the office of president and such other duties as may be
prescribed by the board of directors from time to time.
Section 7. The Secretary. The secretary shall:<PAGE>
<PAGE> 15
(a) keep the minutes of the shareholders' and of the board of
directors' meetings in one or more books provided for that
purpose; (b) see that all notices are duly given in accordance
with the provisions of these by-laws or as required by law;
(c) be custodian of the corporate records and of the seal of the
Corporation and see that the seal of the Corporation is affixed
to all documents, the execution of which on behalf of the
Corporation under its seal, is duly authorized; (d) keep a
register of the post office address of each shareholder which
shall be furnished to the secretary by such shareholder; (e) sign
with the president, or a vice president, certificates for shares
of the Corporation, the issuance of which shall have been
authorized by resolution of the board of directors; (f) have
general charge of the stock transfer books of the Corporation;
and (g) in general perform all duties incident to the office of
secretary and such other duties as from time to time may be
assigned to him by the president or by the board of directors.
Section 8. The Treasurer. The treasurer shall
(a) have charge and custody of and be responsible for all funds
and securities of the Corporation; (b) receive and give receipts
and monies due and payable to the Corporation from any source
whatsoever, and deposit all such monies in the name of the
Corporation in such banks, trust companies or other depositories
as shall be selected in accordance with the provisions of Article
VI of these by-laws; and (c) in general perform all of the duties
incident to the office of treasurer and such other duties as from
time to time may be assigned to him by the president or by the
board of directors. If the board of directors do not appoint an
individual Treasurer, either the President or the Secretary<PAGE>
<PAGE> 16
shall, at the board of directors discretion, perform the duties
of Treasurer.
Section 9. The Vice President. If a vice president
shall be elected by the board of directors, the vice president
shall, in the absence of the president or in the event of the
president's death, inability or refusal to act, perform the
duties of the president, and when so acting, shall have all the
powers of and be subject to all the restrictions upon the
president. The vice president may sign, with the secretary,
certificates for shares of the Corporation; and shall perform
such other duties as from time to time may be assigned to him by
the president or by the board of directors.
Section 10. Assistant Officers. The board of
directors shall have the power, in its discretion, to appoint any
qualified person to act as assistant to any officer of the
Corporation. Such assistant shall perform such duties as the
board shall prescribe, including the performance of the duties of
the principal officer when the incumbent is unable to act or it
is impractical for him to act personally, subject to any
restrictions on such authority as may be imposed by the board.
The acts of such assistant officer, within the scope of his
authority as delineated by the board, shall be the acts of the
Corporation to the same extent as if done by the principal
officer.
Section 11. Salaries. The salaries of the officers
shall be fixed from time to time by the board of directors and no
officer shall be prevented from receiving such salary by reason
of the fact that he is also a director of the Corporation.<PAGE>
<PAGE> 17
Article VI. Contracts, Loans, Checks and Deposits.
Section 1. Contracts. The board of directors may
authorize any officer or officers, agent or agents, to enter into
any contract or execute and deliver any instrument in the name of
and on behalf of the Corporation, and such authority may be
general or confined to specific instances.
Section 2. Loans. Loans shall be contracted on
behalf of the Corporation and evidences of indebtedness shall be
issued in its name in such manner as shall from time to time be
determined by resolution of the board of directors. Such
authority may be general or confined to specific instances.
Section 3. Checks, Drafts, etc. All checks, drafts
or other orders for the payment of money, notes or other
evidences of indebtedness issued in the name of the Corporation,
shall be signed by such officer or officers, agent or agents of
the Corporation and in such manner as shall from time to time be
determined by resolution of the board of directors.
Section 4. Deposits. All funds of the Corporation
not otherwise employed shall be deposited from time to time to
the credit of the Corporation in such banks, trust companies or
other depositories as the board of directors may select.
Article VII. Certificates for Shares and their Transfer.
Section 1. Certificates for Shares. Certificates
representing shares of the Corporation shall be in such form as
shall be determined by the board of directors. Such certificates
shall be signed by the president or a vice president and by the
secretary. All certificates for shares shall be consecutively<PAGE>
<PAGE> 18
numbered or otherwise identified. The name and address of the
person to whom the shares represented thereby are issued, with
the number of shares and date of issue, shall be entered on the
stock transfer books of the Corporation. All certificates
surrendered to the Corporation for transfer shall be cancelled
and no new certificate shall be issued until the former
certificate for a like number of shares shall have been
surrendered and cancelled, except that in case of a lost,
destroyed or mutilated certificate, a new one may be issued
therefor upon such terms and indemnity to the Corporation as the
board of directors may prescribe.
Section 2. Transfer of Shares. Transfer of shares of
the Corporation shall be made only on the stock transfer books of
the Corporation by the holder of record thereof or by his legal
representative, who shall furnish proper evidence of authority to
transfer, or by his attorney thereunto authorized by power of
attorney duly executed and filed with the secretary of the
Corporation, and on surrender for cancellation of the certificate
for such shares. The person in whose name shares stand on the
books of the Corporation shall be deemed by the Corporation to be
the owner thereof for all purposes.
Article VIII. Indemnity.
Each director and officer, or former director or
officer of this Corporation, shall be indemnified against
expenses actually and necessarily incurred by him in connection
with the defense of any action, suit or proceeding, civil or
criminal, in which he is made a party by reason of being or
having been such director or officer, except in relation to<PAGE>
<PAGE> 19
matters in which he shall be adjudged, in such action, suit or
proceeding, to be liable for willful misconduct in the
performance of duty to the Corporation. A conviction or judgment
(whether based on a plea of guilty or its equivalent or after
trial) in a criminal or civil proceeding shall not be deemed an
adjudication of liability for willful misconduct in the
performance of duty to the Corporation if such director or
officer acted in good faith in what he considered to be the best
interest of the Corporation and with no reasonable cause to
believe that the action was illegal. If in the judgment of the
board of directors a settlement of any claim so arising is deemed
in the best interests of the Corporation, any such director or
officer shall be reimbursed for any amounts paid in effecting
such settlement and reasonable expenses thereby incurred.
To the extent available, the Corporation shall maintain
directors and officers insurance coverage on each present and
former director and officer of the Corporation for all acts and
ommissions which are insurable.
Article IX. Dividends.
The board of directors may from time to time declare,
and the Corporation may pay, dividends on its outstanding shares
in the manner and upon the terms and conditions provided by law
and its articles of incorporation.
Article X. Seal.
The board of directors shall provide a corporate seal
which shall be circular in form and shall have inscribed thereon
the name of the Corporation, the state and year of incorporation,<PAGE>
<PAGE> 20
and the words "Corporate Seal", but the board may adopt a
different seal from time to time.
Article XI. Waiver of Notice.
Whenever any notice is required to be given to any
shareholder or director of the Corporation under the provisions
of these bylaws or under the provisions of the articles of
incorporation or under the provisions of law, a waiver thereof in
writing, signed by the person or persons entitled to such notice,
whether before or after the time stated therein, shall be deemed
equivalent to the giving of such notice.
Article XII. Amendments.
These Bylaws may be altered, amended or repealed and
new Bylaws may be adopted by the board of directors at any
regular or special meeting of the board of directors, but any
Bylaws or amendments to Bylaws made by the directors may be
amended, altered or repealed by the board of directors or by a
majority of the stockholders.
<PAGE>
EXHIBIT
NUMBER DESCRIPTION
21.1 Subsidiaries of the Company.<PAGE>
<PAGE> 1
ALLEGHENY & WESTERN ENERGY CORPORATION
SUBSIDIARIES
1. Mountaineer Gas Company, a West Virginia corporation,
formerly Columbia Gas Company of West Virginia.
2. Petro Services, Inc., a West Virginia corporation.
3. Gas Access Systems, Inc., a West Virginia corporation.
4. TEX-HEX, Corp., a Texas corporation.
5. A&W Exploration New Zealand Limited, a New Zealand
Corporation.
6. Mountaineer Gas Services, Inc., a West Virginia corporation,
a wholly-owned subsidiary of Mountaineer Gas Company.<PAGE>
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> JUN-30-1994
<PERIOD-END> JUN-30-1994
<CASH> 5,611
<SECURITIES> 3,142
<RECEIVABLES> 24,968
<ALLOWANCES> 1,429
<INVENTORY> 16,468
<CURRENT-ASSETS> 53,120
<PP&E> 213,522
<DEPRECIATION> 65,765
<TOTAL-ASSETS> 216,609
<CURRENT-LIABILITIES> 64,100
<BONDS> 0
<COMMON> 81
0
0
<OTHER-SE> 106,861
<TOTAL-LIABILITY-AND-EQUITY> 216,609
<SALES> 202,286
<TOTAL-REVENUES> 204,476
<CGS> 128,879
<TOTAL-COSTS> 128,879
<OTHER-EXPENSES> 60,894
<LOSS-PROVISION> 1,105
<INTEREST-EXPENSE> 4,290
<INCOME-PRETAX> 9,308
<INCOME-TAX> 1,868
<INCOME-CONTINUING> 7,440
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 1,562
<NET-INCOME> 9,002
<EPS-PRIMARY> 1.17
<EPS-DILUTED> 1.17
</TABLE>
