UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
AMENDMENT NO. 1
(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.
None
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 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:
Twelve Months Ended June 30,
(dollars in thousands)
1994 1993 1992
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 $154,021
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 Rate (per Mcf) $.32 $ .36 $ .25
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 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
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.
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 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 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.
Development Wells Drilled
Total Productive Oil Productive Gas Dry
Gross Net Gross Net Gross Net Gross Net
Fiscal Year
ended
June 30, 1992 4 0.34 --- --- 4 0.34 --- ---
Fiscal Year
ended
June 30, 1993 --- --- --- --- --- --- --- ---
Fiscal Year
ended
June 30, 1994 --- --- --- --- --- --- --- ---
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
$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:
Undeveloped Developed
Gross Net Gross Net
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
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
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):
Fiscal Year Ended June 30,
1994 1993 1992
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
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 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 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
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
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.
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 indicated:
Net Proved Developed Oil and Gas Reserves (1)
Oil (Bbls) Gas (Mcf)
Allegheny Allegheny MGS
Balance, June 30, 1991 (2) 136,000 19,432,000 ---
Revisions of previous estimates (15,000) (3,350,000) ---
Extensions, discoveries and other addition --- 159,000 ---
Production (62,000) (1,489,000) ---
Sales of reserves in place (17,000) (11,000) ---
Balance, June 30, 1992 (2) 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 (2) 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
(1)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.
(2)Independent petroleum engineers providing the estimates for
these years are
indicated in the Company's Annual Report on Form 10-K for such
years.
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 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
National Association of
Securities Dealers, Inc. Automated Quotation ("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:
High Low
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
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 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.)
Item 6. Selected Financial Data (1)
Allegheny & Western Energy Corporation and Subsidiaries
Fiscal Year Ended June 30,
INCOME STATEMENT DATA 1994 1993 1992 1991 1990
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 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
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
(1) 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.
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 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
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%
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.
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.
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
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:
June 30, June 30, June 30,
1994 1993 1992
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
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 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
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
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, 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 199327
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 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.
ALLEGHENY & WESTERN ENERGY CORPORATION
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
June 30, June 30,
ASSETS 1994 1993
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
The accompanying notes are an integral part of these consolidated
balance sheets.
ALLEGHENY & WESTERN ENERGY CORPORATION
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
June 30, June 30,
LIABILITIES AND STOCKHOLDERS' EQUITY 1994 1993
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
The accompanying notes are an integral part of these consolidated
balance sheets.
ALLEGHENY & WESTERN ENERGY CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
Year Ended Year Ended Year Ended
June 30, June 30, June 30,
1994 1993 1992
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
outstanding 7,673,268 8,013,970 8,083,188
The accompanying notes are an integral part of these consolidated
financial statements.
ALLEGHENY & WESTERN ENERGY CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
Common Stock
Additional
Number Paid-in Retained Treasury
of Shares Amount Capital Earnings Stock
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)
The accompanying notes are an integral part of these consolidated
financial statements.
ALLEGHENY & WESTERN ENERGY CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended Year Ended Year Ended
June 30, June 30, June 30,
1994 1993 1992
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 5,185,5132 6,326,984
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)
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
The accompanying notes are an integral part of these consolidated
financial statements.
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 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.
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
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
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:
Fiscal
Year
Maturity
Dates 1994 1993
Term Credit Agreement (a) 1995-1996 $4,375,000 $5,875,000
Revolving Credit Note (b) 1996 --- ---
Pension fund notes (c) 1998-2007 15,000,000 15,000,000
Notes payable to insurance
companies (d) 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
(a) 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.
(b) 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
financial covenants.
(c) 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.
(d) 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.
The combined scheduled annual maturities of long-term debt are as
follows:
Notes
Pension Payable to
Fiscal Term Credit Fund Notes Insurance
Year Agreement (a) (c) Companies (d) Total
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
(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 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:
Deferred Deferred
income taxes - income taxes -
noncurrent current
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
Components of taxes on income are as follows:
Fiscal Year Ended June 30,
1994 1993 1992
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
A reconciliation of the Federal statutory rate to taxes on income is as follows:
Fiscal Year Ended June 30,
1994 1993 1992
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%
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 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:
(Dollars in Thousands)
1994 1993
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)
Net pension cost for fiscal years ended June 30, 1994, 1993 and 1992 included the
following components:
(Dollars in Thousands)
1994 1993 1992
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
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 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:
June 30, July 1,
1994 1993
(Dollars in thousands)
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 $---
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):
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
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 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:
Fiscal Year Ending
June 30, Amount
1995 $723,000
1996 415,000
1997 369,000
1998 368,000
1999 360,000
Thereafter 647,000
$2,882,000
(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:
Average
Number Exercise
of Price
Shares Per Share
Outstanding at June 30, 1991 1,150,300 $ 8.17
Granted ---
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
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:
Fiscal Year Ended June 30,
1994 1993 1992
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
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, 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:
Fiscal Year Ended June 30,
1994 1993
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
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:
Fiscal Year Ended June 30,
1994 1993 1992
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
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
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:
Oil (Bbls) Gas (Mcf)
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
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.
(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.
Fiscal Year Ended June 30,
1994 1993 1992
(Dollars in Thousands)
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
The following table summarizes the principal sources of changes
in the standardized
measure of discounted future net cash flows:
Fiscal Year Ended June 30,
1994 1993 1992
(Dollars in Thousands)
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)
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:
1994 1993
Carrying Fair Carrying Fair
Amount Value Amount Value
(Dollars in Thousands)
Assets:
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
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 amountsapproximate 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 currentincremental 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:
Fiscal Quarter First Second Third Fourth
(Dollars in thousands except per share amounts)
1994
Revenues $22,806 $69,609 $97,070 $14,991
Income (loss) before income taxes and
cumulative effect of 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)
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 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 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 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 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
Item 10. Directors and Executive Officers of the Registrant
Name and Principal Director
Occupation or Employment Age Since
John G. McMillian 68 1987
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.
Michael S. Berman 55 1981
Mr. Berman has been President of The Duberstein Group, Inc.,
which provides government relations, planning and counseling
services, since August 1989. From 1981 to August 1989, Mr.
Berman, an attorney, was a partner in the law firm of Kirkpatrick
& Lockhart, Washington, D.C.
Sidney S. Lindley 66 1990
From 1981 to 1986, Mr. Lindley served as the President and a
director of Energy Ventures, Inc. a public company engaged in
the exploration and production of oil and gas. From 1986 to
1988, he managed private investing activities. From 1988 to
1990, Mr. Lindley was associated with a private investment
banking firm, Strevig & Associates. From December 1990 to
March 1992, Mr. Lindley served as President of TEX-HEX Corp.,
a wholly-owned subsidiary of the Company. Prior to 1981, he
was Chairman of the Board of Champion Chemicals, Inc. He
currently serves as a director of A&W Exploration New Zealand,
Limited, a wholly-owned subsidiary of the Company and is
engaged as a consultant to the Company. Mr. Lindley is a
member of the Compensation Committee.
Rush Moody, Jr. 64 1987
Mr. Moody is Managing Partner of the law firm of Andrews &
Kurth, L. L. P., and is located in its Washington, D.C. office. He
has practiced law privately for more than fifteen years. Mr.
Moody was formerly a Commissioner of the Federal Power
Commission, the predecessor of the Federal Energy Regulatory
Commission. Mr. Moody serves as a member of the
Company's Executive, Audit and Compensation Committees.
Henry E. Tauber 53 1993
Mr. Tauber is President and Chief Executive Officer of Marker
International and President of Marker USA and has served in
these capacities for more than the past five years. Mr. Tauber
is also the Vice President and a Council Member of the
International Ski Federation. Mr. Tauber is a member of the
Company's Audit Committee.
Jack H. Vaughn 74 1981
Mr. Vaughn is currently Chairman of the Board of ECOTRUST, a
private conservation group with projects in Alaska, Washington,
Oregon and Western Canada. From 1988 to 1992, he served
as the United States government's senior consultant in natural
resources management for Central America. Prior to that, Mr.
Vaughn had been founding Chairman of Conservation
International in Washington, D.C. Mr. Vaughn also is a director
of IMRE Corporation. Mr. Vaughn is the Chairman of the
Company's Compensation Committee.
Harold M. Wit 66 1981
Mr. Wit serves as a Managing Director and a member of the
Executive Committee of Allen & Company Incorporated, an
investment banking firm of which he has been an officer and
director for more than the past five years. Mr. Wit is also a
director of Toys "R" Us, Inc. He is the Chairman of the
Company's Audit Committee and a member of its Executive
Committee.
Information concerning the executive officers and significant
employees of the Company is
contained in Item 1 of this Report.
Pursuant to Section 16(a) of the Securities Exchange Act of 1934
and the rules issued
thereunder, the Company's directors, executive officers and
beneficial owners of more than
10% of the common stock are required to file reports of ownership
and changes in
ownership of the Company's Common Stock with the Securities and
Exchange Commission
and the NASDAQ National Market System. Copies of such reports
are required to be
furnished to the Company. Based solely upon its review of the
copies of such reports
furnished to it, the Company believes that during its fiscal year
ended June 30, 1994, except
for the late filing of one Form 4 covering one transaction by
each of Messrs. Grant, Fletcher,
Pittman and Vaughn, respectively, all Section 16(a) filing
requirements applicable to its
directors, executive officers and greater than 10% beneficial
owners of Common Stock were
met.
Item 11. Executive Compensation
EXECUTIVE COMPENSATION
The following table sets forth a summary of compensation paid or
awarded by the Company
in the last three fiscal years to the chief executive officer and
those executive officers, in all
capacities in which they served, whose total annual salary and
bonus exceeded $100,000.
SUMMARY COMPENSATION TABLE
Annual Compensation Long-Term Compensation
Awards Payouts
Restricted All Other
Other Annual Stock Options/ LTIP Compen-
Name and Principal Fiscal Salary Bonus Compensation Awards SARs Payouts sation
Position Year ($) ($) ($) ($) ($) ($) ($)
John G. McMillian, 1994 287,053 0 134,520(1) 0 0 0 0
Chairman, President and 1993 287,053 0 184,076(1) 0 0 0 0
Chief Executive 1992 277,650 0 N/A 0 0 0 N/A
Officer
Richard L. Grant, Secretary 1994 240,898 150,000 7,361(3) 0 0 0 0
of the Company and 1993 221,109 35,000 8,823(3) 0 0 0 0
President of Mountaineer Gas 1992 197,419 15,000 N/A 0 0 0 N/A
Company(2)
Michael S. Fletcher, 1994 188,202 100,000 14,854(3) 0 0 0 0
Senior Vice President, 1993 172,741 35,000 4,798(3) 0 0 0 0
Chief Financial Officer and 1992 154,233 10,000 N/A 0 0 0 0
Secretary of Mountaineer
Gas Company(2)
W. Merwyn Pittman, Vice 1994 141,932 100,000 10,783(3) 0 15,000 0 0
President, Chief Financial
Officer and Treasurer
(1) Other Annual Compensation consists of tax reimbursements and perquisites and other
benefits. Perquisites and other benefits include personal financial consulting services
($55,780 and $101,730 in fiscal 1994 and 1993, respectively).
(2) Mountaineer Gas Company is a wholly-owned subsidiary of the Company.
(3) Other Annual Compensation consists of tax reimbursements.
The following table sets forth certain information concerning
options/SARs granted during
fiscal 1994 to the named executives:
OPTIONS/SAR GRANTS IN LAST FISCAL YEAR
Number of
Securities Percent of Total
Underlying Options/SARs
Options/ Granted to Exercise or Grant Date
SARs Employees in Base Price Expiration Present
Name Granted (1) Fiscal 1994 Per Share Date Value (2)
W. Merwyn Pittman 15,000 100% $7.50 6/21/99 $29,170
(1) During fiscal 1994, the Board of Directors in effect extended the expiration date of
certain options granted to Messrs. McMillian, Grant and Fletcher from February 15,
1994 to February 13, 1999.
(2) Option values reflect Black-Scholes model output for options. The assumptions used
in the model were expected volatility of 5%, risk-free rate of return of 7.28%, dividend
yield of 0%, and time to exercise of five years. The model does not take into account
a significant feature of the options granted to employees under the Company's 1987
Stock Option Plan, i.e., the non-transferability of options awarded under the
Company's 1987 Stock Option Plan.
The following table summarizes options and SARs exercised during
fiscal year 1994 and
presents the value of unexercised options and SARs held by the
named executive officers
as of the end of the fiscal year:
AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR (1)
AND FISCAL YEAR-END OPTION/SAR VALUES
Number of Value of
Securities Underlying Unexercised
Unexercised In-the-Money
Options/SARs(2) at Options/SAR(2) at
June 30, 1994 June 30,1994(3)
Name Exercisable Unexercisable Exercisable Unexercisalbe
John G.
McMillian 1,000,000 --- $90,000 ---
Richard L.
Grant 27,000 --- 2,178 ---
Michael S.
Fletcher 16,000 --- 1,224 ---
W. Merwyn
Pittman 15,000 --- 11,250 ---
(1) Since no options were exercised by the above-named executive
officers in fiscal 1994,
no shares were acquired or value realized upon the exercise
of options by such officers in the last fiscal year.
(2) The Company has not issued any SARs as of June 30, 1994.
(3) Market value of underlying securities at fiscal year-end
market price of $8.25 per share minus the exercise price.
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. Replacement options may be granted in substitution
for outstanding options,
which may be at a lower price (but, in the case of incentive
stock options, at a purchase
price not less than the fair market value of the shares subject
to the replacement option at
the time of substitution and the replaced outstanding options may
be canceled). The 1987
Plan also provides that employees may be granted stock
appreciation rights ("SAR's") at the
discretion of the Board of Directors. Upon the exercise of an
SAR, payment will be made
to the grantee in an amount equal to the excess of the fair
market value of a share of
Common Stock on the date of exercise over the fair market value
of a share of Common
Stock on the date the SAR was granted. Payment may be made in
shares of Common
Stock, in cash or partly in cash and partly in shares of Common
Stock, as the Board of
Directors shall determine. When an SAR is exercised, the related
stock option is
surrendered; when a stock option is exercised, the related SAR,
if any, is surrendered. No
SARs have been granted under the 1987 Plan.
Retirement Income Plan
The Company offers virtually all employees a Retirement Income
Plan. The Retirement
Income Plan provides retirement income for employees and, if
elected, for survivors. Such
retirement income is related to final average annual compensation
during the highest
consecutive 60 months in the last 120 months of employment, years
of credited service and
age at date of retirement.
The following table reflects the estimated annual pension
benefits payable (assuming the
Retirement Income Plan will continue in its present form) upon
retirement at age 65 to
covered employees under the Retirement Income Plan based upon
various levels of
compensation and years of service.
PENSION PLAN TABLE
PENSION PLAN TABLE
Years of Credited Service
-----------------------------------------------------------------------------------------
Remuneration 15 20 25 30 35
$300,000 $31,500 $42,000 $52,500 $62,900 $66,700
250,000 31,500 42,000 52,500 62,900 66,700
200,000 31,500 42,000 52,500 62,900 66,700
175,000 31,500 42,000 52,500 62,900 66,700
150,000 31,500 42,000 52,500 62,900 66,700
125,000 25,700 34,200 42,800 51,300 54,400
100,000 19,800 26,500 33,100 39,700 42,200
The remuneration amounts listed above are within 10% of the cover
ed compensation of the
executive officers named in the Summary Compensation Table.
Benefits reflected above are
computed based upon a straight-life annuity and are subject to
Social Security deductions.
As of June 30, 1994, years of credited service under the Plan for
each named executive
officer were as follows: Mr. McMillian, seven; Mr. Grant, eight;
Mr. Fletcher, seven; Mr.
Pittman, one.
Key Executives' Supplemental Retirement Benefit Plan
The Company's Board of Directors has established a Key
Executives' Supplemental
Retirement Benefit Plan (the "SERP") to assist the Company and
its subsidiaries in attracting
and retaining 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 Messrs. Grant,
Fletcher and Pittman who would be entitled to their full
retirement benefits (see Employment
Contracts discussion below). 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.
DIRECTOR COMPENSATION
Each director receives a monthly retainer of $1,000, a $1,000 fee
for each meeting of the
Board attended and reimbursement for expenses incurred for
serving as a director. Each
committee chairman receives a monthly retainer of $100 and each
committee member
receives $500 for each committee meeting attended.
Mr. Lindley served as a consultant to the Company during fiscal
year 1994 and is performing
consulting services in fiscal year 1995. Mr. Lindley's services
include, but are not limited to,
review and consultation with management regarding potential
acquisition candidates and
assistance with the Company's investment in New Zealand. The
agreement between the
Company and Mr. Lindley is such that Mr. Lindley will provide
consulting services for a
period of three years until February 1995 in return for
compensation of $7,500 per month.
This agreement may be terminated by either party upon 60 days
notice.
EMPLOYMENT CONTRACTS
The Company has entered into two-year employment agreements,
dated September 14,
1993, with Messrs. Grant, Fletcher and Pittman pursuant to which
they will be paid annual
base salaries of $224,800, $175,616 and $135,000, respectively.
In addition, each will
receive annual increases which are based primarily upon the
percentage increases given by
the Company to other employees whose performance is judged to be
above average. The
agreements also provide for automatic renewal periods of one year
unless declined by the
Company. Among other provisions, the agreements for Messrs.
Grant and Fletcher provide
that in the event of a change in control of the Company or
Mountaineer Gas Company, they
will be entitled to receive a lump-sum amount equal to 2.95 times
the yearly average of their
respective salaries, together with any bonuses and additional
compensation paid to them
during the three preceding calendar years, and their
participation in the SERP would become
fully vested. The agreement with Mr. Pittman, the Company's Vice
President, Chief Financial
Officer and Treasurer, provides that in the event of a change in
control of the Company he
will be entitled to be paid a lump-sum amount equal to 2.95 times
the yearly average of his
salary together with any bonuses and additional compensation paid
to him during the three
preceding calendar years (or the annualized average of such
compensation if employed less
than three years), and his participation in the SERP will become
fully vested. The
agreements with Messrs. Grant and Fletcher supersede the
agreements previously in effect
with Mountaineer Gas Company.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
As noted previously under Director Compensation above, Mr.
Lindley served as a consultant
to the Company during fiscal year 1994 and is performing
consulting services in fiscal year
1995. Mr. Lindley's services include, but are not limited to,
review and consultation with
management of potential acquisition candidates and assistance
with the Company's
investment in New Zealand. The agreement between the Company and
Mr. Lindley is such
that Mr. Lindley will provide consulting services for a period of
three years expiring in
February 1995 in return for compensation of $7,500 per month.
This agreement may be
terminated by either party upon 60 days notice.
As noted previously in the Certain Transactions section, the law
firm of Andrews & Kurth,
L.L.P., of which Mr. Moody is managing partner, performed legal
services for the Company
during fiscal year 1994 and is performing legal services in
fiscal year 1995. The fees
received from the Company by Andrews & Kurth, L.L.P., during
fiscal year 1994 did not
exceed 5% of such firm's gross revenues.
Mr. McMillian serves on the Compensation Committee of Marker
International. Mr. Tauber,
a director of the Company, is President and Chief Executive
Officer of Marker International.
COMPENSATION COMMITTEE REPORT
In 1992, the U.S. Securities and Exchange Commission amended the
disclosure
requirements covering compensation of executive officers. These
requirements call for a
format that includes a report by the Compensation Committee on
the Company's policies
for making executive compensation decisions (including the
factors and criteria on which the
chief executive officer's pay is based), a series of tables
covering annual and long-term
compensation, and a performance graph comparing the Company's
five-year cumulative
total stockholder return with the cumulative return of a broad
equity market index and another
selected index.
Overview
The Compensation Committee is responsible for establishing and
reviewing the Company's
executive compensation policies and for recommending to the Board
of Directors on an
annual basis the compensation to be paid to the executive
officers of the Company. In
addition, the Compensation Committee advises the Board of
Directors on the administration
of the Company's 1987 Plan (for key employees) and administers
the SERP (for key
executive employees). The Compensation Committee consists of
Messrs. Vaughn
(Chairman), Lindley and Moody. None of the foregoing were
employees of the Company
or eligible to participate in any of the compensation programs
under the Compensation
Committee's purview.
The Company's executive compensation, stock option and
supplemental retirement
programs are designed to attract and retain high-caliber
executives and other key employees
through compensation and benefits which are competitive within
its industry and to motivate
these individuals to enhance profitability and stockholder value
by making them stockholders
in the Company. Each year, the Compensation Committee reviews
the Company's
performance and the compensation, benefits and stock ownership of
its executives and other
key employees and compares them to industry peer companies. (The
industry group index
in the Performance Graph below includes but is not limited to the
companies used for
compensation analysis). The Compensation Committee has access
to, but is not required
to seek, advice and counsel from independent third parties in the
performance of its review.
On the Compensation Committee's advice, the Company may, on a
case-by-case basis,
enter into employment agreements with individual executives.
Base Salaries
The base salaries of the Company's executive officers are
intended to be generally
competitive with the base salaries of officers holding comparable
positions at industry peer
companies. Base salaries are determined by evaluating the
responsibilities of the position
held and the experience and capability of the individual. In
addition, consideration is given
to both national and local factors in the marketplace for
executive talent. The Compensation
Committee reviews and recommends adjustments to individual
salaries annually, based on
an overall evaluation of the performance of the Company and of
each executive officer.
Annual Bonus
The Compensation Committee may recommend that the Board of
Directors award annual
cash bonuses to the Company's executive officers and key
employees, based on both the
Company's performance and each individual's contribution thereto.
Individual contributions
are determined subjectively, on a case-by-case basis. The
Compensation Committee may
also consider other factors, such as the bonus levels paid to
officers holding comparable
positions at industry peer companies and national and local
factors in the executive
marketplace.
During fiscal year 1994, discretionary bonuses were paid to
Messrs. Grant, Fletcher and
Pittman. In connection therewith, the Compensation Committee
took special notice of the
Company's recent financial performance and improved competitive
position and the fact that
the Company is engaged in several expansion projects which
provide the potential for long-
term earnings growth and increased shareholder value.
Stock Options
The Company believes that encouraging stock ownership by its
management further aligns
the interests of management and stockholders in increasing
profitability and stockholder
value. Under the Company's 1987 Plan, and upon the advice of the
Compensation
Committee, the Board of Directors periodically may grant to the
Company's key employees
non-qualified or incentive stock options, with a purchase price
no less than the price of the
Company's stock on the date of grant. In addition, key employees
may be granted SARs
under the 1987 Plan. In recommending that stock options or SARs
be granted, such
Committee typically considers factors similar to those considered
for annual bonuses.
However, stock options and SARs may be granted throughout the
year and are less
dependent on variables such as the Company's cash position than
are annual bonuses.
During fiscal 1994, the Board of Directors granted Mr. Pittman
15,000 options and also in
effect extended the expiration date of certain options previously
granted to Messrs. McMillian,
Grant and Fletcher from February 15, 1994 to February 13, 1999.
Supplemental Retirement Benefits
In December 1992, following a study of benefit plans at industry
peer group companies, the
Compensation Committee recommended and the Board of Directors
approved adoption of
the Company's SERP. The SERP provides retirement benefits to
certain executives who
remain in the Company's employ until retirement age and is
intended to be competitive with
similar plans benefitting executive officers and key employees at
such other companies. In
determining the estimated amounts of supplemental retirement
benefits awarded to
participants under the SERP, the Compensation Committee and Board
of Directors
considered the amounts awarded to individuals holding comparable
positions at industry
peer companies, the Company's performance in recent years and
each individual's
contribution thereto. In the future, the Board of Directors may,
at any time and in its sole
discretion, terminate or amend the SERP and the benefits awarded
thereunder, with respect
to any participant who has not already died, become disabled or
retired at the time of such
termination or amendment.
Chief Executive Officer's Compensation
As indicated in the Summary Compensation Table, during the fiscal
year just ended, Mr.
McMillian received a base salary of $287,053, and other annual
compensation (including tax
reimbursements and perquisites and other benefits) of $134,520.
Since 1989, by informal
arrangement between Mr. McMillian and the Company's Board of
Directors, the chief
executive officer's salary has been fixed (with certain minor
adjustments). During this period,
it has not been the Company's practice to award an annual
performance bonus to its chief
executive officer.
SUBMITTED BY THE COMPENSATION COMMITTEE:
Jack Vaughn, Chairman
Sidney S. Lindley
Rush Moody, Jr.
PERFORMANCE GRAPH
The following graph compares the cumulative total stockholder
return on the Company's
Common Stock with the cumulative total return of the stocks
included in the NASDAQ Stock
Market Index and a peer group index (including Arkla, Inc., Bow
Valley Energy, Inc., The
Columbia Gas System, Inc., Consolidated Natural Gas Co.,
Equitable Resources Inc., Maxus
Energy Corporation, Pacific Enterprises, Presidio Oil Company,
Wainoco Oil Corporation and
Washington Energy Co.) over the five-year period ending June 30,
1994. The peer group
index was weighted according to the companies' market
capitalization. The graph assumes
that $100 was invested in the Company's Common Stock and in the
stock of the companies
in the NASDAQ Stock Market Index and the peer group index,
respectively, at June 30, 1989
and that all dividends were reinvested in the quarter received.
Item 12. Security Ownership of Certain Beneficial Owners and
Management
Amount and Nature
Name of of Beneficial
Beneficial Owner Ownership (1) Percent of Class
(2)
The Guardian Life Insurance
Company of America (3)
201 Park Avenue South
New York, New York 10003 806,900 10.8%
Allen & Company Incorporated (4)
711 Fifth Avenue
New York, New York 10022 728,024 9.7%
FMR Corp. (5)
82 Devonshire Street
Boston, Massachusetts 02109 598,900 8.0%
Ingalls & Snyder (6)
61 Broadway
New York, New York 10006 534,430 7.1%
John G. McMillian (7)
Allegheny & Western Energy Corporation
300 Capitol Street, Suite 1600
Charleston, West Virginia 25301 1,026,000 12.1%
Michael S. Berman 3,000 (8)
Michael S. Fletcher (9) 17,800 (8)
Richard L. Grant (10) 27,600 (8)
Sidney S. Lindley 10,000 (8)
Rush Moody, Jr. 200 (8)
W. Merwyn Pittman (11) 16,000 (8)
Henry E. Tauber (12) 2,000 (8)
Jack H. Vaughn (13) 4,650 (8)
Harold M. Wit (14) 102,111 1.4%
All officers and directors
as a group (11 persons) (15) 1,219,361 14.3%
(1) Each director and officer disclaims beneficial ownership of
securities of the Company
owned by any company of which such person is a director or
officer.
(2) Based on 7,479,360 shares outstanding as of September 1,
1994.
(3) According to Schedule 13G filed on February 13, 1991, with
the Securities and
Exchange Commission (the "Commission"), this includes
260,500 shares owned by
the Guardian Life Insurance Company of America and 546,400
shares owned by its
affiliates. According to the Schedule 13G, the Guardian
Life Insurance Company of
America and its affiliates have shared power to dispose of
and to vote 546,400
shares.
(4) According to Schedule 13D filed with the Commission on March
29, 1991, as
amended on October 17, 1991, this does not include 20,000
shares then owned by
American Diversified Enterprises, Inc., or 621,414 shares
owned by members of the
Allen family, of whom certain members are directors,
officers and shareholders of
Allen & Company Incorporated, its parent and American
Diversified Enterprises, Inc.
It also does not include 139,577 shares owned by other
officers and directors of Allen
& Company Incorporated.
(5) According to Schedule 13G filed with the Commission on
February 14, 1994, FMR
has sole power to dispose of 598,900 shares.
(6) According to Schedule 13G filed with the Commission on
February 7, 1994, Ingalls
& Snyder has sole power to dispose of 534,430 shares and
sole power to vote 4,500
shares.
(7) Includes options to purchase 1,000,000 shares of common
stock.
(8) Less than one percent (1%).
(9) Includes options to purchase 16,800 shares of common stock.
(10) Includes options to purchase 27,100 shares of common stock.
(11) Includes options to purchase 15,000 shares of common stock.
(12) Includes 2,000 shares owned as custodian for a minor child,
as to which Mr. Tauber
disclaims beneficial ownership.
(13) Includes 500 shares owned by Mr. Vaughn directly, 1,550
shares owned jointly with
his wife, 700 shares owned by his wife directly and 1,900
shares owned by his
children. Mr. Vaughn disclaims beneficial ownership of the
shares held by his wife
directly and his children.
(14) Includes 100,961 shares owned by Mr. Wit and 1,150 shares
owned by his wife, as
to which Mr. Wit disclaims beneficial ownership. Does not
include 728,024 shares
held by Allen & Company Incorporated, of which Mr. Wit is a
managing director.
(15) Includes options to purchase 1,068,900 shares of common
stock.
Item 13. Certain Relationships and Related Transactions
CERTAIN TRANSACTIONS
In accordance with the Company's employee relocation policies,
the Company made
noninterest-bearing bridge loans totalling $65,000 to Mr. Pittman
to facilitate his relocation
to Charleston, West Virginia, in connection with his acceptance
of the positions of Vice
President, Chief Financial Officer and Treasurer of the Company.
The loan was repaid in full
on September 21, 1993. Additionally, the Company purchased Mr.
Pittman's former
residence at its appraised fair market value during fiscal 1994
in connection with his
acceptance of employment with the Company.
The law firm of Andrews & Kurth, L.L.P., of which Mr. Moody is
managing partner, performed
legal services for the Company during fiscal year 1994 and is
performing legal services in
fiscal year 1995. The fees received from the Company by Andrews
& Kurth, L.L.P., during
fiscal year 1994 did not exceed 5% of such firm's gross revenues.
Allen & Company Incorporated provided financial advisory services
and, in connection with
the Company's stock repurchase program, brokerage services to the
Company during fiscal
year 1994 and is performing such services in fiscal year 1995.
Mr. Wit is a Managing
Director and a member of the Executive Committee of Allen &
Company Incorporated. The
fees received from the Company by Allen & Company Incorporated
during fiscal year 1994
did not exceed 5% of such firm's gross revenues.
CERTAIN BUSINESS RELATIONSHIPS
Mr. Lindley served as a consultant to the Company during fiscal
year 1994 and is performing
consulting services in fiscal year 1995. Mr. Lindley's services
include, but are not limited to,
review and consultation with management regarding potential
acquisition candidates and
assistance with the Company's investment in New Zealand. The
agreement between the
Company and Mr. Lindley is such that Mr. Lindley will provide
consulting services for a
period of three years until February 1995 in return for
compensation of $7,500 per month.
This agreement may be terminated by either party upon 60 days
notice.
Mr. McMillian serves on the Compensation Committee of Marker
International. Mr. Tauber,
a director of the Company, is President and Chief Executive
Officer of Marker International.
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
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
ALLEGHENY & WESTERN ENERGY CORPORATION
AND SUBSIDIARIES
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT
Column A Column B Column C Column D Column E Column F
Balance at Other Changes Balance at
Beginning Additions Add (Deduct) End of
Description of Period at Cost Retirements Describe Period
Year ended
June 30, 1994:
Utility plant $137,737,323 $12,831,730 $2,819,353 $1,496,169 (a) $ 149,245,869
Oil and gas properties 43,538,030 6,000 4,333,017 (98,585)(b) 39,112,428
Gas gathering systems 13,116,959 --- 456,094 --- 12,660,865
Transmission plant 4,736,819 66,144 --- 167,252 (b) 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 (c) $ 137,737,323
Oil and gas properties 38,598,014 3,991,137 451,588 1,400,467 (d) 43,538,030
Gas gathering systems 13,116,959 --- --- --- 13,116,959
Transmission plant --- 3,236,819 --- 1,500,000 (e) 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 (a) $ 122,879,794
Oil and gas properties 43,263,578 496,710 37,545 (5,124,729)(f ) 38,598,014
Gas gathering systems 13,116,959 --- --- --- 13,116,959
Other 8,047,302 267,500 596,337 (53,000) (g) 7,665,465
$178,367,460 $9,533,924 $1,959,592 $(3,681,560) $ 182,260,232
(a) Negative goodwill amortization.
(b) Includes reclassification relating to purchase price
allocation and other miscellaneous items.
(c) Includes $1,496,169 of negative goodwill amortization and
$482 of miscellaneous adjustments.
(d) Includes $1,500,000 of purchase price allocation related to
gas contract reserves and $(99,533) of miscellaneous adjustments.
(e) Purchase price allocation related to gas contract reserves.
(f ) Includes ($5,061,505) related to the sale of TEX-HEX
properties and $(63,224) of miscellaneous adjustments.
(g) Write-down of certain office equipment to net realizable
value.
ALLEGHENY & WESTERN ENERGY CORPORATION
AND SUBSIDIARIES
SCHEDULE VI - ACCUMULATED DEPLETION, DEPRECIATION, AND
AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT
Column A Column B Column C Column D Column E Column F
Additions
Balance at Charged to Other Changes Balance at
Beginning Cost and Add (Deduct) End of
Description of Period Expenses Retirements Describe Period
Year ended June 30, 1994:
Utility plant $37,429,316 $7,335,388 $2,819,352 $(222,954)(a) $ 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)(b) $ 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)(c) $ 32,370,857
Oil and gas properties 18,389,849 2,978,035 --- (4,504,167)(d) 16,863,717
Gas gathering 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
(a) Consists of ($308,720) of cost of removal and $85,766 of net salvage value.
(b) Consists of ($230,573) of cost of removal and $75,043 of net salvage.
(c) Consists of ($239,970) of cost of removal and $105,023 of net salvage.
(d) This amount represents the reduction in accumulated depletion, depreciation and
amortization related to the sale of TEX-HEX properties.
ALLEGHENY & WESTERN ENERGY CORPORATION
AND SUBSIDIARIES
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS
Additions
Balance at Charged to Deductions Balance at
Beginning Results of from End of
Description of Period Operations Other Reserves Period
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 (a) $ 1,334,141 (b) $1,429,308
June 30, 1993 1,660,500 836,000 249,471 (a) 1,438,767 (b) 1,307,204
June 30, 1992 1,488,423 1,183,773 262,119 (a) 1,273,815 (b) 1,660,500
(a)Collection of accounts previously written off.
(b)Uncollectible accounts written off.
ALLEGHENY & WESTERN ENERGY CORPORATION
AND SUBSIDIARIES
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
Year Ended Year Ended Year Ended
June 30, 1994 June 30, 1993 June 30, 1992
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
All other required captions are less than one percent of sales.
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:October 28, 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
Financial
of Directors, President and Officer and Treasurer
Chief Executive Officer
/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