SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
______________________________________________________________________________
(Mark One)
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 (FEE REQUIRED)
For the fiscal year ended December 31, 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 1-4566
THE MONTANA POWER COMPANY
(Exact name of registrant as specified in its charter)
Montana 81-0170530
(State or other jurisdiction (IRS Employer
of incorporation or organization) Identification No.)
40 East Broadway, Butte, Montana 59701-9989
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code (406) 723-5421
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each Class on which registered
Common Stock New York Stock Exchange
Pacific Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Preferred Stock
(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 check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K (Section 229.405 of this chapter) 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.
Yes X No
<PAGE>
The aggregate market value of the voting stock held by nonaffiliates of the
registrant was $1,305,588,284 at March 17, 1995.
On March 17, 1995, the Company had 53,819,717 shares of common stock
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
(1) Notice of 1995 Annual Meeting of Shareholders and Proxy Statement,
pages 1-18, is incorporated into Part III of this report.
<PAGE>
PART I
ITEM 1. BUSINESS
GENERAL - INDUSTRY SEGMENTS: The Montana Power Company (the Company)
and its subsidiaries conduct a number of diversified, but related businesses.
The Company's principal business, which is conducted through its Utility
Division, includes regulated utility operations involving the generation,
purchase, transmission and distribution of electricity and the production,
purchase, transportation and distribution of natural gas. The Company,
through its wholly-owned subsidiary, Entech, Inc. (Entech), engages in
nonutility operations principally involving the mining and sale of coal and
exploration for, and the development, production, processing and sale of oil
and natural gas and the sale of telecommunication equipment and services. The
Company, through its Independent Power Group (IPG) manages long-term power
sales, and develops and invests in nonutility power projects and other energy-
related businesses. See Item 8, Note 10 to the Consolidated Financial
Statements for further information. A group of officers and employees of the
Company constitute the Office of the Corporation. The Office of the
Corporation provides strategic direction and policy, approves the allocation
of capital and provides financial, legal and other services to all of the
operating units. The Company was incorporated in 1961 under the laws of the
State of Montana, where its principal business is conducted, as the successor
to a New Jersey corporation incorporated in 1912.
UTILITY DIVISION:
SERVICE AREA AND SALES: The Utility Division's service territory
comprises 107,600 square miles or approximately 73% of Montana. Within its
service territory, 86% of the state's population resides. The Division serves
approximately 593,000 residents, or 81% of the population within the service
territory. Additionally, energy is provided to cooperatives that serve
approximately 72,000 residents. Dominant factors in Montana's diversified
economy are agriculture and livestock, which constitute Montana's largest
industry, tourism and recreation, coal and metals mining, oil and gas
production, and the forest products industry which embraces the production of
pulp and paper, plywood and lumber.
Electric service is provided to 191 communities, the rural areas
surrounding them and Yellowstone National Park, and natural gas service is
provided to 109 communities. Firm electric power is sold at wholesale to two
rural electric cooperatives. Natural gas is sold at wholesale or transported
to distribution companies in Great Falls, Cut Bank, Shelby, Kevin, Sweetgrass
and Sunburst, Montana.
Weather is a factor which can significantly affect electric and natural
gas revenues. The Company's sales generally increase as a result of colder
weather with customer demand peaking during the winter months.
COMPETITIVE ENVIRONMENT: The electric and natural gas industries are
currently in a transition to a more competitive market environment. Federal
legislation, including the National Energy Policy Act, is intended to promote
competition and reduce the level of regulation in the energy supply industry.
The Utility Division's electric and natural gas businesses currently are
substantially free from direct competition with other suppliers for
residential and commercial customers. The Utility Division is subject to, in
certain circumstances, increased competition for large industrial loads and
with other energy suppliers for large wholesale loads. Because of the absence
of competing transmission pipelines in its natural gas service territory, the
Utility Division is less subject to bypass by its large industrial and
wholesale natural gas customers.
In February 1995, the Company became a charter member of the Western
Regional Transmission Association (WRTA). WRTA is a Regional Transmission
Group (RTG), certified by the Federal Energy Regulatory Commission (FERC),
formed by its members "to foster the efficient, equitable and reliable use of
existing and future transmission facilities and the expeditious and fair
resolution of disputes related to transmission access." The Company has also
been involved in the formation of another RTG, the Northwest Regional
Transmission Association (NRTA). The Company expects that NRTA will be
certified by FERC in 1995 and that it will become a member.
REGULATION AND RATES: The Company's public utility business in Montana
is subject to the jurisdiction of the Public Service Commission of
Montana (PSC). The PSC has jurisdiction over the issuance of securities by
the Company. FERC also has jurisdiction over the Company, under the Federal
Power Act, as a licensee of hydroelectric projects and as a public utility
engaged in interstate commerce. The importation of natural gas from Canada
requires approval by the Alberta Energy Resources Conservation Board, the
National Energy Board of Canada and the United States Department of Energy.
The PSC issued an order approving electric and natural gas rate
increases for the Company totaling $13,500,000 annually effective April 28,
1994. This order allowed the Company a $7,800,000 annual electric rate
increase, down from the interim increase of $8,800,000 and an annual natural
gas rate increase of $5,700,000, up from the interim increase of $4,000,000.
In its updated application, the Company had requested general rate increases
of $37,600,000 annually for electricity and natural gas based upon a 12.25%
return on common equity.
The order reduced the Company's authorized return on common equity from
12.1% to 11.0% for both the electric and natural gas utilities. Of the
$24,100,000 difference between the requested amount and allowed increases,
$11,100,000 is attributable to the lower return on common equity. Another
$7,000,000 of the difference is attributable to the disallowance of certain
fuel expense on coal sales from the Company's subsidiary, Western Energy
Company, to the Utility Division. The remaining differences relate primarily
to the denial of the Company's request to begin recovery of previously flowed
through tax timing differences and does not affect net income.
On June 17, 1994, the Company filed a complaint requesting the District
Court, Butte-Silver Bow County, to set aside that portion of the PSC's
decision disallowing the portion of the fuel expense and remand the coal cost
issue to the PSC for a redetermination. On December 29, 1994, the District
Court ruled that the PSC is entitled to choose the method by which coal costs
are determined for inclusion in rates. Legislation was introduced into the
1995 session of the Montana Legislature to require the PSC to use a market
price approach for determining the amount of coal costs to be included in
rates. On March 17, 1995, the bill was signed into law by the Governor.
In August 1993, the Company filed an allocated cost of service and rate
design docket with the PSC requesting that the portion of total electric
revenues collected from various customer classifications be changed to more
appropriately reflect the cost of providing service to these customers. The
filing proposed an 8.16% reduction in average industrial rates, which would be
offset by increased revenues collected from other customer classifications.
In its final order dated June 17, 1994, the PSC refrained from deciding
several contested issues central to the allocation of costs to customer
classes. Instead, the PSC strongly encouraged the parties to come together in
a collaborative effort to settle, or at least narrow, their differences. That
collaborative effort is in progress, and is expected to be completed in time
for the results to be used in a new allocated cost of service and rate design
filing expected in the fourth quarter of 1995. In the interim, rate designs
remain largely unchanged.
On August 22, 1994, the Company filed with the PSC, and has since
updated, a request for an increase in annual electric revenues of $24,700,000
representing a 7.4% increase. The request is based upon a 12.75% return on
common equity and continues to seek a market price approach for determining
the amount of coal costs allowed to be collected in rates. A 1% change in the
return allowed on common equity would result in a change of approximately
$7,000,000 in annual electric revenues. The Company's interim rate increase
request of $16,700,000 was considered by the PSC in November and an interim
rate increase of $7,700,000 was granted effective November 28. The interim
increase was based on an 11% return on common equity and included a $5,700,000
coal cost disallowance. A proposed settlement between the Company and the
Montana Consumer Counsel, which would provide a $13,800,000 annual increase
was reached on March 8, 1995. The settlement is now under consideration by
the PSC. Final orders are anticipated no later than May 1995.
Natural gas rates changed on December 13, 1994, reflecting a net
increase of $4,000,000 in annual revenues. This net increase reflected:
1) The Company's annual deferred gas cost accounting filing. The Company, on
an annual basis, is allowed to submit its actual natural gas supply costs and
related revenues as a basis for rate adjustments: and 2) The Gas
Transportation Adjustment Clause (GTAC) net balance. The GTAC mechanism
tracks the difference between estimated interruptible transportation (IT)
revenues and the actual IT revenues received. The bulk of the
$4,000,000 increase was created by the completion of the deferred gas cost
balance and GTAC net balance amortizations from the 12-month tracking period
ending in August, 1993, as approved in last year's gas tracking filing in
November, 1993, for amortization in the subsequent 12 months. This rate
change did not affect the Company's overall net income.
Central Montana Electric Power Cooperative, Inc. (Central) manages the
contract for purchases of power from the Utility Division by a group of
Montana coops. During 1994, Central purchased 4% of the total energy sold by
the Utility Division. On an annual basis the Company prepares and analyzes
the cost of service associated with providing this wholesale service to
Central. During 1994, the Company prepared a cost of service based on 1993
FERC Form 1 actual data, modified for known and measurable changes. Following
presentation of the 1993 data, the Company and Central Montana negotiated a
zero rate adjustment for the 1994 rate period and agreed to continue the
annual rate review/adjustment process.
ELECTRIC UTILITY OPERATIONS: The maximum demand on the resources in
1994 was 1,468,000 kW on February 7, 1994. Total firm capability of the
Utility's electric system for 1994 was 1,601,000 kW. Of this capability,
1,186,000 kW was provided by the Utility's generating facilities, and
415,000 kW was provided by firm Electric Utility power purchases and exchange
arrangements. The Electric Utility's 1994 reserve margin, as a percentage of
maximum demand, was 9%.
Increases in peak capability will be met with a combination of resources
including upgrades to hydroelectric and thermal facilities, both short- and
long-term purchase contracts and Demand Side Management. New electric
capacity will be required in the late 1990s to meet load growth and the
expiration of two power purchase contracts totalling approximately
150 megawatts. Pursuant to a Request for Proposal (RFP), a variety of
projects, including some proposed by the Company have been evaluated under a
least cost planning process. To date, the bid resources that have been
acquired include the extension to 2003 of an existing 50,000 Kw exchange
contract with the Idaho Power Company, the purchase of a 15 year 98,000 kW
winter season power purchase starting in November 1996 from Basin Electric
Power Cooperative, and construction has commenced on a 41,000 kW upgrade to
the Utility's hydroelectric facility at Thompson Falls. In addition, the
Utility is continuing to decrease energy and peak demand by investing in
demand-side management programs. In 1994, the Company went out for its second
RFP for resources. Evaluation of the responses is ongoing and will be
complete during the first half of 1995. The results of this analysis will be
part of the Electric Utility's 1995 integrated least cost plan filing with the
Montana Public Service Commission. <PAGE>
ITEM 1. BUSINESS (Continued)
During the year ended December 31, 1994, the sources of the Utility
Division electric supply were: hydro, 27%; coal, 44%; and purchased power,
29%. Hydroelectric generation decreased 16% due to lower stream flows in
1994, partially offset by an 8% increase in steam generation. The cost of
coal burned has been as follows:
Year Ended December 31
1994 1993 1992
Average cost per million Btu's. . . . . . $ 0.66 $ 0.65 $ 0.65
Average cost per ton (delivered). . . . . 11.24 11.16 11.30
The Company's electric system forms an integral part of the Northwest
Power Pool consisting of the major electric suppliers in the United States,
Pacific Northwest and British Columbia, and parts of Alberta, Canada. The
Company also is a party to the Pacific Northwest Coordination Agreement which
integrates electric and hydroelectric operations of the 18 parties associated
with generating facilities in the Columbia River Basin; is a member of the
Western Systems Coordinating Council, organized by 68 member systems and
10 affiliates in the 14 western states, British Columbia, Alberta and Mexico
to assure reliability of operations and service to their customers; is one of
64 members of the Western Systems Power Pool, organized to enhance the
economics of power production and reliability of service among the western
states power systems; and is a party to the Intercompany Pool Agreement for
the coordination of load, resource and transmission planning, operations and
reserve requirements among eight utilities in Washington, Oregon, Idaho,
Montana, Wyoming, Nevada and Utah. The Company participates in an
interconnection agreement with The Washington Water Power Company, Idaho Power
Company, and PacifiCorp, providing for the sharing of transmission capacity of
certain lines on their respective interconnected systems. The Company also
operates, in coordination with its own transmission lines and facilities, the
transmission lines and facilities which are jointly owned by the utility
owners of the four Colstrip generating units. The Company and the Western
Area Power Administration have transmission interconnection and agreements
which provide for the mutual use of excess capacity of certain lines on each
party's system for the transmission of power east of the Continental Divide in
Montana and for the firm use of certain of the Company's transmission lines to
deliver government power.
NATURAL GAS UTILITY OPERATIONS: Natural gas supply requirements in 1994
totaled 19,594 Mmcf, of which 12,537 Mmcf were from Montana and 7,057 Mmcf
from Canada. The Gas Utility produced 40% of the Montana natural gas and its
Canadian subsidiaries produced 62% of the Canadian natural gas.
The Company implemented open access gas transportation on November 1,
1991. As of September 1993, substantially all eligible customers were
acquiring 100% of their gas supplies directly from other suppliers. The Gas
Utility transports gas supplies for these customers. The total volumes of
natural gas transported were 23,700 Mmcf, 17,900 Mmcf and 15,100 Mmcf for
1994, 1993 and 1992, respectively.
Total 1995 natural gas requirements, estimated to be 21,600 Mmcf, are
anticipated to be supplied from existing reserves and purchase contracts.
Approximately 13,100 Mmcf of these requirements are expected to be obtained in
the United States and 8,500 Mmcf from Canada. The Gas Utility expects to
produce 45% of the Montana natural gas. Its Canadian subsidiaries are
expected to produce 60% of the Canadian natural gas. The 1995 transportation
volumes are anticipated to be 28,961 Mmcf.
Exportation of natural gas from Canada is controlled by the Canadian
provincial and federal governments. The Company has a long-term export
license which entitles it to export up to 10,000 Mmcf, after losses, annually
through October 2006.
ENTECH:
GENERAL: Entech, Inc. (Entech) conducts its businesses through various
subsidiaries, all of which, with immaterial exceptions, are wholly-owned. It
also owns a passive investment in a gold mine in Brazil. Its coal and lignite
business is conducted through several subsidiaries. Western Energy Company
(Western) holds leases and rights on coal properties in Montana and Wyoming
and operates the Rosebud Mine. Western's subsidiary, Western SynCoal Company
(SynCoal), owns 75% of a patented coal enhancement process and a subsidiary of
Northern States Power owns 25% of this patented coal enhancement process and
each own 50% of the Rosebud SynCoal Partnership. The Partnership owns and
operates a coal enhancement process demonstration plant at the Rosebud Mine.
Northwestern Resources Company (Northwestern) holds leases on coal and lignite
properties in Texas and Wyoming and operates the Jewett Mine. Basin
Resources, Inc. (Basin) operates the Golden Eagle Mine, and North Central
Energy Company (North Central) owns and holds leases on coal properties, in
Colorado. Horizon Coal Services, Inc. (Horizon) markets coal and lignite, and
holds leases and rights on lignite properties in Montana, Texas and Alabama.
Approximately 94% of total annual coal and lignite production is sold under
long-term contracts. Entech's oil and natural gas business is conducted in
the United States through North American Resources Company (NARCO) and in
Canada through both Altana Exploration Company (Altana) and Roan Resources,
Ltd. (Roan). Entech's telecommunication business is conducted through TRI
Touch America, Inc. Entech's other businesses are conducted by various
subsidiaries, none of which is a significant subsidiary.
COAL OPERATIONS: Western's Rosebud Mine is at Colstrip, Montana, in the
northern Powder River Basin, where coal is surface-mined and, after crushing,
sold without further preparation, principally for use by electric utilities in
steam-electric generating plants. The mine's principal customers are the
owners of the four mine-mouth Colstrip units and the Utility Division's
Corette Plant located at Billings, Montana. These customers purchased
approximately 71% of the 1994 production. Most of the remainder is sold to
Midwestern customers located in Michigan, Minnesota, North Dakota and
Wisconsin.
During 1994, Western mined and sold 13,717,418 tons, of which
3,787,318 tons were sold to the Company. Western's Colstrip production is
estimated to be 12,300,000 tons in 1995 and 10,300,000 tons in 1996. Future
production is reduced as a result of the non-renewal of a contract with a
Midwestern customer at year-end 1994 and the anticipated non-renewal of
contracts with another Midwestern customer and the Corette Plant at year-end
1995.
Western has experienced strong competition from southern Powder River
Basin producers, primarily those in Wyoming, for its Midwestern coal sales,
which represent approximately 23% of Western's total sales. In December 1994,
Western lost a contract with a Midwestern customer because of a market price
reopener. While Western has a per-ton rail rate advantage to some of the
upper Midwest markets, Wyoming producers generally experience lower stripping
ratios, royalties and production taxes. In addition, Western produces coal
containing higher, noncompliance levels of sulfur than southern Powder River
Basin Mines.
Northwestern's Jewett Mine is located in central Texas about midway
between Dallas and Houston. Northwestern supplies lignite under a long-term
contract to the two electric generating units, located adjacent to the mine,
that are owned by Houston Lighting and Power Company. Total deliveries during
1994, a record production year, were 8,627,923 tons. The estimated production
for 1995 and 1996 is 8,100,000 and 7,700,000 tons, respectively. Future
production is reduced as a result of the two generating units returning to
normal levels of demand plus planned maintenance outages.
Basin's underground Golden Eagle Mine is located in southern Colorado
near Trinidad. The coal is processed through an on-site wash plant to reduce
the ash content prior to sale. Total deliveries from the mine, which has a
current capacity to produce 2,000,000 tons annually, were 1,076,321 tons
during 1994. In July 1994, Basin began delivering coal under a long-term
contract to supply up to 1,200,000 tons annually to a southeastern utility. A
portion of Basin's production supplies short-term sales to industrial and
utility customers. The mine experienced unanticipated production problems in
both the mining and the wash plant operations during 1994. These production
problems are being addressed and management expects resolution of them in
1995. Estimated production for 1995 and 1996 is 1,400,000 and 1,900,000 tons,
respectively. For further discussion of Basin's production problems, see
Item 7, "Management's Discussion and Analysis of Financial Condition and
Results of Operation" under "Entech Coal Operations."
OIL AND GAS OPERATIONS: NARCO's producing oil and natural gas
properties are principally located in the states of Wyoming, Colorado, Kansas,
Oklahoma and Montana. Altana and Roan's properties are principally located in
the Province of Alberta, Canada.
NARCO has entered into agreements to supply 138,000 Mmcf of natural gas
to four cogeneration facilities over periods of 10 to 16 years with
performance guaranteed by Entech. NARCO has sufficient proven, developed and
undeveloped reserves to supply all of the remaining natural gas required by
those agreements. None of the reserves are dedicated to supply these
agreements. For information on another subsidiary's participation in an
investment in these cogeneration projects, See Item 1 "Independent Power
Group."
Natural gas production in both the United States and Canada is currently
sold pursuant to short-term, spot market and long-term contracts.
Approximately 30,000 Mmcf, or one-third of Altana and Roan's natural gas
reserves, are dedicated to long-term contracts expiring at various times
through 2005.
Through its subsidiary Entech Altamont, Inc., (a single purpose
subsidiary), Entech owns a minority interest in a joint venture to construct
the proposed Altamont pipeline. In 1991, Altamont received FERC approval to
construct a 620 mile pipeline running from the Alberta-Montana border to Muddy
Creek, Wyoming. The decision to proceed with the construction of this
pipeline will depend upon obtaining the necessary regulatory approval and
shipper commitments.
<PAGE>
INDEPENDENT POWER GROUP:
GENERAL: The Independent Power Group (IPG), which consists of
Continental Energy Services, Inc. (CES) and Colstrip 4 Lease Management
Division, manages sales of the Company's 210 megawatt share of Colstrip Unit 4
generation to the Los Angeles Department of Water and Power and to Puget Sound
Power & Light Company (Puget) under contracts which are coextensive with the
Company's leasehold interest in the Unit. See Item 3, "Legal Proceedings" for
additional information pertaining to the Puget Contract.
Through CES, the IPG has invested in six operating, natural gas fired,
independent power projects located in Texas, New York, Washington and the
United Kingdom, two independent power projects under construction in Texas and
Washington and another under development in China. CES also participates with
several partners in several nonutility electric generation development efforts
and peak shaving facilities by providing funding and project development
expertise. This participation includes domestic as well as foreign projects.
In August 1994, CES sold 50% of its wholly-owned subsidiary, North
American Energy Services Company (NAES), which it acquired in November 1992,
to Illinova Generating Company. NAES provides energy-related support services
including the operation and maintenance of power plants for private power
generating companies and provides maintenance services for power plants owned
and operated by electric utilities.
ENVIRONMENT:
The information required in this section is contained in Item 7,
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" under "Environmental Issues."
EMPLOYEES:
At December 31, 1994, the Company and its subsidiaries employed
3,686 persons of which 2,290 were utility and Office of the Corporation
employees (including 569 employees at the jointly owned Colstrip Units 1-4), 9
Independent Power Group employees and 1,387 Entech employees.
FOREIGN AND DOMESTIC OPERATIONS:
See Item 2, "Utility Natural Gas Properties," for information on the
Company's Canadian and domestic utility natural gas properties. See Item 2,
"Entech Oil and Natural Gas Properties" for information on Entech's Canadian
and domestic oil and natural gas properties.
<PAGE>
EXECUTIVE OFFICERS:
Corporate Officers:
In 1992, D. T. Berube, 61, was elected Chairman of the Board and Chief
Executive Officer. He served as President and Chief Operating Officer,
Entech, Inc., 1988-1991.
In 1991, J. P. Pederson, 52, was elected Vice President and Chief
Financial Officer. He served as Vice President Corporate Finance 1990-1991.
In 1993, P. K. Merrell, 42, was elected Vice President and Secretary.
She served as Staff Attorney 1981-1991, Assistant Secretary 1991-1992, and
Secretary 1992-1993.
In 1991, M. E. Zimmerman, 46, was elected Vice President and General
Counsel. He served as General Counsel from 1989-1991.
Utility Division Officers:
In 1990, R. P. Gannon, 50, was elected President and Chief Operating
Officer - Utility Division.
In 1993, A. K. Neill, 57, was elected Executive Vice President -
Generation and Transmission. He had previously served as Executive Vice
President - Utility Services since 1987.
In 1993, J. D. Haffey, 49, was elected Vice President - Administration
and Regulatory Affairs. He had previously served as Vice President -
Regulatory Affairs for the Utility Division since 1987.
In 1993, D. A. Johnson, 50, was elected Vice President - Utility
Services. He had previously served as Vice President - Gas Supply and
Transportation for the Utility Division since 1984.
In 1993, C. D. Regan, 58, was elected Vice President - Natural Gas
Supply and Transportation. He had previously served as Vice President -
Energy Services for the Utility Division since 1986.
In 1988, G. A. Thorson, 60, was elected Vice President - Colstrip
Project Division for the Utility Division.
In 1993, W. C. Verbael, 57, was elected Vice President - Accounting,
Finance and Information Services. He had previously served as Vice
President - Accounting and Finance for the Utility Division since 1984.
In 1993, P. J. Cole, 37, was elected Treasurer for the Utility Division.
He served as Manager, Corporate Financial Planning and Analysis 1986-1992, and
as Assistant Treasurer 1992-1993.
In 1990, J. S. Miller, 51, was elected Controller for the Utility
Division.
Entech Officers:
In 1992, J. J. Murphy, 56, was elected President and Chief Operating
Officer - Entech, Inc. He served as President and Chief Operating Officer,
Western Energy and Northwestern Resources Co., 1988-1991.
In 1985, E. M. Senechal, 45, was elected Vice President and Treasurer -
Entech, Inc.
Independent Power Group Officer:
In 1992, R. F. Cromer, 49, was elected President and Chief Operating
Officer - Continental Energy Services, Inc. He served as Vice President and
General Manager, Continental Energy Services 1989-1992.
<PAGE>
ITEM 2. PROPERTIES
UTILITY DIVISION:
ELECTRIC PROPERTIES: The Company's Utility Division electric system
extends through the western two-thirds of Montana. Generating capability is
provided by four coal-fired thermal generation units, with total net
capability available to the Utility of 697,000 kW, and 12 hydroelectric
projects, with total net capability of 489,000 kW. The thermal units are (1)
Colstrip Unit 3, which has a net capability of 727,000 kW, of which the
Company owns 218,000 kW, (2) Colstrip Units 1 and 2, with a combined net
capability of 638,000 kW, of which the Utility owns 319,000 kW, and (3) the
160,000 kW Corette Plant. Substantially all of the Utility's coal
requirements are supplied by Western Energy Company under long-term contracts.
Reliability of service is enhanced by the location of hydroelectric generation
on two separate watersheds with different precipitation characteristics and by
diverse sources of thermal generation.
In addition to the Utility's hydroelectric and thermal resources, it
currently receives power through 21 power contracts totaling 415,000 kW of
firm winter peak capacity. These contracts vary in type, size, seller and
ending dates. The Utility has one energy contract ending in 1995 for the
delivery of up to 10,000 kW of power to the Utility during the off-peak hours.
Hydroelectric projects are licensed by the FERC under licenses which
expire on varying dates from 1995 to 2035. The Company is in the process of
relicensing its nine dams located on the Missouri and Madison rivers. See
Item 8, "Note 2 to the Consolidated Financial Statements."
At December 31, 1994, the Utility owned and operated 6,890 miles of
transmission lines and 15,073 miles of distribution lines.
NATURAL GAS PROPERTIES: The Utility produces natural gas from fields in
Montana and Wyoming and through its subsidiary, Canadian-Montana Gas Company,
from fields in southeastern Alberta, Canada. Natural gas is also purchased
from independent producers in Montana and Alberta.
All of the Utility's natural gas customers are served from its
transmission system which extends through the western two-thirds of Montana.
System reliability is enhanced by four natural gas storage fields which enable
the Utility to store natural gas in excess of system load requirements during
the summer for delivery during winter periods of peak demand.
At December 31, 1994, the Gas Utility and its subsidiaries owned and
operated 2,034 miles of natural gas transmission lines and 3,075 miles of
distribution mains.
All natural gas volumes are at a pressure base of 14.73 psia at
60 degrees Fahrenheit, except for those volumes used to compute the average
revenues by customer classification.
For information pertaining to the Company's net recoverable utility
natural gas reserves, see Item 8, "Supplementary Data."
In addition to owned reserves, the Utility at December 31, 1994,
controlled under purchase contracts, 60,604 Mmcf of proven reserves in the
United States and 36,190 Mmcf in Canada. No significant change has occurred
and no event has taken place since December 31, 1994, that would materially
affect the magnitude of the Utility's reserve estimates.
Utility natural gas reserve estimates have not been filed with any other
federal or any foreign governmental agency during the past twelve months.
Certain lease and well data, with respect only to owned wells, are filed with
the Internal Revenue Service for tax purposes.
Total produced, royalty and purchased natural gas volumes in Mmcf during
the last three years were as follows:
United States Canada
Produced Royalty Purchased Produced Royalty Purchased
1992 . . . . 5,724 561 8,713 2,951 916 3,443
1993 . . . . 5,587 539 8,554 3,927 1,186 2,824
1994 . . . . 4,742 230 7,565 3,350 998 2,709
The following table presents information as of December 31, 1994,
concerning the Utility natural gas wells and the owned or leased acreages in
which they are located.
United States Canada
Gross productive wells. . . . . . . . . . 610 173
Net productive wells. . . . . . . . . . . 499 162
Gross wells with multiple completions . . 18 11
Net wells with multiple completions . . . 12.8 10.5
Gross producing acres . . . . . . . . . . 457,145 194,392
Net producing acres . . . . . . . . . . . 296,759 171,798
Gross undeveloped acres . . . . . . . . . 63,344 45,280
Net undeveloped acres . . . . . . . . . . 53,227 44,320
These acreages are located primarily in Montana and Alberta, Canada.
The Company anticipates that during 1995 total exploration and
development expenditures (expense and capital) will be approximately
$2,114,000 in the United States and approximately $1,735,000 in Canada.
The following table presents information on utility natural gas
exploratory and development wells drilled during 1994, 1993 and 1992.
United States Canada
1994 1993 1992 1994 1993 1992
Net productive exploratory
wells. . . . . . . . . . . . - - - - - -
Net dry exploratory wells. . . - - - - - -
Net productive development
wells. . . . . . . . . . . . 14.38 12.25 6.38 6.00 3.00 -
Net dry development wells. . . 4.00 2.00 3.00 1.00 1.00 -
The following table presents average revenues received per Mcf by
customer classification for natural gas from all sources for the years 1994,
1993 and 1992. Revenues per Mcf are computed based on volumes at varying
pressure bases as billed.
Year Ended December 31
Customer Classification 1994 1993 1992
Residential. . . . . . . . . . . . . . . $ 4.64 $ 4.35 $ 4.22
Commercial . . . . . . . . . . . . . . . 4.43 4.20 3.91
Industrial . . . . . . . . . . . . . . . 4.25 4.02 3.76
Other gas utilities. . . . . . . . . . . 3.72 3.38 3.33
The following table presents the average production cost per Mcf for
produced utility natural gas, in U. S. dollars, for the three years 1994, 1993
and 1992.
United States Canada
1992. . . . . . $ 0.84 $ 0.38
1993. . . . . . 0.97 0.36
1994. . . . . . 1.07 0.40
Production cost per unit fluctuated over the three-year period primarily
as a result of expensing fixed costs over varying levels of production.
ENTECH:
COAL PROPERTIES: Western leases and produces coal from Montana and
Wyoming properties. Northwestern leases and produces lignite from properties
in Texas and leases coal properties in Wyoming. Basin produces coal from
properties in Colorado that North Central owns and leases. Horizon leases
lignite properties in Montana, Texas and Alabama. Western SynCoal owns a 50%
partnership interest in a coal enhancement demonstration plant at Colstrip,
Montana.
Western has coal mining leases covering approximately 551,000,000 proved
and probable, and recoverable tons of surface-minable coal reserves averaging
less than 0.9 pounds of sulfur per million Btu (low-sulfur quality) at
Colstrip. Approximately 264,000,000 tons of these reserves are committed to
present contracts, including requirements of the Colstrip Units.
Northwestern has lignite mining leases in central Texas at the Jewett
Mine covering approximately 237,000,000 proved and probable, and recoverable
tons of surface-minable lignite reserves. Northwestern has contracted all of
these reserves to Houston Lighting and Power Company, which owns two electric
generating units located adjacent to the mine.
In 1990, Northwestern acquired surface rights and coal leases which
contain approximately 628,000,000 proved and probable, and recoverable tons of
surface-minable, coal reserves, averaging less than 0.6 pounds of sulfur per
million Btu (compliance quality), in the southern Powder River coal region
located at Rocky Butte, Wyoming. In January 1993, Northwestern acquired an
adjacent federal lease which contains approximately 56,000,000 proved and
probable, and recoverable tons of compliance quality, surface minable, coal
reserves. Northwestern's application with the Department of Interior to
combine these leases into one logical mining unit, which was granted in
December 1993, requires the property to be developed by January 1, 2003. A
permit application was submitted to the Wyoming Department of Environmental
Quality on November 7, 1994. Northwestern expects to receive a mine permit by
the second quarter of 1996. No definite plans for mine development have been
made.
North Central owns and leases lands containing approximately
98,600,000 tons of proved and probable, and recoverable, compliance quality
underground-minable coal reserves near Trinidad, Colorado. Approximately
32,000,000 tons of these reserves are dedicated to a long-term contract.
Horizon has undeveloped mining leases covering lands in three different
states. Properties in eastern Montana contain approximately 31,000,000 proved
and probable, and recoverable tons of low-sulfur surface-minable lignite,
under lease. Those in southeastern Alabama contain approximately 97,000,000
proved and probable, and recoverable tons of surface-minable lignite
(averaging greater than 1.25 pounds of sulfur per million Btu). Those in
central Texas contain approximately 177,000,000 proved and probable, and
recoverable tons of surface-minable lignite.
OIL AND NATURAL GAS PROPERTIES: No significant change has occurred and
no event has taken place since December 31, 1994, which would materially
affect the estimated quantities of proved reserves. For information
pertaining to net recoverable Entech oil and natural gas reserves, see Item 8,
"Supplementary Data."
Entech's oil and natural gas volumes are at a pressure base of
14.73 psia at 60 degrees Fahrenheit.
Entech's oil and natural gas reserve estimates have not been filed with
any other federal or any foreign government agency during the past 12 months.
Certain lease information and well data, only with respect to owned wells, is
filed with the Internal Revenue Service for tax purposes.
The following table presents information on produced oil and natural gas
average sales prices and production costs in U.S. dollars for 1994, 1993 and
1992.
<TABLE>
<CAPTION>
Year Ended December 31
1994 1993 1992
United United United
States Canada States Canada States Canada
<S> <C> <C> <C> <C> <C> <C>
Average sales price:
Per Mcf of natural gas . . . . . . $ 1.60 $ 1.48 $ 1.84 $ 1.25 $ 1.50 $ 1.06
Per barrel of oil. . . . . . . . . 14.75 12.95 17.61 14.21 19.15 14.77
Per barrel of natural gas liquids. 9.50 9.99 10.98 11.66 10.16 13.42
Average production cost:
Per barrel of oil equivalent . . . $ 3.00 $ 2.93 $ 3.84 $ 3.02 $ 3.52 $ 3.15
</TABLE>
Natural gas production was converted to barrel of oil equivalents based
on a ratio of 6 Mcf to 1 barrel of oil.
Entech's oil, natural gas and natural gas liquids production was sold
under both short- and long-term contracts at posted prices or under forward
market arrangements. From 1993 to 1994, Entech's average sale prices changed
due to fluctuations in market prices and currency exchange rates. In the
U.S., Entech's average production cost changed reflecting lower production
taxes per barrel of oil equivalent due to lower revenues received and lower
operating expenses.
Information on Entech's natural gas and oil wells and the owned or
leased acreages in which they are located, as of December 31, 1994, is
presented below.
United
States Canada
Gross productive natural gas wells 379 184
Net productive natural gas wells 232.03 121.31
Gross productive oil wells 247 209
Net productive oil wells 160.56 119.08
Gross producing acres 127,675 191,439
Net producing acres 58,752 96,805
Gross undeveloped acres 260,410 202,764
Net undeveloped acres 126,028 125,288
The wells located in Canada include multiple completions of 12 gross
productive natural gas wells and 9.81 net productive gas wells.
The foregoing acreages located in the United States and Canada are
primarily in the Rocky Mountain states and Alberta.
It is anticipated that during 1995 total exploration, acquisition and
development expenditures (expense and capital) will be approximately
$26,895,000 in the United States and approximately $10,814,000 in Canada.
<PAGE>
The following table presents information on Entech's oil and natural gas
exploratory and development wells drilled during 1994, 1993 and 1992.
<TABLE>
(CAPTION>
United States Canada
1994 1993 1992 1994 1993 1992
<S> <C> <C> <C> <C> <C> <C>
Net productive natural gas
exploratory wells. . . . . 1.15 1.25 0.56 0.87 0.87 0.50
Net productive oil
exploratory wells. . . . . -- 3.00 -- -- 1.04 0.56
Net productive natural gas
development wells. . . . . 6.28 32.16 20.73 1.06 5.70 1.00
Net productive oil
development wells. . . . . 1.29 4.12 7.00 8.67 6.56 24.65
Net dry exploratory wells. . 3.44 2.79 -- 2.00 5.92 3.14
Net dry development wells. . 0.59 2.76 4.50 3.05 3.00 3.84
</TABLE>
For information on properties acquired, see Item 8, "Supplementary
Data."
<PAGE>
INDEPENDENT POWER GROUP:
The IPG manages the sale of power from the Company's 210 MW Colstrip 4
leased interest and associated common and transmission facilities. The IPG
also has ownership or contract rights in a number of nonutility power
generation projects:
Projects in Operation:
<TABLE>
<CAPTION>
IPG
Share
of
Rated Rated
Location Capa- Capa-
(Commercial Ownership city city Customer
Project Operation) or Interest MW MW Electricity Thermal
<S> <C> <C> <C> <C> <C> <C>
Encogen One Sweetwater, TX 49.5% 255 126 Texas Utility U.S. Gypsum
(1989) Electric Co
Tenaska-Paris Paris, TX 10.0% 223 22 Texas Utility Campbell
(1989) Electric Co Soup Co
Encogen Four Buffalo, NY 49.5% 62 31 Niagara Mohawk Outokumpu
(1992) Power Corp
Lockport Lockport, NY 22.3% 168 37 New York State Harrison
(1993) Electric & Radiator
Gas Corp
Teesside United Kingdom 3.2%* 1,725* 56 Various U.K. --
(1993) customers
Tenaska- Ferndale, WA 25.1% 245 61 Puget Sound Tosco Corp
Ferndale (1994) Power & Light
* Interest is the contractual right to utilize one-third of 168 megawatts of capacity to
produce electricity for sale from a 1,725 megawatt natural gas-fired electric generating
facility.
Projects Under Construction:
IPG
Share
of
Location Rated Rated
(Anticipated Capa- Capa-
Commercial Ownership city city Customer
Project Operation) or Interest MW MW Electricity Thermal
Tenaska- Bonneville None
Frederickson Frederickson, WA 25.3% 248 63 Power Admn
(1996)
Tenaska-
Cleburne Cleburne, TX 25% 258 65 Brazos REA **
(1997)
**Not determined at this time.
<PAGE>
Projects Under Development:
IPG
Share
of
Rated Rated
Devel- Capa- Capa-
opment city city Customer
Project Location Interest MW MW Electricity Thermal
China-Henan Henan Province, 18.3% 700 ** Henan Province None
China Electric
Power Bureau
**Not determined at this time.
</TABLE>
<PAGE>
ITEM 3. LEGAL PROCEEDINGS
The Company, through the IPG, sells 94 MW of electricity to Puget Sound
Power & Light Company (Puget) under a 25-year agreement which expires in 2010
(the Agreement). On February 27, 1995, Puget notified the Company of its
intention to terminate the Agreement, effective the next day, alleging the
Company had failed to satisfy a requirement to secure firm contractual rights
to transmission paths for the delivery of the electricity.
If Puget establishes its right to terminate the Agreement, the Company
would be at risk for the difference between the power purchase price under the
Agreement, approximately 4.6 cents/kWh ($29,000,000 in revenue) for the
current contract year and escalating annually thereafter, and the prices it
might receive from future sales of the electricity. In addition, the Company
would be obligated to reimburse Puget approximately $37,000,000 for the amount
by which Puget's payments for the electricity have exceeded its projection of
avoided costs. This reimbursement obligation would peak at approximately
$47,000,000 by the end of 1995 and would be reduced to zero by the end of the
Agreement's term in 2010. The Company also may be required to make a non-cash
adjustment to its accounting records reducing an asset related to the
Agreement by an amount currently estimated to be approximately $20,000,000,
pre-tax.
The Company believes that is has performed its obligations under the
Agreement and that Puget has no basis for termination. On February 28, 1995,
the Company obtained, from a Montana district court, a temporary restraining
order enjoining Puget from terminating the Agreement. A hearing has been set
for March 15, 1995 to determine whether a preliminary injunction should be
issued. The Company also has filed with that court a complaint for a
declaratory ruling that it has complied with the Agreement and that Puget has
no basis for termination. The Company will seek to enforce the Agreement and
to obtain damages for any breach; however, it cannot predict the outcome of
this controversy.
Refer to Item 7, "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Environmental Issues" for additional
information pertaining to legal proceedings.
Refer to Item 8, "Financial Statements and Supplementary Data - Note 2
to the Consolidated Financial Statements" for additional information
pertaining to legal proceedings.
The Company and its subsidiaries are party to various other legal
claims, actions and complaints arising in the ordinary course of business.
Management does not expect disposition of these matters to have a material
adverse effect on the Company's consolidated results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
<PAGE>
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
Common Stock Information
The Common Stock of the Company is listed on the New York and Pacific
Stock Exchanges. The following table presents the high and low sale prices of
the common stock of the Company as well as dividends declared for the years
1994 and 1993. The number of common shareholders of record on December 31,
1994, was 40,956.
Dividends
Declared
per
1994 High Low Share
1st quarter $ 25.875 $ 23.250 $ 0.40
2nd quarter 25.000 22.125 0.40
3rd quarter 24.625 21.750 0.40
4th quarter 24.000 22.250 0.40
Dividends
Declared
per
1993 High Low Share
1st quarter $ 27.875 $ 25.125 $ 0.395
2nd quarter 27.750 25.500 0.395
3rd quarter 28.125 26.375 0.395
4th quarter 27.500 24.500 0.400
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
The Montana Power Company and Subsidiaries
Balance Sheet Items (000)
1994 1993 1992
<S> <C> <C> <C>
Assets:
Utility plant. . . . . . . . . . . . $2,071,749 $1,943,428 $1,854,297
Less accumulated depreciation
and depletion. . . . . . . . . . . 619,195 572,141 533,216
Net Utility plant . . . . . . . . 1,452,554 1,371,287 1,321,081
Entech property. . . . . . . . . . . 530,167 526,692 482,732
Less accumulated depreciation
and depletion. . . . . . . . . . . 189,926 182,129 163,185
Net Entech property . . . . . . . 340,241 344,563 319,547
Independent Power Group property . . 70,253 70,198 69,805
Less accumulated depreciation. . . . 17,560 16,822 15,090
Net Independent Power Group . . . 52,693 53,376 54,715
Total net plant and property. . 1,845,488 1,769,226 1,695,343
Other assets . . . . . . . . . . . . 667,209 616,801 590,079
Total Assets. . . . . . . . . . $2,512,697 $2,386,027 $2,285,422
Liabilities:
Common shareholders' equity. . . . . $ 988,100 $ 945,651 $ 902,989
Unallocated stock held by Trustee
for Deferred Savings and ESOP. . . (32,580) (34,419) (36,098)
Preferred stock. . . . . . . . . . . 101,416 101,419 51,984
Long-term debt . . . . . . . . . . . 588,876 571,870 581,179
Other liabilities. . . . . . . . . . 866,885 801,506 785,368
Total Liabilities . . . . . . . $2,512,697 $2,386,027 $2,285,422
</TABLE>
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
The Montana Power Company and Subsidiaries
Balance Sheet Items (000)
1991 1990 1989
<S> <C> <C> <C>
Assets:
Utility plant. . . . . . . . . . . . $1,774,185 $1,712,255 $1,662,887
Less accumulated depreciation
and depletion. . . . . . . . . . . 495,720 468,201 440,944
Net Utility plant . . . . . . . . 1,278,465 1,244,054 1,221,943
Entech property. . . . . . . . . . . 464,978 403,169 357,088
Less accumulated depreciation
and depletion. . . . . . . . . . . 144,691 124,309 106,702
Net Entech property . . . . . . . 320,287 278,860 250,386
Independent Power Group property . . 66,477 66,507 66,000
Less accumulated depreciation. . . . 11,633 10,583 8,790
Net Independent Power Group . . . 54,844 55,924 57,210
Total net plant and property. . 1,653,596 1,578,838 1,529,539
Other assets . . . . . . . . . . . . 564,450 537,686 542,085
Total Assets. . . . . . . . . . $2,218,046 $2,116,524 $2,071,624
Liabilities:
Common shareholders' equity. . . . . $ 862,601 $ 821,521 $ 788,447
Unallocated stock held by Trustee
for Deferred Savings and ESOP. . . (37,631) (39,031) -
Preferred stock. . . . . . . . . . . 51,984 51,984 51,984
Long-term debt . . . . . . . . . . . 603,266 599,971 562,610
Other liabilities. . . . . . . . . . 737,826 682,079 668,583
Total Liabilities . . . . . . . $2,218,046 $2,116,524 $2,071,624
</TABLE>
<PAGE>
Income Statement Items (000)
1994 1993 1992
<TABLE>
<CAPTION>
<S> <C> <C> <C>
Revenues . . . . . . . . . . . . . . . $1,005,970 $1,024,285 $ 943,872
Expenses:
Operations . . . . . . . . . . . . . 440,472 480,382 416,072
Maintenance. . . . . . . . . . . . . 75,357 70,029 70,525
Selling, general and administrative. 103,524 101,286 87,545
Taxes other than income taxes. . . . 99,200 92,430 94,328
Depreciation, depletion and
amortization . . . . . . . . . . . 86,314 82,661 81,732
804,867 826,788 750,202
Income from operations . . . . . . 201,103 197,497 193,670
Interest expense and other income:
Interest . . . . . . . . . . . . . . 46,102 50,739 50,682
Other (income) deductions-net. . . . (13,817) (14,573) (9,716)
32,285 36,166 40,966
Income taxes . . . . . . . . . . . . . 55,226 54,120 45,639
Net income . . . . . . . . . . . . . . 113,592 107,211 107,065
Dividends on preferred stock . . . . . 7,227 4,353 3,790
Net income available for common stock. $ 106,365 $ 102,858 $ 103,275
Net income per share of common stock:
Utility operations . . . . . . . . . $ 0.91 $ 1.07 $ 0.97
Entech operations. . . . . . . . . . 0.90 0.91 0.98
Independent Power Group operations . 0.19 - 0.07
$ 2.00 $ 1.98 $ 2.02
Dividends declared per share of
common stock . . . . . . . . . . . . $ 1.60 $ 1.585 $ 1.55
Average shares outstanding (000) . . . 53,125 52,040 51,126
</TABLE>
<PAGE>
Income Statement Items (000)
1991 1990 1989
<TABLE>
<CAPTION>
<S> <C> <C> <C>
Revenues . . . . . . . . . . . . . . . $ 889,104 $ 795,528 $ 718,430
Expenses:
Operations . . . . . . . . . . . . . 368,797 322,010 288,817
Maintenance. . . . . . . . . . . . . 70,510 66,634 59,040
Selling, general and administrative. 88,926 78,188 60,658
Taxes other than income taxes. . . . 86,278 82,418 72,683
Depreciation, depletion and
amortization . . . . . . . . . . . 75,782 65,790 66,595
690,293 615,040 547,793
Income from operations . . . . . . 198,811 180,488 170,637
Interest expense and other income:
Interest . . . . . . . . . . . . . . 54,135 53,537 58,284
Other (income) deductions-net. . . . (11,432) (8,235) 11,990
42,703 45,302 70,274
Income taxes . . . . . . . . . . . . . 50,393 40,206 25,952
Net income . . . . . . . . . . . . . . 105,715 94,980 74,411
Dividends on preferred stock . . . . . 3,790 3,790 3,790
Net income available for common stock. $ 101,925 $ 91,190 $ 70,621
Net income per share of common stock:
Utility operations . . . . . . . . . $ 0.98 $ 0.89 $ 1.13
Entech operations. . . . . . . . . . 0.98 0.94 0.87
Independent Power Group operations . 0.07 0.01 (0.55)
$ 2.03 $ 1.84 $ 1.45
Dividends declared per share of
common stock . . . . . . . . . . . . $ 1.495 $ 1.435 $ 1.39
Average shares outstanding (000) . . . 50,317 49,657 48,830
</TABLE>
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Results of Operations:
The Company's net income available for common stock increased to
$106,365,000 in 1994 compared to $102,858,000 and $103,275,000 in 1993 and
1992, respectively. The following discussion presents significant events or
trends which have had an effect on the operations of the Company during the
years 1992 through 1994. Also presented are factors which are expected to
have an impact on operating results in the future.
Net Income Per Share of Common Stock:
Although net income available for common stock increased $3,507,000, the
net income per share increase was moderated by additional outstanding shares.
The following table shows the sources of consolidated net income on a per
share basis.
1994 1993 1992
Utility Operations $ 0.91 $ 1.07 $ 0.97
Entech 0.90 0.91 0.98
Independent Power Group 0.19 - 0.07
$ 2.00 $ 1.98 $ 2.02
Consolidated net income per share for 1994 increased due to sharply
higher Independent Power Group (IPG) earnings resulting from power project
development revenues and improved performance by the Colstrip units. Despite
higher revenues resulting from rate increases, growth in the number of
customers, increased industrial electric loads and improved Colstrip units
performance, Utility Division earnings were lower due to less favorable
hydroelectric generation and wholesale market conditions, increased property
taxes, an increased regulatory disallowance on coal purchases and warmer
weather. Entech earnings were comparable to 1993. A 1993 non-recurring gain
on the sale of an Entech Oil Division's non-strategic asset and continuing
losses at Entech's underground mine in Colorado, where production problems are
being addressed, were offset by increased coal sales from mines in Montana and
Texas.
Colder weather and increased hydroelectric generation combined to
increase the earnings of the Utility Division for 1993. The Utility increase
offset reduced earnings of Entech and the IPG. Entech earnings decreased
primarily due to reduced coal sales resulting from an extended outage at a
Colstrip generating unit. The IPG earnings decrease resulted primarily from a
decrease in independent power project development revenues.
<PAGE>
<TABLE>
<CAPTION>
UTILITY OPERATIONS
Year Ended December 31
1994 1993 1992
Thousands of Dollars
ELECTRIC UTILITY:
<S> <C> <C> <C>
REVENUES
Revenues . . . . . . . . . . . . . . . . . . . $ 427,686 $ 426,746 $ 402,402
Intersegment revenues. . . . . . . . . . . . . 5,924 7,532 4,783
433,610 434,278 407,185
EXPENSES
Power supply . . . . . . . . . . . . . . . . . 178,927 172,190 166,695
Transmission and distribution. . . . . . . . . 27,566 28,109 23,896
Selling, general and administrative. . . . . . 46,134 43,284 38,638
Taxes other than income taxes. . . . . . . . . 42,214 39,014 36,202
Depreciation and amortization. . . . . . . . . 40,699 39,151 37,180
335,540 321,748 302,611
INCOME FROM ELECTRIC OPERATIONS. . . . . . . . 98,070 112,530 104,574
NATURAL GAS UTILITY:
REVENUES
Revenues (other than gas supply
cost revenues) . . . . . . . . . . . . . . . 88,914 87,634 77,320
Gas supply cost revenues . . . . . . . . . . . 18,191 23,062 20,165
Intersegment revenues. . . . . . . . . . . . . 917 778 1,054
108,022 111,474 98,539
EXPENSES:
Gas supply costs . . . . . . . . . . . . . . . 18,191 23,062 20,165
Other production, gathering and exploration. . 8,882 9,331 11,420
Transmission and distribution. . . . . . . . . 10,154 9,256 8,829
Selling, general and administrative. . . . . . 18,066 17,197 16,100
Taxes other than income taxes. . . . . . . . . 13,708 12,715 11,418
Depreciation, depletion and amortization . . . 9,445 8,971 8,302
78,446 80,532 76,234
INCOME FROM GAS OPERATIONS 29,576 30,942 22,305
INTEREST EXPENSE AND OTHER INCOME:
Interest . . . . . . . . . . . . . . . . . . . 43,013 46,885 47,733
Other (income) deductions - net. . . . . . . . (3,947) (839) (1,183)
39,066 46,046 46,550
INCOME BEFORE INCOME TAXES . . . . . . . . . . . 88,580 97,426 80,329
INCOME TAXES . . . . . . . . . . . . . . . . . . 33,171 37,364 27,226
UTILITY NET INCOME . . . . . . . . . . . . . . . $ 55,409 $ 60,062 $ 53,103
</TABLE>
<PAGE>
Utility Operations:
Weather can significantly affect revenues and net income, and should be
considered when determining trends. The Company's sales increase as a result
of colder weather in the winter months. As measured by heating degree days,
the weather in 1994 in the Company's service territory was 13% warmer than
1993 and 6% warmer than normal. The weather in 1993 was 17% colder than 1992
and 8% colder than normal.
Electric Utility:
The following table shows year-to-year changes for the previous two
years, in millions of dollars, in the various classifications of electric
revenues (excluding intersegment revenues) and the related percentage changes
in volumes sold and prices received:
1994 1993
General business - revenue $ 11 $ 9
- volume 3% 3%
- price/kWh - -
Other utilities - revenue $ (9) $ 11
- volume (6%) 5%
- price/kWh (5%) 10%
Miscellaneous - revenue $ (1) $ 4
1994 Compared to 1993
Income from electric operations decreased $14,500,000 due primarily to
the less favorable hydroelectric generation and wholesale market conditions
partially offset by higher rates and growth in customers.
Revenues:
Electric sales from general business customers increased $11,500,000
including an increase of $5,800,000 in revenues from industrial customers.
Industrial revenues increased due to a 5% increase in volumes sold, primarily
the result of additional equipment installed by several customers and demand
for irrigation because of dry summer weather. Growth in residential and
commercial customers and higher rates also contributed to the increase in
revenues. These increases were moderated by volume decreases resulting from
the warmer winter weather.
Electric revenues from sales to other utilities decreased $5,100,000 due
to a reduction in volumes and $4,300,000 due to a decrease in average price.
The decreases resulted from wholesale market conditions returning to near-
normal compared with better than average conditions experienced during the
first and fourth quarters of 1993.
Miscellaneous electric revenues decreased $1,100,000 primarily due to
reduced wheeling revenues resulting from the previously discussed change in
wholesale market conditions.
Intersegment revenues decreased $1,600,000 due primarily to lower
volumes sold to the IPG.
Expenses:
The following table shows the Company's sources of electricity and power
supply expenses (Operation, Fuel for electric generation, and Maintenance)
for 1994 and 1993.
1994 1993
Sources Megawatt Hours
Hydroelectric. . . . . . . . . . . . . . . 2,999,396 3,560,915
Steam. . . . . . . . . . . . . . . . . . . 4,909,852 4,542,100
Purchases. . . . . . . . . . . . . . . . . 3,193,522 3,186,025
Total Power Supply . . . . . . . . . . . 11,102,770 11,289,040
Expenses Thousands of Dollars
Hydroelectric. . . . . . . . . . . . . . . $ 18,395 $ 18,092
Steam. . . . . . . . . . . . . . . . . . . 61,385 57,876
Purchases. . . . . . . . . . . . . . . . . 99,147 96,222
Total Power Supply Expenses. . . . . . . $ 178,927 $ 172,190
Cents per Kilowatt-Hour. . . . . . . . . 1.612 1.525
Steam generation and related fuel expense increased as a result of
improved performance at the Colstrip units which experienced outages in 1993.
Purchased power costs increased as a result of a 3% increase in average price
paid. Total power supply cost increased as a result of this price increase
and a change in the mix of the Utility's sources of energy. In 1994, a larger
portion of power supply was provided by steam generation which is
incrementally more expensive than hydroelectric generation.
The increase in selling, general and administrative results primarily
from a $1,800,000 increase associated with the recognition of postretirement
benefit expense in accordance with SFAS No. 106 commensurate with the approval
of rate treatment for this expense by the PSC in April 1994, a $500,000
increase related to insurance for postemployment disability-related benefits
and a $600,000 increase due to the costs associated with Colstrip housing
damages.
The $3,200,000 increase in taxes - other than income taxes is
principally due to increased property taxes resulting from property additions
and higher mill levies.
Depreciation and amortization expense increased $1,500,000 as a result
of depreciation of additional plant and property in service.
1993 Compared to 1992
Income from electric operations increased $8,000,000 primarily as a
result of increased sales to other utilities resulting from better than normal
market conditions, increased sales to general business customers due to colder
weather and increased hydroelectric generation caused by higher stream flows.
Revenues:
Electric revenues from general business customers increased due to a
3% increase in volumes sold. Weather, which was 17% colder than 1992, and a
2% increase in the number of customers, combined to increase revenues
$8,600,000.
Electric revenues from sales to other utilities increased revenues
$11,400,000. Volumes increased 5% and unit prices increased 10% providing
additional revenues of $4,000,000 and $7,400,000, respectively. The increases
occurred primarily during the first and fourth quarters as a result of
improved regional market conditions during those periods. In spite of reduced
steam generation resulting from outages at a Colstrip generating unit, volumes
sold increased due to a 27% increase in hydroelectric generation for the year
and increased power purchases.
The $4,300,000 increase in miscellaneous electric revenues resulted
primarily from a $2,500,000 increase in wheeling revenues and a $2,300,000
increase due to recording the SFAS No. 87 pension cost funding difference
which is explained further in the expense discussion below.
Intersegment revenues increased due to increased sales to the IPG
resulting from the reduction in the IPG's steam generation at Colstrip due to
the outages.
<PAGE>
Expenses:
The following table shows the Company's sources of electricity and power
supply expenses (Operation, Fuel for electric generation, and Maintenance) for
1993 and 1992.
1993 1992
Sources Megawatt Hours
Hydroelectric. . . . . . . . . . . . . . . 3,560,915 2,793,974
Steam. . . . . . . . . . . . . . . . . . 4,542,100 5,176,130
Purchases. . . . . . . . . . . . . . . . . 3,186,025 2,833,388
Total Power Supply . . . . . . . . . . . 11,289,040 10,803,492
Expenses Thousands of Dollars
Hydroelectric. . . . . . . . . . . . . . . $ 18,092 $ 17,384
Steam. . . . . . . . . . . . . . . . . . . 57,876 59,563
Purchases. . . . . . . . . . . . . . . . . 96,222 89,748
Total Power Supply Expenses. . . . . . . $ 172,190 $ 166,695
Cents per Kilowatt-Hour. . . . . . . . . 1.525 1.543
The Company's hydroelectric output increased as a result of improved
stream flows, offsetting a decline in generation from the Company's coal-fired
plants. Purchased power volumes were increased to meet higher sales to
general business and wholesale customers.
Increases in purchased power costs were partially offset by a $2,900,000
decrease in the amortization of previously deferred costs. Fuel for electric
generation decreased $4,900,000 as a result of outages at a Colstrip
generating unit. The decrease in fuel was partially offset by a $3,000,000
increase in maintenance of steam plants resulting from scheduled maintenance
and unscheduled repairs due to the outages.
Transmission and distribution expense increased $4,200,000 primarily as
a result of increased wheeling expense associated with higher volumes of out-
of-state sales and increased maintenance of the transmission and distribution
system.
The $4,600,000 increase in selling, general and administrative resulted
principally from a $2,600,000 increase in pension costs and expenses of
$1,600,000 related to property damages to homes at Colstrip. The Utility
recovers pension expense for regulatory purposes on a funding basis. In 1993,
pension costs funded were less than SFAS No. 87 pension expense and the
difference of $1,900,000 was recorded as miscellaneous operating revenue.
The $2,800,000 increase in taxes - other than income taxes is
principally due to increased property taxes resulting from property additions
and higher mill levies.
Depreciation and amortization expense increased $2,000,000 as a result
of depreciation of additional plant and property in service.
Natural Gas Utility:
The following table shows year-to-year changes for the previous two
years, in millions of dollars, in the various classifications of natural gas
revenues (excluding intersegment revenues) and the related percentage changes
in volumes sold and prices received:
1994 1993
Revenues (other than gas
supply cost revenues)
Full requirement
Customers -revenue $ (3) $ 7
-volume (13%) 4%
-price/Mcf 11% 6%
Transportation -revenue $ 3 $ 2
-volume 32% 19%
-price/Mcf 26% 35%
Miscellaneous -revenue $ 1 $ 1
1994 Compared to 1993
Income from natural gas operations decreased $1,400,000 primarily due to
decreased volumes resulting from warmer weather and increases in expenses
other than gas supply costs the effects of which were moderated by higher
rates.
Revenues:
Effective September 1, 1993 natural gas customers who consume more than
60,000 Mcfs annually (non full-requirements customers) are no longer required
to purchase any portion of their natural gas supply from the Company. All but
one eligible customer have chosen to convert their volumes to transportation
service only and have secured their own supply. The resulting decline in
natural gas revenue has been offset by revenues from transportation fees and
lower purchased gas costs.
Natural gas revenues (other than gas supply cost) increased $1,300,000.
Growth in the number of residential and commercial customers, higher rates and
increased transportation fees contributed $13,200,000. This increase was
mostly offset by an approximately $11,800,000 decrease due to warmer weather
and the previously discussed switch by eligible customers to transportation
service only.
Gas supply cost revenues consist of the amount authorized by the PSC to
be collected in rates from full requirement customers to cover the cost of
supplying the gas. The $4,900,000 decrease in gas supply cost revenues is the
result of reduced volumes sold due to warmer weather and a supply cost rate
reduction for overcollections of supply costs in prior years. Gas supply cost
revenues and gas supply cost expenses are always equal due to rate and
accounting procedures adopted by the PSC in January 1980.
Expenses:
The decrease in gas supply costs results from the reasons mentioned in
the gas supply cost revenue discussion.
As presented in the electric expense discussion, the $900,000 increase
in selling, general and administrative results primarily from increased costs
associated with the recognition of postretirement benefit expense in
accordance with SFAS No. 106 and insurance for postemployment disability-
related benefits.
Also as previously discussed, the $1,000,000 increase in taxes - other
than income taxes is principally due to increased property taxes resulting
from property additions and higher mill levies.
1993 Compared to 1992
The $8,600,000 increase in income from natural gas operations results
primarily from increased volumes sold to full requirement general business
customers due to colder weather and an increase in the number of customers.
Revenues:
Natural gas revenues (other than gas supply cost revenues) increased
$10,300,000. Volumes sold to residential and commercial customers increased
19% primarily as a result of 17% colder weather and a 4% increase in the
number of customers. The volume increases along with higher rates and
increased transportation fees increased revenues approximately $14,600,000.
These increases were partially offset by the decrease resulting from a 53%
reduction in volumes sold to industrial, government and municipal and other
utility customers who switched to transportation service only.
The $2,900,000 increase in gas supply revenues resulted from the
increase in volumes delivered to full requirement customers resulting from
colder weather and more customers.
Expenses:
The increase in gas supply costs results from the reasons mentioned in
the above gas supply cost revenue discussion.
Other production, gathering and exploration expense decreased $2,000,000
due to decreased operation and maintenance costs and the capitalization of
future use gas well expenses.
The $1,100,000 increase in selling, general and administrative resulted
principally from an increase in labor costs.
The $1,300,000 increase in taxes - other than income taxes is
principally due to increased property taxes resulting from property additions
and higher mill levies.
Interest Expense and Other Income, and Income Taxes:
The decreases in interest expense from 1992 to 1994 are primarily a
result of refinancing of long-term debt at lower interest rates. The average
cost of debt was 7.84%, 8.34% and 8.48% for 1994, 1993 and 1992, respectively.
Other (income) deductions - net increased $3,100,000 in 1994 due
primarily to a non-recurring increase in investment income.
Income taxes changed due primarily to changes in pre-tax income.
<PAGE>
<TABLE>
<CAPTION>
ENTECH OPERATIONS
Year Ended December 31
1994 1993 1992
Thousands of Dollars
<S> <C> <C> <C>
COAL:
REVENUES
Revenues . . . . . . . . . . . . . . . . . . . $ 252,507 $ 225,155 $ 228,191
Intersegment revenues. . . . . . . . . . . . . 42,201 39,637 45,892
294,708 264,792 274,083
EXPENSES
Cost of sales. . . . . . . . . . . . . . . . . 169,259 152,300 152,552
Selling, general and administrative. . . . . . 29,463 24,988 21,029
Taxes other than income taxes. . . . . . . . . 37,733 34,221 41,033
Depreciation, depletion and amortization . . . 12,649 10,193 11,259
249,104 221,702 225,873
INCOME FROM COAL OPERATIONS. . . . . . . . . . 45,604 43,090 48,210
OIL AND NATURAL GAS:
REVENUES
Revenues . . . . . . . . . . . . . . . . . . . 97,994 114,431 90,961
Intersegment revenues. . . . . . . . . . . . . 254 741 1,021
98,248 115,172 91,982
EXPENSES
Cost of sales. . . . . . . . . . . . . . . . . 54,283 71,311 47,058
Selling, general and administrative. . . . . . 8,514 8,549 8,198
Taxes other than income taxes. . . . . . . . . 3,340 4,239 3,190
Depreciation, depletion and amortization . . . 18,464 19,327 19,607
84,601 103,426 78,053
INCOME FROM OIL AND NATURAL GAS OPERATIONS . . 13,647 11,746 13,929
OTHER OPERATIONS:
REVENUES
Revenues . . . . . . . . . . . . . . . . . . . 24,164 24,252 29,473
Intersegment revenues. . . . . . . . . . . . . 787 700 467
24,951 24,952 29,940
EXPENSES
Cost of Sales. . . . . . . . . . . . . . . . . 16,787 17,090 19,566
Selling, general and administrative. . . . . . 4,717 4,719 6,823
Taxes other than income taxes. . . . . . . . . 287 473 741
Depreciation, depletion and amortization . . . 1,945 2,133 2,665
23,736 24,415 29,795
INCOME FROM OTHER OPERATIONS . . . . . . . . . 1,215 537 145
INTEREST EXPENSE AND OTHER INCOME
Interest . . . . . . . . . . . . . . . . . . . 1,425 2,284 2,144
Other (income) deductions-net. . . . . . . . . (3,517) (11,364) (6,235)
(2,092) (9,080) (4,091)
INCOME BEFORE INCOME TAXES . . . . . . . . . . . 62,558 64,453 66,375
INCOME TAXES . . . . . . . . . . . . . . . . . . 14,670 17,263 16,178
ENTECH NET INCOME. . . . . . . . . . . . . . . . $ 47,888 $ 47,190 $ 50,197
/TABLE
<PAGE>
Entech Operations:
Coal Operations:
1994 Compared to 1993
Income from coal operations increased $2,500,000 as a result of
increased coal volumes sold.
Revenues:
Overall coal revenues, including intersegment revenues, increased
$30,000,000 over 1993 due to a 13% increase in volumes sold. Prices per ton
were substantially unchanged. Coal revenues increased $14,200,000 at the
Rosebud Mine due to increased volumes sold to the Colstrip units as compared
to 1993 which was lower due to unplanned outages, and increased volumes sold
to the SynCoal demonstration plant. At the Jewett Mine, coal revenues
increased $3,300,000 due to increased volumes delivered to the mine-mouth
plant. This increase was partially offset by lower revenues received as a
result of mining more of the customer's coal in 1994. Revenues at Jewett are
affected by the mix of tons mined from Northwestern's lignite leases and the
customer's lignite leases. Increased revenues of $12,900,000 at the Golden
Eagle Mine resulted from increased volumes sold to supply coal for a long-term
supply contract and for spot market sales. In July, the mine began delivering
coal under a long-term contract to supply up to 1,200,000 tons of coal
annually to a Southeastern utility.
Entech's Rosebud Mine faces increasing competition for Midwestern
customers resulting from surplus coal capacity in the southern Powder River
Basin. In 1994, the Rosebud Mine sold approximately 2,000,000 tons of coal
under contracts with two Midwestern customers. One of the contracts, totaling
approximately 1,000,000 tons per year, was not renewed in December 1994. The
second contract, also totaling approximately 1,000,000 tons per year, will
expire in December 1995, and is not expected to be renewed. This customer is
expected to purchase approximately 1,000,000 tons during 1995. Revenues from
the Rosebud Mine in 1995 will be reduced by approximately $11,500,000 due to
the loss of the first Midwestern contract and revenues will be reduced in 1996
by another $16,800,000 due to the anticipated loss of the second Midwestern
contract. In addition, due to the anticipated loss of the Corette Plant
supply contract resulting from air quality concerns in Billings, Montana,
revenues may be reduced by $3,900,000 in 1996.
Expenses:
Cost of sales increased $15,000,000 at the Golden Eagle Mine due to
increased volumes sold and higher costs per ton including those related to
unanticipated production problems in both the mining and the wash plant
operations. Also, cost of sales increased $2,000,000 at the Rosebud Mine as a
result of increased volumes sold. Selling, general and administrative
expenses increased $4,500,000 from legal fees incurred relating to coal
contract price arbitration and leasehold interest litigation, from the
implementation of an accounting pronouncement pertaining to postemployment
benefits and from the use of outside consultants. Taxes other than income
taxes increased $3,500,000 due to increased coal revenues. Depreciation and
depletion increased $2,400,000 principally due to increased volumes sold and
increased investment in the operation at the Golden Eagle Mine.
Operating expenses at the Rosebud Mine in 1995 will decrease by
approximately $9,600,000 and may decrease in 1996 by another $12,300,000 due
to the anticipated loss of the contracts mentioned above.
Since the Company acquired the Golden Eagle Mine in 1991, it has
incurred losses of approximately $7,800,000, $4,300,000 and $5,500,000 in
1994, 1993 and 1992, respectively. The Company entered into a long-term
contract to supply up to 1,200,000 tons annually starting in July 1994. With
these sales added to spot sales of approximately 500,000 tons, losses were
expected to end. However, unanticipated problems have caused production costs
to be higher than expected. Capital of $1,100,000 was expended in 1994, and
an additional $6,800,000 is budgeted in 1995 to resolve these mining and wash
plant problems. Management expects to see improved results in 1995.
1993 Compared to 1992
Income from coal operations decreased $5,100,000 due to decreased coal
volumes sold.
Revenues:
Overall coal revenues, including intersegment revenues, decreased
$9,300,000 from 1992 due to a 7% decrease in volumes sold. Prices per ton
were substantially unchanged. Coal revenues at the Rosebud Mine decreased
$21,000,000 due to lower volumes sold to the Colstrip units as a result of
unscheduled outages and from fewer spot sales to Midwestern customers. This
revenue decrease was partially offset by an increase of $4,400,000 from a
combination of higher brokered coal revenues, increased fees related to
operating the SynCoal demonstration plant and offset by increased losses from
a joint venture. At the Jewett Mine, coal revenues increased by $11,400,000
due to higher volumes sold to the mine-mouth power plants, offset by an
$8,000,000 decrease from lower reimbursable mining expenses. Higher volumes
sold to supply coal for test burns and spot market sales resulted in increased
revenues of $4,000,000 at the Golden Eagle Mine.
Expenses:
Selling, general and administrative expense increased from the
implementation of Statement of Financial Accounting Standards No. 106,
"Employer's Accounting for Postretirement Benefits Other Than Pensions" and
from a non-recurring workers' compensation refund received in 1992. Taxes
other than income taxes decreased as a result of lower coal revenues at the
Rosebud Mine. The decrease in depreciation and depletion results primarily
from lower coal production at the Rosebud Mine.
Oil and Natural Gas Operations:
The following table shows year-to-year changes for the previous two
years, in millions of dollars, in the various classifications of revenues
including intersegment revenues, with the related percentage changes in
volumes sold and prices received:
1994 1993
Oil -revenue $ (7) $ (5)
-volume (19%) (10%)
-price/bbl (11%) (6%)
Natural gas -revenue $ - $ 9
-volume 7% 16%
-price/Mcf (4%) 20%
Natural gas marketing -revenue $ (9) $ 19
1994 Compared to 1993
Income from oil and natural gas operations increased $1,900,000 due to
higher profit margins realized on the natural gas marketing activity.
Revenues:
Oil revenues decreased $7,000,000 from both lower volumes sold due to
natural declining production and lower market prices received. Natural gas
revenues in Canada increased $3,500,000 from higher volumes sold as a result
of 1993 development drilling and from higher market prices received. However,
natural gas revenues in the U.S. decreased $3,900,000 from lower market prices
received. Natural gas marketing revenues decreased $12,000,000 due to the
expiration of a short-term supply contract in 1993. The operating revenue
decrease was partially offset by the absence of losses of $3,200,000 as a
result of a marketing joint venture that was sold in December 1993.
Expenses:
Cost of sales decreased $17,000,000. This amount is comprised of
$14,700,000 decreased costs of natural gas purchased for resale because of
lower spot market prices and decreased natural gas marketing volumes sold in
the U.S., and $2,300,000 decreased operating costs resulting from the sale of
a non-strategic asset in the fourth quarter of 1993. The decrease of $900,000
in taxes other than income taxes reflects lower revenues.
1993 Compared to 1992
Income from oil and natural gas operations decreased $2,200,000 due to
losses from a natural gas marketing joint venture.
Revenues:
Oil revenues decreased primarily from lower volumes sold as a result of
natural declining production and from lower market prices received in both
Canada and the U.S. Natural gas revenues increased principally from higher
market prices received and higher volumes sold as a result of development
drilling in both Canada and the U.S. The increase in natural gas marketing
revenues reflects a combination of escalated prices received under three
cogeneration supply contracts, and higher volumes sold partially offset by
losses from a joint venture.
Expenses:
Natural gas for resale increased $23,100,000 and costs from increased
production of natural gas increased $1,400,000. Taxes other than income taxes
increased as a result of higher natural gas revenues.
Other Operations:
1994 Compared to 1993
Income from other operations increased $700,000 due to expanded
telecommunications services.
Revenues:
Revenues from Entech's other operations decreased $3,500,000 because of
the sale of the waste management operations in May 1993. This decrease was
offset by $3,000,000 increased revenues from telecommunications operations due
to increased services provided to common carriers and expanded operations in
three western states, and by $500,000 increased revenues from land sales.
Expenses:
The operating expenses of Entech's other operations decreased $3,600,000
due to the sale of the waste management operations mentioned above. This
decrease was substantially offset by $2,900,000 increased costs of
telecommunications operations and land sales.
1993 Compared to 1992
Income from other operations increased $400,000 due to expanded
telecommunications services.
Revenues:
Revenues from Entech's other operations decreased $5,200,000 as a net
result of the sale of the waste management operations in May 1993, offset by
higher telecommunications revenues resulting from expansion of services into
three Northwestern states plus increased contractual services provided to
common carriers, and an increase in joint ventures income.
Expenses:
Cost of sales decreased from the combination of a $1,900,000 increase
from telecommunications services offset by a $4,500,000 decrease as a result
of the sale of the waste management operations. The decrease in selling,
general and administrative expense was also a result of the sale of the waste
management operation.
Interest Expense and Other Income, and Income Taxes:
1994 Compared to 1993
The decrease in interest expense is due to lower levels of outstanding
debt. The $7,800,000 decrease in other (income) deductions - net resulted
from the 1993 sales of a non-strategic asset and the waste management
operations.
Income taxes decreased $3,700,000 due to income tax credits utilized and
lower pre-tax net income.
<PAGE>
1993 Compared to 1992
Other (income) deductions - net increased approximately $5,200,000 from
the net effect of several events. Profits from asset sales increased
$2,200,000 and deductions decreased $3,000,000 reflecting a 1992 payment to
settle a lawsuit, and joint ventures income increased $1,100,000. These
increases were offset by $1,100,000 less income received from the Brazilian
subsidiary in 1993.
<PAGE>
<TABLE>
<CAPTION>
INDEPENDENT POWER GROUP OPERATIONS
Year Ended December 31
1994 1993 1992
Thousands of Dollars
<S> <C> <C> <C>
REVENUES
Revenues . . . . . . . . . . . . . . . . . . . $ 93,647 $ 119,189 $ 93,053
Earnings from unconsolidated investments . . . 2,080 3,117 1,839
Intersegment revenues. . . . . . . . . . . . . 1,461 5,528 2,552
97,188 127,834 97,444
EXPENSES
Operation and maintenance. . . . . . . . . . . 75,080 114,923 84,573
Selling, general and administrative. . . . . . 4,088 9,605 3,900
Taxes other than income taxes. . . . . . . . . 1,916 1,767 1,744
Depreciation and amortization. . . . . . . . . 3,112 2,887 2,720
84,196 129,182 92,937
INCOME (LOSS) FROM OPERATIONS. . . . . . . . . 12,992 (1,348) 4,507
INTEREST EXPENSE AND OTHER INCOME
Interest . . . . . . . . . . . . . . . . . . . 22 211 47
Other (income) deductions - net. . . . . . . . (4,711) (1,011) (1,539)
(4,689) (800) (1,492)
INCOME BEFORE INCOME TAXES . . . . . . . . . . . 17,681 (548) 5,999
INCOME TAXES . . . . . . . . . . . . . . . . . . 7,386 (507) 2,234
IPG NET INCOME . . . . . . . . . . . . . . . . . $ 10,295 $ (41) $ 3,765
</TABLE>
<PAGE>
Independent Power Group Operations:
In November 1992, the IPG acquired 100% of North American Energy
Services Company (NAES) and their operations were included in the Company's
financial statements on a consolidated basis throughout the remainder of 1992
and 1993. In August 1994, the IPG sold a 50% interest in NAES and, as a
result of the sale, NAES has been included in the Company's operations on the
equity basis of accounting as of January 1, 1994.
1994 Compared to 1993
Income from IPG operations increased $14,300,000 primarily due to
increased revenues from independent power project development activity, a gain
on the sale of NAES and improved performance by the Colstrip generating units.
Earnings from development activities in 1995 are not expected to maintain the
1994 levels.
Revenues:
IPG revenues decreased $43,600,000 due to the accounting change for the
IPG's investment in NAES as mentioned above. The decrease was partially
offset by increases in independent power project development revenues of
$12,600,000, management fees of $500,000 and a $4,900,000 increase in revenues
from long-term power sales from the Colstrip units due to a 13% increase in
volumes sold.
The decrease in earnings from unconsolidated investments results
primarily from lower earnings from operating projects. The decrease in
intersegment revenues results primarily from the sale of NAES and the
resulting change in accounting.
Expenses:
The NAES sale and corresponding accounting change resulted in decreases
of $41,500,000 in operation and maintenance expense and $5,300,000 in selling,
general and administrative. Operation and maintenance expense was also
impacted by a $2,100,000 decrease in wheeling expense, a $2,100,000 decrease
in purchased power costs and a $3,000,000 increase in fuel costs due to
increased generation at the Colstrip units. Expenses associated with project
development increased by $1,600,000 primarily due to the development of two
power projects.
Interest Expense and Other Income:
Other (income) deductions - net increased $3,700,000 due principally to
increases in interest income and the gain on the sale of 50% of NAES.
1993 Compared to 1992
Income from IPG operations decreased $5,800,000 primarily due to
decreased revenues from independent power project development activity and
reduced generation from the Colstrip generating units due to outages.
Revenues:
Total IPG revenues increased $30,400,000. The acquisition of NAES
resulted in increased revenues of $39,300,000 and income from investments in
independent power projects increased $1,300,000. The increases were partially
offset by a $6,000,000 reduction in independent power project development
revenues and a $3,800,000 decrease resulting from a change in the amount of
amortization of the loss on long-term sales.
A $3,800,000 increase in intersegment revenues resulting from the
acquisition mentioned previously was partially offset by a $900,000 decrease
in sales from the Colstrip generating units.
Expenses:
IPG operation and maintenance expense increased $30,000,000 primarily as
a result of a $34,400,000 increase resulting from the acquisition of NAES
mentioned above and a $3,000,000 increase in purchased power costs resulting
from outages at a Colstrip generating unit. The increases were offset by
a $3,500,000 reduction in fuel expense resulting from the Colstrip outages and
a $3,000,000 decrease in independent power project development expenses.
Selling, general and administrative expense rose primarily due to a
$4,200,000 increase resulting from the acquisition mentioned previously and a
$1,000,000 increase due to the accrual of Colstrip housing damage claims.
<PAGE>
Liquidity and Capital Resources:
Net cash provided by operating activities was $203,886,000 in 1994
compared to $185,809,000 in 1993 and $227,988,000 in 1992. Cash from
operating activities less dividends paid provided 54% of capital expenditures
in 1994, 54% in 1993 and 91% in 1992.
The Company's long-term debt as a percentage of capitalization was 36%,
36% and 39% in 1994, 1993 and 1992, respectively. The Company also has
entered into long-term lease arrangements and other long-term contracts for
sales and purchases that are not reflected on its balance sheet. See Item 8,
"Financial Statements and Supplementary Data - Note 3 to the Consolidated
Financial Statements" for additional information.
Capital expenditures during the prior three years are as follows:
Years Utility Entech IPG Total
Thousands of Dollars
1992 $ 96,352 $ 44,662 $ 19,489 $ 160,503
1993 112,178 66,832 4,542 183,552
1994 150,903 50,253 6,154 207,310
The following table sets forth the Company's estimated capital
expenditures for the years 1995-1999:
Years Utility Entech IPG Total
Thousands of Dollars
1995 $128,000 $ 81,000 $ 27,000 $ 236,000
1996 158,000 98,000 31,000 287,000
1997 161,000 78,000 25,000 264,000
1998 134,000 70,000 29,000 233,000
1999 135,000 114,000 26,000 275,000
In addition, $153,677,000 of long-term debt will mature during the years
1995-1999. See Item 8, "Financial Statements and Supplementary Data - Note 7
to the Consolidated Financial Statements" for details on maturities of long-
term debt.
For the years 1995-1999, the Company estimates that approximately 61% of
its utility construction program, 81% of Entech capital expenditures and 37%
of IPG investments will be financed from funds generated internally and that
the balance, as well as the repayment of maturing long-term debt, will be
financed through the incurrence of short- and long-term debt and the sales of
equity securities, the timing and amounts of which will depend upon future
market conditions. The Company anticipates that it will have adequate sources
of external capital to meet its financing needs.
Dividends on common and preferred stock increased to $92,009,000 in 1994
from $85,823,000 in 1993 and $82,343,000 in 1992. The Company paid dividends
of $1.60 per share of outstanding common stock during 1994, up 1.27% from
1993. In an effort to move toward the Company's target payout ratio for
dividends of 70% of earnings, the Board of Directors voted in December to
continue the regular quarterly dividend at 40 cents per share of common stock,
$1.60 on an annual basis.
The Company and Entech have Revolving Credit and Term Loan Agreements in
the amount of $60,000,000 and $75,000,000, respectively. These businesses
also have short-term borrowing facilities with commercial banks that provide
both committed and uncommitted lines of credit, and the ability to sell
commercial paper. See Item 8, "Financial Statements and Supplementary Data -
Notes 7 and 8 to the Consolidated Financial Statements."
In January 1994, the Company sold $5,000,000 of Secured Medium-Term
Notes, 7.25% series due 2024. The proceeds were used to repay short-term debt
incurred to complete the refinancing of $80,000,000 of the 10% and 10-1/8%
series Pollution Control Revenue Bonds in December 1993.
In June 1994, the Company sold $20,000,000 of Secured Medium-Term Notes,
7.2% series due 2000, the proceeds of which were used to retire other long-
term debt.
In November 1994, the Company sold $10,000,000 of Secured Medium-Term
Notes, 7.6% series due 1997 and $10,000,000 of Secured Medium-Term Notes,
7.85% series due 1998, the proceeds of which were used to retire three series
of unsecured Medium-Term Notes, $9,000,000 of the 8.78% series due November
1994, $5,000,000 of the 8.57% series due December 1994 and $5,000,000 of the
8.78% series due December 1994.
The Company's Mortgage and Deed of Trust contains certain restrictions
upon the issuance of additional First Mortgage Bonds. At December 31, 1994,
the unfunded net property additions and retired bonds test, which is the most
restrictive test, would have permitted the issuance of approximately
$514,000,000 additional First Mortgage Bonds. There are no restrictions upon
issuance of short-term debt or preferred stock in the Company's Restated
Articles of Incorporation, its Mortgage and Deed of Trust or its Sinking Fund
Debenture Agreement.
SEC Ratio of Earnings to Fixed Charges:
For the twelve months ended December 31, 1994, the Company's ratio of
earnings to fixed charges was 3.05 times. Fixed charges include interest, the
implicit interest of Unit 4 rentals and one-third of all other rental
payments.
<PAGE>
Inflation:
Capital intensive businesses, such as the Company's electric and natural
gas utility operations, are significantly and adversely affected by long-term
inflation as neither depreciation nor the ratemaking process reflect the
replacement cost of utility plant. Although prices for natural gas may
fluctuate, earnings of the Gas Utility are not impacted because a gas cost
tracking procedure annually balances gas costs collected from customers with
the costs of supplying gas.
Entech's long-term coal contracts and the IPG's long-term power sales
contracts provide for the adjustment of prices either through indices, fixed
escalations and/or direct pass-through of costs.
The Company believes that the effects of inflation, at currently
anticipated levels, will not significantly affect results of operations.
Environmental Issues:
The Company is committed to do its part to protect and maintain the
environment. A management function is in place which monitors compliance and
keeps management informed regarding the status of compliance.
The Clean Air Act Amendments of 1990 should have no major effects on the
Company's electric generation facilities. The Company's coal-fired generating
plants meet the 1995 Phase I requirements of the Act. Low-sulfur coal and
state-of-the-art scrubbers already result in sulfur dioxide emissions from
the Colstrip units well below the new requirements. Either fuel switching or
the use of allowances, or both, would permit the Corette Plant to meet the
Phase II requirements of the Act in 2000. The Company has agreed to a new
State Implementation Plan required by the Federal Environmental Protection
Agency to reduce sulfur dioxide emissions in Billings, Montana. Under the
Plan, the Company will reduce its emissions at the Corette Plant from an
average of 7,800 tons in 1987-93 to less than 5,000 tons annually. This
reduction is expected to be obtained by changing the Plant's fuel to
low-sulphur, compliance coal.
Modifications will be required at three units in the late 1990's to meet
the nitrogen oxide emission standards of the Act. Phase II rules implementing
the Act are subject to legal appeal, challenging their adoption. The Company,
therefore, does not yet know what requirements may result from the Phase II
Rules. Consequently, the capital costs associated with the modifications to
meet the nitrogen oxide standards of the Act have not yet been determined.
However, capital improvements that may be required are expected to be
recovered through rates, and therefore, the costs are not expected to have a
material impact on earnings.
In 1988, the United States Environmental Protection Agency advised the
Company that it, along with certain other parties, is a potentially
responsible party (PRP) for the release of certain toxic substances which have
come to rest behind the dam at the Company's Milltown Hydroelectric Plant.
Because of federal legislation specifically relating to Milltown, the Company
believes it has no responsibility for any of the alleged releases. If the
Company should have some responsibility, it would have to share, together with
other responsible parties, the costs related to the handling of these toxic
substances. While these costs have not been determined, the Company believes
that any portion which it might bear would not have a significant impact upon
its earnings.
The Company, along with others, has been named a PRP with respect to the
Silver Bow Creek/Butte Area Superfund Site. The alleged contamination is soil
and groundwater contamination, for the most part, associated with decades of
copper mining in the area. The PRPs have cooperated to summarize the data
that currently exists, to evaluate the useability of this existing data and to
determine additional data needs. Studies to determine the extent of the
alleged contamination, and a proposal for removal or remediation of the
alleged contamination are not complete.
Regarding this superfund site, the Company has focused on its property
ownership and alleged contamination that may be attributed to that ownership.
It has spent approximately $650,000 to investigate its property within the
site, collect data, evaluate studies and monitor its property. Costs to clean
up this contamination, including sums spent in the studies mentioned above,
are not expected to exceed $1,000,000.
Other contamination at the Company's property within the site involves
heavy metals and substances which may be attributed to mining and activities
of others within the greater area of the site. Consultants employed by the
PRPs to compile and analyze previously prepared study data regarding the
greater area of this superfund site have made preliminary estimates indicating
that clean-up costs could range from $20,000,000 to $60,000,000. While the
Company denies any responsibility for costs associated with this
contamination, if the Company should have some responsibility, it would have
to share a portion of the costs ultimately related to the handling of the
contamination.
The Company was also a PRP at another site of soil contamination in
Montana, alleged to have resulted from the salvage of electric transformers by
a third party or parties who obtained the transformers from the Company. The
Company completed clean-up work at this site in 1994 and has received
acceptance of the clean-up from the state agency with jurisdiction over this
site. Costs incurred by the Company were approximately $610,000.
The Company is a PRP at two sites in the State of Washington where
electric transformers were sent for salvage. At one of the sites, the Company
is an extremely small contributor and liability will be de minimis. At the
second site, pursuant to the terms of a Consent Decree, the Company has paid
approximately $360,000. Clean-up at this site is near completion.
Mercury has been used in measurement devices used to measure natural gas
production at the Company's properties. The Company has gathered information
regarding mercury content in the surrounding wellhead sites and, with the
appropriate state agency, is preparing a response strategy. Preliminary
estimates indicate the Company may incur costs ranging from $250,000 to
$750,000 to clean approximately 120 sites.
A subsidiary of the Company operating oil and gas properties in Canada
has notified regulatory authorities with jurisdiction over environmental
matters of potential contamination that may have been caused by a leaking
condensate tank. Contamination is contained at the site of the plant where
the tank was situated and estimated clean-up costs are $250,000 in Canadian
dollars. The Company's subsidiary owns 60% of the facility.
The Company has accrued the estimated minimum costs associated with
these matters. The Company does not expect these costs to materially impact
the results of its operations.
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA
Page
Management's Responsibility for Financial Statements 50
Report of Independent Accountants 51
Consolidated Financial Statements:
Consolidated Statements of Income for the Years Ended
December 31, 1994, 1993 and 1992 52
Consolidated Balance Sheets as of December 31, 1994 and 1993 53-54
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1994, 1993 and 1992 55
Consolidated Statements of Common Shareholders' Equity for the
Years Ended December 31, 1994, 1993 and 1992 56
Notes to Consolidated Financial Statements 57-83
Supplementary Data (Unaudited) 84-92
Financial Statement Schedules for the Years Ended December 31,
1994, 1993 and 1992:
Schedule VIII - Valuation and Qualifying Accounts and Reserves 97
Financial statement schedules not included in this Form 10-K Annual Report
have been omitted because they are not applicable or the required information
is shown in the Consolidated Financial Statements or notes thereto.
<PAGE>
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS
The management of The Montana Power Company is responsible for the
preparation and integrity of the consolidated financial statements of the
Corporation. These financial statements have been prepared in accordance with
generally accepted accounting principles which are consistently applied, and
appropriate in the circumstances. In preparing the financial statements,
management makes appropriate estimates and judgements based upon available
information. Management also prepared the other financial information in the
annual report and is responsible for its accuracy and consistency with the
financial statements.
Management maintains systems of internal accounting control which are
adequate to provide reasonable assurance that the financial statements are
accurate, in all material respects. The concept of reasonable assurance
recognizes that there are inherent limitations in all systems of internal
control in that the costs of such systems should not exceed the benefits to be
derived. Management believes the Company's systems provide this appropriate
balance.
The Company maintains an internal audit function that independently
assesses the effectiveness of the systems and recommends possible
improvements. Price Waterhouse LLP, the Company's independent public
accountants, also considered the systems in connection with its audit.
Management has considered the internal auditors' and Price Waterhouse LLP's
recommendations concerning the systems and has taken cost-effective actions to
respond appropriately to these recommendations.
The Board of Directors, acting through an Audit Committee composed
entirely of directors who are not employees of the Company, is responsible for
determining that management fulfills its responsibilities in the preparation
of the financial statements. The Audit Committee recommends, and the Board of
Directors appoints, the independent public accountants. The independent
accountants and internal auditors are assured of full and free access to the
Audit Committee and meet with it to discuss their audit work, the Company's
internal controls, financial reporting and other matters. The Committee is
also responsible for determining that there is adherence to the Company's Code
of Business Conduct (Code). The Code addresses, among other things, potential
conflicts of interests and compliance with laws, including those relating to
financial disclosure and the confidentiality of proprietary information.
The financial statements have been examined by Price Waterhouse LLP,
which is responsible for conducting its examination in accordance with
generally accepted auditing standards.
/s/ Daniel T. Berube /s/ J. P. Pederson
Daniel T. Berube J. P. Pederson
Chairman of the Board and Vice President and
Chief Executive Officer Chief Financial Officer
<PAGE>
Report of Independent Accountants
To the Board of Directors
and Shareholders of
The Montana Power Company
In our opinion, the consolidated financial statements listed in the
accompanying index present fairly, in all material respects, the financial
position of The Montana Power Company and its subsidiaries at December 31,
1994 and 1993, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1994, in conformity
with generally accepted accounting principles. These financial statements are
the responsibility of the Company's management; our responsibility is to
express an opinion on these financial statements based on our audits. We
conducted our audits of these statements in accordance with generally accepted
auditing standards which require that we plan and perform the audits 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, assessing
the accounting principles used and significant estimates made by management,
and evaluating the overall financial statement presentation. We believe that
our audits provide a reasonable basis for the opinion expressed above.
As discussed in Note 2 to the consolidated financial statements, the
Company is party to a long-term supply contract price dispute subject to
arbitration. The outcome of the arbitration is final and binding on all
parties to the contract retroactive to August 1, 1991. The ultimate outcome
of the arbitration cannot be determined at present. No provision for any
liability that may result upon completion of arbitration has been made in the
accompanying consolidated financial statements.
As discussed in Note 9 to the consolidated financial statements, the
Company changed its method of accounting for postretirement benefits other
than pensions in 1993.
PRICE WATERHOUSE LLP
Portland, Oregon
February 10, 1995<PAGE>
CONSOLIDATED STATEMENT OF INCOME
The Montana Power Company and Subsidiaries
<TABLE>
<CAPTION>
Year Ended December 31
1994 1993 1992
Thousands of Dollars
<S> <C> <C> <C>
REVENUES. . . . . . . . . . . . . . . . . . . $1,005,970 $1,024,285 $ 943,872
EXPENSES:
Operations. . . . . . . . . . . . . . . . . 440,472 480,382 416,072
Maintenance . . . . . . . . . . . . . . . . 75,357 70,029 70,525
Selling, general and administrative . . . . 103,524 101,286 87,545
Taxes other than income taxes . . . . . . . 99,200 92,430 94,328
Depreciation, depletion and amortization. . 86,314 82,661 81,732
804,867 826,788 750,202
INCOME FROM OPERATIONS . . . . . . . . . 201,103 197,497 193,670
INTEREST EXPENSE AND OTHER INCOME:
Interest. . . . . . . . . . . . . . . . . . 46,102 50,739 50,682
Other (income) deductions - net . . . . . . (13,817) (14,573) (9,716)
32,285 36,166 40,966
INCOME TAXES. . . . . . . . . . . . . . . . . 55,226 54,120 45,639
NET INCOME. . . . . . . . . . . . . . . . . . 113,592 107,211 107,065
DIVIDENDS ON PREFERRED STOCK. . . . . . . . . 7,227 4,353 3,790
NET INCOME AVAILABLE FOR COMMON STOCK . . . . $ 106,365 $ 102,858 $ 103,275
AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING (000) . . . . . . . . . . . . . 53,125 52,040 51,126
NET INCOME PER SHARE OF COMMON STOCK. . . . . $ 2.00 $ 1.98 $ 2.02
The accompanying notes are an integral part of these statements.
</TABLE>
<PAGE>
CONSOLIDATED BALANCE SHEET
The Montana Power Company and Subsidiaries
ASSETS
<TABLE>
<CAPTION>
December 31
1994 1993
Thousands of Dollars
<S> <C> <C>
PLANT AND PROPERTY IN SERVICE:
Utility plant (includes $79,510 and $38,966 plant
under construction):
Electric . . . . . . . . . . . . . . . . . . . . . $ 1,608,615 $ 1,514,472
Natural gas. . . . . . . . . . . . . . . . . . . . 463,134 428,956
2,071,749 1,943,428
Less - accumulated depreciation and depletion . . . . . 619,195 572,141
1,452,554 1,371,287
Entech property (includes $3,030 and $2,446
property under construction) . . . . . . . . . . . . 530,167 526,692
Less - accumulated depreciation and depletion . . . . . 189,926 182,129
340,241 344,563
Independent Power Group property (includes $671
and $84 property under construction) . . . . . . . . 70,253 70,198
Less - accumulated depreciation . . . . . . . . . . . . 17,560 16,822
52,693 53,376
1,845,488 1,769,226
MISCELLANEOUS INVESTMENTS (at cost):
Independent power investments. . . . . . . . . . . . 54,397 45,493
Other. . . . . . . . . . . . . . . . . . . . . . . . 49,713 51,492
104,110 96,985
CURRENT ASSETS:
Cash and temporary cash investments. . . . . . . . . 21,564 11,604
Accounts receivable. . . . . . . . . . . . . . . . . 159,975 158,352
Materials and supplies (principally at
average cost). . . . . . . . . . . . . . . . . . . 47,937 42,728
Prepayments and other assets . . . . . . . . . . . . 65,154 57,182
294,630 269,866
DEFERRED CHARGES:
Advanced coal royalties. . . . . . . . . . . . . . . 22,939 20,905
Regulatory assets related to income taxes. . . . . . 146,844 143,447
Regulatory assets - other. . . . . . . . . . . . . . 49,880 36,695
Other deferred charges . . . . . . . . . . . . . . . 48,806 48,903
268,469 249,950
$ 2,512,697 $ 2,386,027
The accompanying notes are an integral part of these statements.
<PAGE>
LIABILITIES
December 31
1994 1993
Thousands of Dollars
CAPITALIZATION:
Common shareholders' equity:
Common stock (120,000,000 shares without par
value authorized; 53,578,737 and 52,498,896
shares issued) . . . . . . . . . . . . . . . . . . $ 667,344 $ 642,926
Retained earnings and other shareholders' equity . . 320,756 302,725
Unallocated stock held by trustee for Deferred
Savings and Employee Stock Ownership Plan. . . . . (32,580) (34,419)
955,520 911,232
Preferred stock . . . . . . . . . . . . . . . . . . . . 101,416 101,419
Long-term debt. . . . . . . . . . . . . . . . . . . . . 588,876 571,870
1,645,812 1,584,521
CURRENT LIABILITIES:
Short-term borrowing. . . . . . . . . . . . . . . . . . 113,989 68,865
Long-term debt-portion due within one year. . . . . . . 16,980 26,199
Dividends payable . . . . . . . . . . . . . . . . . . . 23,249 22,835
Income taxes. . . . . . . . . . . . . . . . . . . . . . 9,210 4,927
Other taxes . . . . . . . . . . . . . . . . . . . . . . 46,521 43,743
Accounts payable. . . . . . . . . . . . . . . . . . . . 50,788 55,794
Interest accrued. . . . . . . . . . . . . . . . . . . . 11,785 11,942
Other current liabilities . . . . . . . . . . . . . . . 40,546 53,918
313,068 288,223
DEFERRED CREDITS:
Deferred income taxes . . . . . . . . . . . . . . . . . 322,835 309,780
Investment tax credit . . . . . . . . . . . . . . . . . 48,729 50,476
Accrued mining reclamation costs. . . . . . . . . . . . 110,035 101,817
Other deferred credits. . . . . . . . . . . . . . . . . 72,218 51,210
553,817 513,283
CONTINGENCIES AND COMMITMENTS (Notes 2 and 3)
$ 2,512,697 $ 2,386,027
The accompanying notes are an integral part of these statements.
</TABLE>
<PAGE>
CONSOLIDATED STATEMENT OF CASH FLOWS
The Montana Power Company and Subsidiaries
<TABLE>
<CAPTION>
Year Ended December 31
1994 1993 1992
Thousands of Dollars
<S> <C> <C> <C>
Net Cash Flows From Operating Activities:
Net income. . . . . . . . . . . . . . . . . . $ 113,592 $ 107,211 $ 107,065
Noncash charges (credits) to net income:
Depreciation, depletion and amortization. . 86,314 82,661 81,732
Mining reclamation costs expensed . . . . . 19,527 19,410 21,081
Amortization of loss on long-term
sales of power. . . . . . . . . . . . . . (4,226) (5,251) (9,026)
Deferred income taxes . . . . . . . . . . . 5,432 15,701 (4,082)
Collection of accrued revenues from
utility rate-moderation plans . . . . . . 16,221
Other-net . . . . . . . . . . . . . . . . . 31,204 16,834 24,522
Changes in other assets and liabilities . . . (24,810) (31,856) 4,968
Accounts receivable . . . . . . . . . . . . . (1,622) (15,367) (4,614)
Materials and supplies. . . . . . . . . . . . (5,209) (975) (694)
Accounts payable. . . . . . . . . . . . . . . (5,007) 6,922 2,387
Payment of mining reclamation costs . . . . . (11,309) (9,481) (11,572)
Net Cash Flows From Operating
Activities. . . . . . . . . . . . . . . . 203,886 185,809 227,988
Net Cash Flows From Investing Activities:
Gross additions to property and plant . . . . (200,966) (177,512) (138,778)
Investments in other operations . . . . . . . (6,344) (6,040) (21,725)
Sales of property . . . . . . . . . . . . . . 27,729 24,924 12,282
Additional investments. . . . . . . . . . . . 1,143 4,014 (255)
Net Cash Flows From Investing
Activities. . . . . . . . . . . . . . . . (178,438) (154,614) (148,476)
Net Cash Flows From Financing Activities:
Sales of common stock . . . . . . . . . . . . 24,380 24,917 21,949
Issuance of long-term debt. . . . . . . . . . 52,094 294,149 37,862
Retirement of long-term debt. . . . . . . . . (45,078) (316,714) (58,755)
Short-term debt . . . . . . . . . . . . . . . 45,125 5,565 6,000
Dividends on common and preferred stock . . . (92,009) (85,822) (82,343)
Issuance of preferred stock . . . . . . . . . 49,435
Net Cash Flows From Financing
Activities. . . . . . . . . . . . . . . . (15,488) (28,470) (75,287)
Change in Cash Flows. . . . . . . . . . . 9,960 2,725 4,225
Cash and cash equivalents at beginning
of year . . . . . . . . . . . . . . . . . . 11,604 8,879 4,654
Cash and cash equivalents at end of year. . . $ 21,564 $ 11,604 $ 8,879
Supplemental Disclosures of Cash
Flow Information:
Cash Paid During Year For:
Income taxes. . . . . . . . . . . . . . . . $ 45,875 $ 46,533 $ 39,260
Interest. . . . . . . . . . . . . . . . . . 45,990 53,541 45,894
The accompanying notes are an integral part of these statements.
/TABLE
<PAGE>
CONSOLIDATED STATEMENT OF COMMON SHAREHOLDERS' EQUITY
The Montana Power Company and Subsidiaries
<TABLE>
<CAPTION>
Year Ended December 31
1994 1993 1992
Thousands of Dollars
<S> <C> <C> <C>
Common Stock:
Balance at beginning of year . . . . . . . . $ 642,926 $ 618,009 $ 596,060
Issuances (1,079,841; 949,951;
and 891,581 shares). . . . . . . . . . . 24,418 24,917 21,949
Balance at end of year . . . . . . . . . . . 667,344 642,926 618,009
Retained Earnings and Other Shareholders'
Equity:
Balance at beginning of year . . . . . . . . 302,725 284,980 266,541
Net income . . . . . . . . . . . . . . . . . 113,592 107,211 107,065
Dividends on common stock ($1.60;
$1.585; and $1.55 per share) . . . . . . (85,193) (82,701) (79,420)
Dividends on preferred stock . . . . . . . . (7,227) (4,353) (3,790)
Other . . . . . . . . . . . . . . . . . . (3,141) (2,412) (5,416)
Balance at end of year . . . . . . . . . . . 320,756 302,725 284,980
Unallocated Stock Held by Trustee for
Deferred Savings and Employee Stock
Ownership Plan:
Balance at beginning of year . . . . . . . . (34,419) (36,098) (37,631)
Distributions. . . . . . . . . . . . . . . . 1,839 1,679 1,533
Balance at end of year . . . . . . . . . . . (32,580) (34,419) (36,098)
Total Common Shareholders' Equity at
End of Year. . . . . . . . . . . . . . . . . $ 955,520 $ 911,232 $ 866,891
The accompanying notes are an integral part of these statements.
</TABLE>
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - Summary of significant accounting policies:
The Company's accounting policies conform to generally accepted
accounting principles. With respect to utility operations, such policies are
in accordance with the accounting requirements and ratemaking practices of the
regulatory authorities having jurisdiction.
Principles of consolidation:
The Consolidated Financial Statements include the accounts of the
Company and its subsidiaries, all of which are wholly-owned. The Independent
Power Group (IPG) includes the Company's Colstrip Unit 4 operations. All
material intercompany sales and purchases between the Utility, Entech and the
IPG have been eliminated from revenues and expenses in the Consolidated
Statement of Income. All other significant intercompany items have also been
eliminated. See Note 10 for details.
Plant and property:
Additions to and replacement of plant and property are recorded at
original cost, which includes material, labor, overhead and contracted
services. Cost includes interest capitalized and, with respect to utility
plant, also includes an allowance for funds used during construction. Gas in
underground storage is included in natural gas utility plant. Maintenance and
repairs of plant and property, and replacements and renewals of items
determined to be smaller than established units of plant, are charged to
operating expenses. The cost of units of utility plant retired or otherwise
disposed of, adjusted for removal costs and salvage, is charged to the
accumulated provision for depreciation and depletion, and the cost of related
replacements and renewals is added to utility plant. Gain or loss is
recognized upon the sale or other disposition of Entech property, Independent
Power Group property and Utility land.
Provisions for depreciation and depletion are recorded at amounts
substantially equivalent to calculations made on straight-line and
unit-of-production methods by application of various rates based on useful
lives of properties determined from engineering studies. The provisions for
utility depreciation and depletion approximated 2.7% for 1994, 1993, and 1992
of the depreciable and depletable utility plant at the beginning of the year.
The Company and its subsidiaries have adopted two methods of accounting
for oil and gas exploration and development costs. Entech's Oil Division uses
the successful efforts method. The regulated natural gas utility capitalizes
all costs associated with the successful development of a natural gas well and
expenses those costs incurred on an unsuccessful well.
The Company is a joint-owner of Colstrip Units 1, 2, and 3 and of
transmission facilities serving these Units. At December 31, 1994, the
Company's joint ownership percentage and investment in these Units and
transmission facilities were:
Units Transmission
1 & 2 Unit 3 Facilities
Thousands of Dollars
Ownership. . . . . . . . . . . . 50% 30% 30%*
Plant in service . . . . . . . . 180,725 280,791 50,046
Plant under construction . . . . 248 1,028 6
Accumulated depreciation . . . . 80,576 85,700 10,959
*This is an approximate ownership percentage. The ownership
percentages are generally based on capacity rights on the various
segments of the transmission system.
The Company also owns $36,321,000 and $33,024,000 of the Colstrip Unit 4
share of common production plant and transmission plant that had related
accumulated depreciation of $11,755,000 and $5,786,000, respectively.
Each joint-owner provides its own financing. The Company's share of
direct expenses associated with the operation and maintenance of these joint
facilities is included in the corresponding operating expenses in the
Consolidated Statement of Income.
Utility revenue and expense recognition:
Operating revenues are recorded on the basis of service rendered. Costs
of service are recognized on the accrual basis and charged to expense
currently except for natural gas costs deferred pursuant to PSC-approved
deferred gas accounting procedures and other costs deferred pursuant to
regulatory decisions which are discussed in the following paragraph of this
note.
In 1985, the Public Service Commission of Montana (PSC) approved an
annual electric rate increase in the amount of $80,400,000 to be collected in
accordance with a rate-moderation plan. During 1992, cash collected under
this plan exceeded revenues recorded by $12,462,000. As of October 1992, all
deferred revenues under the plan had been collected.
Regulatory assets:
In the ratemaking process, tax costs and benefits related to certain
temporary differences are recovered in rates on an as paid or "flow-through"
basis. Financial Accounting Standards No. 109 "Accounting for Income Taxes,"
(SFAS No. 109) requires that tax assets and liabilities be reflected on the
Balance Sheet on an accrual basis. This timing difference requires the
Company to recognize a regulatory asset for taxes accrued but not yet
recovered in rates. That regulatory asset was $146,844,000 and $143,447,000
as of December 31, 1994 and 1993 respectively.
Included in other regulatory assets are costs related to the Company's
Demand Side Management (DSM) programs in the amounts of $27,521,000 and
$17,987,000 for 1994 and 1993, respectively. The amounts are included in the
Company's rate base and are being charged to income over a ten-year period.
Certain other costs have also been deferred pursuant to PSC orders of which
significant amounts will also be charged to income within the next ten years.
Cash and cash equivalents:
For the purposes of these financial statements, the Company considers all
liquid investments with original maturities of three months or less to be cash
equivalents.
Allowance for funds used during construction:
The Company capitalizes, as a part of the cost of utility plant, an
allowance for the cost of equity and borrowed funds required to finance
construction work in progress. The rate used to compute the allowance is
determined in accordance with a formula established by the FERC and was an
average of 7.9% for 1994, 6.5% for 1993, and 7.3% for 1992. The Company
capitalized an allowance for borrowed funds used during construction of
$2,405,000, $1,372,000, and $1,255,000 for 1994, 1993, and 1992, respectively.
Allowance for funds used for conservation expenditures:
The Company has been allowed by the PSC to capitalize, as part of its
conservation expenditures, an allowance for the cost of equity and borrowed
funds required to finance Demand Side Management expenditures. The rate used
to capitalize the allowance is the Company's overall rate of return allowed by
the PSC. The Company capitalized an allowance for borrowed funds used to
finance DSM expenditures of $635,000, $561,000 and $290,000 for 1994, 1993 and
1992, respectively.
Income taxes:
The Company and its U.S. subsidiaries file a consolidated U.S. income tax
return. Consolidated U.S. income taxes are allocated to Utility, Entech, and
IPG operations as if separate U.S. income tax returns were filed. Deferred
income taxes are provided for the temporary differences between the financial
reporting basis and the tax basis of the Company's assets and liabilities.
For further information on income taxes see "Regulatory Assets" in this note
and also Note 4 - "Income Taxes."
Net income per share of common stock:
Net income per share of common stock is computed for each year based upon
the weighted average number of common shares outstanding. The effect of
options outstanding under the Company's Long-Term Incentive Plan is not
significant (see Note 5).
Financial instruments:
In October 1994, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 119, "Disclosure about
Derivative Financial Instruments and Fair Value of Financial Instruments,"
effective for fiscal years ending after December 15, 1994. This statement
requires disclosure about derivative financial instruments - futures,
forwards, swap and option contracts, and other financial instruments with
similar characteristics.
Entech uses derivative financial instruments to manage the price risk
associated with its oil and natural gas operations. Entech is authorized to
use swaps, collars and options (caps and floors) as approved by a committee of
its officers, to hedge up to 75% of its estimated production of oil and
natural gas. At December 31, 1994, Entech held no derivative financial
instruments.
The Independent Power Group (IPG) has investments in independent power
partnerships, some of which have entered into derivative financial instruments
to hedge against interest rate exposure on floating rate debt and foreign
currency and gas price fluctuations.
Statement of Financial Accounting Standards No. 107, "Disclosure About
Fair Value of Financial Instruments," requires disclosure of the fair value of
certain financial instruments. The estimated fair value amounts have been
determined by the Company using available market information and appropriate
valuation methodologies. However, considerable judgement is required in
interpreting market data to develop the estimates of fair value. Accordingly,
the estimates presented herein are not necessarily indicative of the amounts
that the Company could realize in a current market exchange. The use of
different market assumptions and/or estimation methodologies could result in
different estimated fair value amounts.
Cash and temporary cash investments, accounts receivable, current assets,
short-term borrowings, accounts payable and accrued liabilities are reflected
in the financial statements at fair value because of the short-term maturity
of these instruments.
The carrying amounts and estimated fair value of the Company's other
significant financial instruments at December 31, 1994 are as follows:
Estimated
Carrying Fair
Amount Value
Thousands of Dollars
Assets:
Independent Power Investments. . . . . . $ 9,566 $ 5,482
Other Investments. . . . . . . . . . . . 31,690 31,875
Liabilities:
Long-Term Debt . . . . . . . . . . . . . $ 585,157 $ 544,639
The following methods and assumptions were used to estimate fair value:
Independent Power Investments - The fair value represents the Company's
assessment of the present value of net future cash flows embodied in these
investments, discounted to reflect current market rates of return. This
represents only those investments accounted for on the cost basis. The
investments accounted for on the equity basis are not presented.
Other Investments - The carrying value of most of the investments
approximates fair value as the investments have short maturities or the
carrying value equals their cash surrender value. Other investments' fair
value was estimated based on the discounted value of the future cash flows
expected to be received using a rate of return expected on similar current
investments.
Long-Term Debt - The fair value was estimated using quoted market rates
for the same or similar instruments. Where quotes were not available the fair
value was estimated using the Company's year-end incremental borrowing rate.
Reclassifications:
Certain reclassifications have been made to the prior year amounts to
make them comparable to the 1994 presentation. These changes had no impact on
previously reported results of operations or shareholders' equity.
<PAGE>
NOTE 2 - Contingencies:
The Company's hydroelectric projects are operated under licenses issued
by the FERC, which expire on varying dates from 1995 to 2035. When a license
expires, it may be reissued to the Company, issued to a new licensee or the
facility may be taken over by the United States. In either of the last two
events, the Company would be entitled to compensation equivalent to its net
investment in the project plus severance damages. In determining net
investment in the project, the licenses provide that there may be deducted the
amount contained in an appropriated retained earnings account, which shall be
accumulated from a portion of the amount earned in excess of a specified
reasonable rate of return after 20 years of operation under the license. At
December 31, 1994, the amount of these appropriated retained earnings relating
to the Company's hydroelectric projects as computed by the Company is
estimated to be $6,238,000. The Board of Directors has appropriated retained
earnings in the same amount for this purpose, thereby restricting their
availability for dividend purposes.
Under a joint 50-year license with the Confederated Salish and Kootenai
Tribes (Tribes), the Company will own and operate the 180 megawatt Kerr
Hydroelectric project until September 2015. The Tribes may take over the
project anytime between 2015 and 2025 on one year's written notice in return
for payment equal to the Company's remaining net investment. The Company pays
the Tribes an annual rental fee that is adjusted yearly to reflect changes in
the Consumer Price Index.
In 1990, the Company filed with the FERC a plan (the Plan), prepared
pursuant to the joint license issued by the FERC to the Company and the
Tribes, to mitigate damages to, and to manage fish and wildlife habitat
impacted by the operation of the Kerr Hydroelectric Project. The Plan
provides for a one-time payment by the Company of $15,418,000 and annual
payments of $965,000 which would be adjusted annually to reflect the effects
of inflation and which are to be allocated between the Tribes and various
groups.
As part of its review of the Plan, FERC is preparing a draft
environmental impact statement which is expected to suggest modifications to
the Plan. In addition, the Department of Interior, pursuant to its authority
under the Federal Power Act, has proposed certain conditions, requiring
changes in the operation of the project, as well as non-operational measures
which would be funded by an initial payment, annual payments based on a
calculation of the Project's value as a base-load facility and further capital
investments.
While it cannot predict when or in what form the Plan finally will be
approved, the Company expects that the cost of mitigation measures will be
recovered through rates or from the Tribes if they exercise their right to
take over the project and will not have a materially adverse effect on the
Company's financial condition or results of operations.
In November 1992, the Company filed with FERC its application to
relicense nine Madison and Missouri River hydroelectric facilities with
electric generating capacity totaling 292 megawatts. The application, in
preparation since 1989, proposes an additional 74 megawatts of generation.
The total capital investment of relicensing, including physical improvements,
environmental protection, mitigation and enhancement measures, is estimated at
$173,000,000. Additional costs for operational changes, as well as annual
payments for environmental protection, mitigation and enhancement, are
estimated to be about $5,400,000 per year. The Company expects that the
relicensing costs will be recovered through rates and, therefore, will not
have a materially adverse effect on the Company's financial condition or
results of operations.
The coal supply agreement for Colstrip Units 1 and 2 between Puget Sound
Power & Light Company (Puget) and the Company's Utility Division, as co-owners
of the units, and Western Energy Company, as coal supplier, provides for
periodic price redeterminations over the life of the contract, commencing in
1991. Negotiations with respect to the 1991 redetermination were unsuccessful
and an arbitration proceeding was held in January 1995. A decision is
expected in late March 1995. Based upon the positions of the parties, the
estimated effect on pretax net income at December 31, 1994 would range from an
increase of approximately $4,000,000 to a decrease of approximately
$12,000,000 on coal sold to Puget and, in addition, an increase of
approximately $2,000,000 to a decrease of $12,000,000 on coal sold to the
Company's Utility Division. The Company believes Western presented a
convincing position in the arbitration. Further, the Company believes because
its electric rates have been adjusted by a coal cost disallowance, they should
not be subject to further adjustment. The Company, however, cannot predict
the outcome of the arbitration nor any related rate proceeding.
<PAGE>
NOTE 3 - Commitments:
The Company purchases approximately 600 million kWh annually under an
Exchange Agreement with the Washington Public Power Supply System and the
Bonneville Power Administration which expires in 1996. The rate is 4.7 cents
per kWh in the contract year which began in July 1994 and will increase to
approximately 4.8 cents per kWh in the final contract year beginning July
1995. In 1993, the Company entered into a contract to purchase 98 megawatts
of seasonal capacity from Basin Electric Power Cooperative beginning in 1996.
Based upon projected deliveries, the rate, including the capacity charge, will
be approximately 3.3 cents per kWh in the contract year beginning in November
1996 and will increase each subsequent year to approximately 7.1 cents per kWh
in the final contract year which begins in November 2009.
The Company also has long-term purchase contracts with certain
independent power producers and natural gas producers. The purchased power
contracts provide for capacity payments subject to a facility meeting certain
operating standards, and payments based on energy received. The purchased gas
contracts provide for take-or-pay payments. The Entech Oil Division has
various natural gas transportation contracts with terms that expire beginning
in 1998.
Total payments under these contracts for the prior three years were as
follows:
Thousands of Dollars
Years Electric Natural Gas Entech
1992. . . . . . . $ 18,143 $ 12,496 $ 1,938
1993. . . . . . . 18,434 11,633 2,260
1994. . . . . . . 19,242 11,072 2,993
The present value of future minimum payments, at an assumed discount
rate of 8%, under the above agreements are estimated as follows:
Thousands of Dollars
Years Electric Natural Gas Entech
1995. . . . . . . $ 4,609 $ 9,032 $ 2,411
1996. . . . . . . 8,169 7,001 1,889
1997. . . . . . . 11,143 5,810 1,727
1998. . . . . . . 11,109 2,907 1,598
1999. . . . . . . 10,916 2,450 1,406
Remainder. . . .. 151,979 6,156 6,643
Total . . . . . $ 197,925 $ 33,356 $ 15,674
In 1993, the Company entered into contracts for the construction of a
second powerhouse at the Thompson Falls Hydroelectric Plant. Expenditures for
the project to date have been $28,300,000, while the total costs for the next
two years are expected to be $20,600,000.
An Entech Coal Division coal lease purchase agreement requires minimum
annual payments, beginning in 1991 in the amount of $1,125,000 escalated
quarterly by the Gross National Product implicit price deflator. The payments
will continue until the equivalent of $18,750,000, in 1986 dollars, has been
paid. At December 31, 1994, the remaining payments under this agreement were
$13,991,000. A similar agreement requires minimum annual payments of
$1,000,000 through 1995. Under current mine plans, these payments should be
recovered through coal sales.
In 1990, a patented coal enhancement process developed by the Entech
Coal Division was selected for funding under the U.S. Department of
Energy (DOE) Clean Coal Technology Program. The Coal Division and a
subsidiary of Northern States Power are partners in a five-year, $69,000,000
coal enhancement demonstration project at Colstrip, Montana. DOE is funding
50% and the partners share equally in the remaining 50% of the cost of the
project. The Division's remaining commitment at December 31, 1994, was
$2,809,000.
The Entech Oil Division has agreed to supply approximately
138,000 Mmcf of natural gas to four cogeneration facilities over 10 to
16 years. The Oil Division has proven, developed and undeveloped reserves
sufficient to supply all of the remaining natural gas required by these
agreements.
Rental expense for the prior three years was as follows:
1994 1993 1992
Thousands of Dollars
Colstrip Unit 4. . . . $ 32,226 $ 32,226 $ 32,226
Kerr project . . . . . 12,172 11,837 11,486
Other. . . . . . . . . 12,530 11,917 11,985
$ 56,928 $ 55,980 $ 55,697
In addition, operating expenses include delay rentals paid by the Company
to retain mineral rights before development of leased acreage. Delay rentals
were $1,015,000, $1,021,000, and $999,000 in 1994, 1993, and 1992,
respectively.
Leases:
The Company classifies leases as operating or capitalized leases.
Capitalized leases are not material and are included in other long-term debt.
On December 30, 1985, the Company sold its 30% share of Colstrip Unit 4 and is
leasing back this share under a net lease. The transaction has been accounted
for as an operating lease with semiannual lease payments of approximately
$16,113,000 over the remaining term of the 25-year lease.
At December 31, 1994, the Company's future minimum operating lease
payments are as follows:
Thousands of
Year Dollars
1995. . . . . . . . . . . . . . $ 35,265
1996. . . . . . . . . . . . . . 34,317
1997. . . . . . . . . . . . . . 34,022
1998. . . . . . . . . . . . . . 33,831
1999. . . . . . . . . . . . . . 33,781
Remainder . . . . . . . . . . . 356,260
Total . . . . . . . . . . . $ 527,476
<PAGE>
NOTE 4 - Income tax expense:
Income before income taxes for the years ended December 31, 1994, 1993
and 1992 was as follows:
1994 1993 1992
Thousands of Dollars
United States. . . . . . . . . . . . . $ 155,978 $ 150,290 $ 143,298
Canada . . . . . . . . . . . . . . . . 9,144 8,791 6,047
Brazil . . . . . . . . . . . . . . . . 3,696 2,250 3,359
$ 168,818 $ 161,331 $ 152,704
The provision for income taxes differs from the amount of income tax
determined by applying the applicable U.S. statutory federal income tax rate
to pretax income as a result of the following differences:
1994 1993 1992
Thousands of Dollars
Computed "expected" income tax expense . . $ 59,086 $ 56,466 $ 51,919
Adjustments for tax effects of:
Statutory depletion in
coal mining operations . . . . . . . (4,983) (3,775) (5,920)
General business and nonconventional
fuel tax credits . . . . . . . . . . (5,130) (4,496) (3,723)
State income tax, net . . . . . . . . . 4,772 4,704 3,332
Reversal of excess of U.S. utility
income tax depreciation over
financial accounting
depreciation on utility plant
additions. . . . . . . . . . . . . . 3,236 2,281 1,987
Other . . . . . . . . . . . . . . . . . (1,755) (1,060) (1,956)
Actual income tax expense. . . . . . . . . $ 55,226 $ 54,120 $ 45,639
<PAGE>
Income tax expense as shown in the Consolidated Statement of Income
consists of the following components:
1994 1993 1992
Thousands of Dollars
Current
United States. . . . . . . . . . . . $ 38,519 $ 31,039 $ 38,252
Canada . . . . . . . . . . . . . . . 3,093 3,235 3,162
Brazil . . . . . . . . . . . . . . . 1,080
State. . . . . . . . . . . . . . . . 7,742 3,522 8,307
50,434 37,796 49,721
Deferred
United States. . . . . . . . . . . . 4,426 13,664 (2,646)
Canada . . . . . . . . . . . . . . . 850 374 (200)
State. . . . . . . . . . . . . . . . (484) 2,286 (1,236)
4,792 16,324 (4,082)
$ 55,226 $ 54,120 $ 45,639
Deferred tax liabilities (assets) are comprised of the following at
December 31:
1994 1993
Thousands of Dollars
Plant Related. . . . . . . . . . . . . . . . . . . $ 379,401 $ 372,236
Investment in nonutility generation projects . . . 21,752 16,370
Other. . . . . . . . . . . . . . . . . . . . . . . 21,309 16,260
Gross deferred tax liabilities . . . . . . . . . . 422,462 404,866
Coal reclamation . . . . . . . . . . . . . . . . . (40,509) (37,321)
Amortization of gain on sale/leaseback . . . . . . (17,026) (18,090)
Investment tax credit amortization . . . . . . . . (31,665) (32,801)
Other. . . . . . . . . . . . . . . . . . . . . . . (20,392) (14,937)
Gross deferred tax assets. . . . . . . . . . . . . (109,592) (103,149)
Net deferred tax liabilities (assets). . . . . . . 312,870 301,717
Plus current deferred tax assets-net . . . . . . . 9,965 8,063
Total noncurrent deferred tax liabilities
(assets) . . . . . . . . . . . . . . . . . . . . $ 322,835 $ 309,780
The change in net deferred liabilities differs from current year
deferred tax expense as a result of the following:
Thousands of
Dollars
Increase (decrease) in total noncurrent deferred tax
liabilities (assets) . . . . . . . . . . . . . . . . $ 13,055
Regulatory assets related to income taxes. . . . . . . (3,397)
Current deferred tax asset-net . . . . . . . . . . . . (1,902)
Amortization of investment tax credits . . . . . . . . (1,748)
Other. . . . . . . . . . . . . . . . . . . . . . . . . (1,216)
Deferred tax expense . . . . . . . . . . . . . . . . $ 4,792
<PAGE>
NOTE 5 - Common stock:
At December 31, 1994 and 1993, the Company had 120,000,000 shares of
authorized common stock. The Company has a Shareholder Protection Rights Plan
which provides one preferred share purchase right (Right) on each outstanding
common share of the Company. Each Right entitles the registered holder, upon
the occurrence of certain events, to purchase from the Company one
one-hundredth of a share of Participating Preferred Shares, A Series, without
par value. If it should become exercisable, each Right would have economic
terms similar to one share of common stock of the Company. The Rights trade
with the underlying shares and will, except under certain circumstances
described in the Plan, expire on June 6, 1999, unless earlier redeemed or
exchanged by the Company.
The Company's Dividend Reinvestment and Stock Purchase Plan allows
owners of common and preferred stock, as well as Montana utility customers, to
reinvest the dividends paid on their common and preferred stock to purchase
shares of common stock. Participants in the plan may also elect to invest by
purchasing up to $15,000 per quarter of common stock.
The Company has a Deferred Savings and Employee Stock Ownership
Plan (Plan) that covers all regular eligible employees. The Company, on
behalf of the employee, contributes a percentage of the amount contributed to
the Plan by the employee. In 1990, the Company borrowed $40,000,000 at an
interest rate of 9.2% to be repaid in equal annual installments over 15 years.
The proceeds of the loan were lent on similar terms to the Plan Trustee, which
purchased 1,922,297 shares of Company common stock. The loan, which is
reflected as long-term debt, is offset by a similar amount in common
shareholders' equity as unallocated stock. Company contributions plus the
dividends on the shares held under the Plan are used to meet principal and
interest payments on the loan. Shares acquired with loan proceeds are
allocated to Plan participants. As principal payments on the loans are made,
long-term debt and the offset in common shareholders' equity are both reduced.
At December 31, 1994, 610,379 shares had been allocated to the participants'
accounts.
Expense for the Plan is recognized using the Shares Allocated Method,
and consists of the following for the three years ended December 31, 1994:
1994 1993 1992
Thousands of Dollars
Principal allocated.................... $ 2,663 $ 2,663 $ 2,663
Interest incurred...................... 3,114 3,275 3,422
Dividends.............................. (3,046) (3,028) (3,014)
Additional contribution................ 2,952 2,310 1,766
Total Expense..................... $ 5,683 $ 5,220 $ 4,837
The Company's amount of Plan costs funded, which currently is less than
the aforementioned expense amounts, is included in utility rates.
Accordingly, the difference of $968,000, $758,000 and $694,000 for the years
ending December 31, 1994, 1993 and 1992, respectively, were recorded as a
reduction of Plan expense.
Under the Long-Term Incentive Plan, options have been issued to Company
employees. Options issued to Utility employees are not reflected in balance
sheet accounts until exercised, at which time (i) authorized, but unissued
shares are issued to the employee, (ii) the capital stock account is credited
with the proceeds, and (iii) no charges or credits to income are made.
Options issued to Entech and IPG employees are not reflected in balance sheet
accounts. Rather, upon exercise, outstanding shares are purchased at current
market prices and compensation expense is charged with the excess of the
market price over the option price.
Option activity is summarized below.
Number Option Price
Of Shares Per Share
Outstanding
December 31, 1991 657,447 $11.4375 - 26.50
Granted -
Exercised (116,905) 11.4375 - 22.125
Cancelled (4,457) 11.4375 - 22.125
Outstanding
December 31, 1992 536,085 $14.25 - 26.50
Granted -
Exercised (118,243) 14.25 - 26.50
Cancelled (5,532) 14.25 - 26.50
Outstanding
December 31, 1993 412,310 $14.25 - 26.50
Granted 117,100 22.625 - 25.625
Exercised (43,884) 14.25 - 26.50
Cancelled (4,540) 14.25 - 26.50
Outstanding
December 31, 1994 480,986 $17.25 - 26.50
Options Exercisable at
December 31, 1994 480,986
Options were granted at 100% of the closing price on the New York Stock
Exchange on the date granted, and expire ten years from that date. Options
granted prior to January 1, 1987 must be exercised in the order granted.
In 1994, 64,235 restricted stock awards were issued to certain Entech
employees under the Long-Term Incentive Plan. Upon the achievement of
performance and passage of time constraints, restrictions will be lifted and
participants will retain, at no cost, the unrestricted shares. As they are
earned, the awards are reflected as common stock and compensation expense on
the Balance Sheet and Income Statement, respectively.
<PAGE>
NOTE 6 - Preferred stock:
The number of authorized shares of preferred stock is 5,000,000. No
dividends may be declared or paid on common stock while cumulative dividends
have not either been declared and set apart or paid on any of the preferred
stock.
Preferred stock, as shown in the Consolidated Balance Sheet, is in four
series as detailed in the following table:
Shares Amount
Issued and Thousands of
Series Outstanding Dollars
$6.875 500,000 $ 50,000
6.00 159,589 15,959
4.20 60,000 6,025
2.15 1,200,000 30,000
1,919,589 $ 101,984
The stated value and liquidation price of preferred shares is $100 for
the $6.875 series, the $6.00 series and the $4.20 series and $25 for the
$2.15 series, plus accumulated dividends. The preferred stock is redeemable
at the option of the Company upon the written consent or affirmative vote of
the holders of a majority of the common shares on thirty days notice at
$110 per share for the $6.00 series, $103 per share for the $4.20 series and
$25.25 per share for the $2.15 series, plus accumulated dividends. The $6.875
series is redeemable in whole or in part, at anytime on or after November 1,
2003 for a price beginning at $103.438 per share with annual decrements
through the year 2013, after which the redemption price is $100 per share. At
the annual meeting of shareholders in May 1994, shareholders approved a
proposal permitting the redemption of the $2.15 series.
<PAGE>
NOTE 7 - Long-term debt:
Long-term debt consists of the following:
December 31
1994 1993
Thousands of Dollars
First Mortgage Bonds:
7.7% series, due 1999...................... $ 55,000 $ 55,000
7 1/2% series, due 2001.................... 25,000 25,000
7% series, due 2005........................ 50,000 50,000
8 1/4% series, due 2007.................... 55,000 55,000
8.95% series, due 2022..................... 50,000 50,000
Secured Medium-Term Notes.................. 88,000 43,000
Pollution Control Revenue Bonds:
City of Forsyth, Montana
6 1/8% series, due 2023.............. 90,205 90,205
5.9% series, due 2023................ 80,000 80,000
Sinking Fund Debentures:
7 1/2%, due 1998........................... 17,000 17,500
ESOP Notes Payable, due 2004................... 31,943 33,850
Unsecured Medium-Term Notes, Series A.......... 48,250 67,250
Long-Term Commercial Paper..................... 20,000
Other.......................................... 19,847 15,144
Unamortized Discount and Premium.......... (4,389) (3,880)
605,856 598,069
Less: Portion due within one year............. 16,980 26,199
$ 588,876 $ 571,870
First Mortgage Bonds:
The Company's Mortgage and Deed of Trust imposes a first mortgage lien
on all physical properties owned, exclusive of subsidiary company assets, and
certain property and assets specifically excepted. The obligations
collateralized are First Mortgage Bonds, including those First Mortgage Bonds
securing Pollution Control Revenue Bonds set forth above, in the aggregate
principal amount of $493,205,000 at December 31, 1994.
<PAGE>
Secured Medium-Term Notes:
At December 31, 1994 and 1993, the Company had outstanding $88,000,000
and $43,000,000 principal amount of Secured Medium-Term Notes, respectively,
maturing from 3 to 30 years with interest rates varying between 7.20% and
8.11%.
In January 1994, the Company sold $5,000,000 of Secured Medium-Term
Notes, 7.25% series due 2024. The proceeds were used to repay short-term debt
incurred to complete the refinancing of $80,000,000 of the 10% and 10-1/8%
series Pollution Control Revenue Bonds in December 1993.
In June 1994, the Company sold $20,000,000 of Secured Medium-Term Notes,
7.2% series due 2000, the proceeds of which were used to retire other long-
term debt.
In November 1994, the Company sold $10,000,000 of Secured Medium-Term
Notes, 7.6% series due 1997 and $10,000,000 of Secured Medium-Term Notes,
7.85% series due 1998, the proceeds of which were used to retire three series
of unsecured Medium-Term Notes, $9,000,000 of the 8.78% series due November
1994, $5,000,000 of the 8.57% series due December 1994 and $5,000,000 of the
8.78% series due December 1994.
ESOP Notes Payable:
In 1990, the Company borrowed $40,000,000 at an interest rate of 9.2% in
a 15-year loan to be repaid in equal annual installments. The proceeds of the
loan were used to purchase shares of the Company's stock to pre-fund a portion
of the Company's matching requirements under the Deferred Savings and Employee
Stock Ownership Plan. See Note 5 for further information.
Unsecured Medium-Term Notes, Series A:
At December 31, 1994 and 1993, the Company had outstanding $48,250,000
and $67,250,000 principal amount of Medium-Term Notes, respectively, maturing
from 1 to 28 years with interest rates varying between 8.68% and 8.90%.
During 1994 the following Medium-Term Notes matured; on November 15,
1994, $9,000,000 of the 8.78% series due 1994, on December 15, 1994,
$5,000,000 of the 8.57% series due 1994, on December 20, 1994, $5,000,000 of
the 8.78% series due 1994. As previously mentioned, the Company retired these
notes with the proceeds from the sale of Secured Medium-Term Notes.
Revolving Credit Agreements:
The Company has a Revolving Credit and Term Loan Agreement that allows
it to borrow up to $60,000,000, all of which was unused at December 31, 1994.
Under the agreement, borrowings outstanding at October 31, 1995, must be
repaid in eight quarterly installments beginning in January 1996.
Entech has a Revolving Credit and Term Loan Agreement with a group of
banks that allows it to borrow up to $75,000,000, all of which was unused at
December 31, 1994. Under the agreement, borrowings outstanding at
September 30, 1997 must be repaid at maturity.
Fixed or variable interest rate options are available under the
facilities, with commitment fees on the unused portions.
During the period 1995 through 1999, the Company is required to make the
following maturity and sinking fund payments on long-term debt:
1995 1996 1997 1998 1999
Thousands of Dollars
7.7% First Mortgage Bonds.. $ 55,000
Secured Medium-Term Notes.. $ 10,000 $ 10,000
7 1/2% Sinking Fund
Debentures............... $ 500 $ 500 500 15,500
ESOP Notes Payable......... 2,082 2,274 2,483 2,712 2,961
Unsecured Medium-Term
Notes.................... 10,000 8,750 7,500 2,500 2,500
Other...................... 4,398 12,613 303 301 300
$ 16,980 $ 24,137 $ 20,786 $ 31,013 $ 60,761
<PAGE>
NOTE 8 - Short-term borrowing:
The Company is currently authorized by the PSC to incur short-term debt
not to exceed $150,000,000. The Company and Entech have short-term borrowing
facilities with commercial banks that provide both committed, as well as
uncommitted, lines of credit, and the ability to sell commercial paper. Bank
borrowings either bear interest at the lender's floating base rate and may be
repaid at any time, or have fixed rates of interest and maturities.
Commercial paper has fixed rates of interest and maturities.
At December 31, 1994, the Company had lines of credit consisting of
$65,000,000 committed and $75,400,000 uncommitted, and Entech had lines of
credit consisting of $15,000,000 committed and $25,000,000 uncommitted. There
is a commitment fee on the unused portion of some of these facilities which is
not significant. The Company has the ability, subject to the previously
mentioned PSC limitation, to issue up to $125,000,000 of commercial paper and
Entech up to $50,000,000 of commercial paper based on the total of unused
committed lines of credit and revolving credit agreements.
At December 31, 1994 and 1993, the Company's and Entech's short-term
borrowing included the following:
1994 1993
Thousands of Dollars
Notes payable to banks
MPC.......................... $ 90,000 $ 43,900
Entech....................... 14,000 8,000
Commercial paper
Entech....................... 9,989 16,965
$ 113,989 $ 68,865
<PAGE>
NOTE 9 - Retirement plans:
The Company maintains trusteed, noncontributory retirement plans
covering substantially all employees. Retirement benefits are based on
salary, years of service and social security integration levels.
In 1994 and 1993, pension costs funded were less than SFAS No. 87
pension expense by $2,770,000 and $1,887,000, respectively and the difference
was recorded as a reduction of unearned revenue. The amount of utility
pension costs funded are included in rates. In 1992, pension costs funded
exceeded SFAS No. 87 pension expense by $969,000 and the differences were
recorded as unearned revenue. At December 31, 1994, the cumulative amount by
which SFAS No. 87 pension expense exceeded pension costs funded was
$1,408,000.
The assets of the plans consist primarily of domestic and foreign
corporate stocks, domestic corporate bonds and U.S. Government securities.
The Company also has an unfunded, nonqualified benefit plan for senior
management executives and directors that provides for defined benefit payments
upon retirement over the life of the participant or to their beneficiary for a
minimum fifteen-year period. Life insurance payable to the Company is carried
on plan participants as an investment. Utility nonqualified benefit plan
expense is not included in rates.
Net pension and benefit expense includes the following components:
1994 1993 1992
Thousands of Dollars
Service cost benefits earned during
the period.......................... $ 8,442 $ 6,746 $ 5,287
Interest cost on projected benefit
obligation.......................... 13,430 12,077 9,978
Actual return market value of assets.. (13,051) (18,701) (12,688)
Net amortization and deferral......... 3,788 10,891 4,642
Total net periodic pension and
benefit expense................... $ 12,609 $ 11,013 $ 7,219
<PAGE>
The funded status of the pension and benefit plans is as follows:
December 31
1994 1993
Thousands of Dollars
Actuarial present value of accumulated plan
benefits
Vested...................................... $ 119,298 $ 120,550
Nonvested................................... 13,066 10,861
Accumulated benefit obligation.................. 132,364 131,411
Effect of projected future compensation levels.. 40,474 62,278
Projected benefit obligation.................... 172,838 193,689
Plan assets at fair value....................... 153,916 150,913
Plan assets less than projected
benefit obligation............................ (18,922) (42,776)
Unrecognized net loss (gain) from past
experience different from that assumed and
effects of changes in assumptions............. (9,402) 16,675
Prior service cost not yet recognized in net
periodic pension expense...................... 11,498 14,567
Unrecognized initial obligation................. 3,261 3,703
Prepaid (Accrued) benefits expense............ $ (13,565) $ (7,831)
The following assumptions were used in the determination of actuarial
present values of the projected benefit obligations:
December 31
1994 1993
Assumed discount rates:
Active service and vested terminations........ 8.25% 7.00%
Retired employees............................. 8.25% 7.00%
Long-term rate of average compensation increase. 4.25%-5.20% 4.90%-5.45%
Long-term rate on plan assets................... 8.50% 8.50%
<PAGE>
In addition to providing pension benefits, the Company and its
subsidiaries provide certain health care and life insurance benefits for
eligible retired employees. Until 1993, the cost of retiree health care and
life insurance benefits was recognized as expense on a pay-as-you-go (cash)
basis. The cost of these benefits in 1993 and 1992 was $1,387,000 and
$1,267,000, respectively.
In 1994, the Company established a pre-funding plan for postretirement
benefits for utility employees retiring after January 1, 1993. Funding costs
for the plan for 1994 were $1,487,000. The assets of the plan consist
primarily of domestic and foreign corporate stocks, domestic corporate bonds
and U.S. Government securities.
The Company adopted SFAS No. 106 effective January 1, 1993.
SFAS No. 106 requires accrual of the expected cost of these postretirement
benefits during the employees' years of service rather than when the costs are
paid.
In accordance with an Accounting Order issued by the PSC in 1992, the
Company recorded as a deferred expense $600,000 and $2,100,000 representing
the increased costs in 1994 and 1993, respectively, from adopting SFAS No. 106
for the Utility Division. In its April 28, 1994 Order, the PSC allowed the
Company to include in rates the full OPEB cost on the accrual basis provided
by SFAS No. 106, including the amortization of the amounts previously deferred
under a PSC Accounting Order from January 1, 1993 to April 27, 1994.
Consequently, as of April 28, 1994, the Company commenced recognition of these
utility postretirement benefits in expense in accordance with SFAS No. 106.
The incremental increase in 1994 consolidated expenses due to the utility SFAS
No. 106 expense recognition was approximately $1,500,000.
The cost of SFAS No. 106 adoption for the years ended December 31, 1994
and 1993, portions of which have been deferred or capitalized, includes the
following components:
December 31
1994 1993
Thousands of Dollars
Service cost on benefits earned
during the year. . . . . . . . . . . . . $ 1,455 $ 1,356
Interest cost on projected benefit
obligation . . . . . . . . . . . . . . . 2,323 2,296
Actual return market value of assets. . . . (38)
Amortization of transition obligation . . . 1,535 1,492
Total postretirement benefit cost . . . . . $ 5,275 $ 5,144
<PAGE>
The funded status of the postretirement benefit plans other than pensions is
as follows:
December 31
1994 1993
Thousands of Dollars
Accumulated benefit obligation:
Fully eligible active employees . . . . . . $ 2,253 $ 1,920
Other active employees. . . . . . . . . . . 19,857 20,195
Retirees. . . . . . . . . . . . . . . . . . 8,751 12,298
Accumulated benefit obligation. . . . . . . 30,861 34,413
Plan assets at fair value . . . . . . . . . . 1,479 0
Plan assets less than projected
benefit obligation. . . . . . . . . . . . . (29,382) (34,413)
Unrecognized net transition obligation. . . . 25,560 27,519
Unrecognized net loss (gain) from past
experience different from that
assumed and effects of changes
in assumptions. . . . . . . . . . . . . . . (2,417) 3,113
Prepaid (Accrued) benefits expense. . . . . . $ (6,239) $ (3,781)
The assumed 1994 health care cost trend rates used to measure the
expected cost of benefits covered by the plans are 8.75% and 11% for the
utility and non-utility operations, respectively. The utility trend rate
decreases through 2002 to 6%. The nonutility trend rate decreases through
2004 to 5%. The trend rates are for pre-65 benefits since most of the plans
provide a fixed dollar annual benefit for retirees over age 65. One Entech
subsidiary's plan used a trend rate of 9% decreasing through 2003 to an
ultimate rate of 5% for post-65 benefits. The effect of a 1% increase in each
future year's assumed health care cost trend rates increases the service and
interest cost from $3,800,000 to $4,200,000 and the accumulated postretirement
benefit obligation from $29,400,000 to $32,300,000.
On January 1, 1994, the Company adopted Statement of Financial
Accounting Standards No. 112, "Employers' Accounting for Postemployment
Benefits," (SFAS No. 112) with respect to disability related benefits up to
age 65. SFAS No. 112 requires the accrual of a liability or loss contingency
for the estimated obligation for postemployment benefits. At December 31,
1993, the postemployment benefit liability for regulated utility operations
was estimated to be $9,300,000, of which $2,400,000 had been accrued and
included in rates. The remaining $6,900,000 was recorded in 1994 as a
deferred charge and will be expensed and included in rates over the next ten
years. The estimated December 31, 1993 postemployment benefit liability of
$1,300,000 for non-utility operations has been charged to income in 1994. The
Company is no longer self-insured for disability-related benefits resulting
from claims occurring after December 31, 1993. Therefore, SFAS No. 112 will
not apply to benefits after that date, except workman's compensation claims
which are accrued and recovered in rates as previously discussed.
<PAGE>
NOTE 10 - Information on industry segments:
The Company's principal business includes regulated utility operations
involving the generation, purchase, transmission and distribution of
electricity and the production, purchase, transportation and distribution of
natural gas. The Company, through Entech, engages in nonutility operations
principally involving the mining and sale of coal, exploration for, and the
development, production, processing and sale of oil and natural gas and the
sale of telecommunication equipment and services. The Company, through its
Independent Power Group (IPG), manages long-term power sales, develops and
invests in independent power projects, and other energy-related businesses.
Substantially all of the natural gas produced by the Company's Canadian
utility operations has been sold to the Company's United States utility
operations.
Pre-tax operating income for the Utility, Entech, and IPG segments
represents revenues excluding earnings from unconsolidated investments less
all costs and expenses except interest and other (income) deductions-net.
Immaterial intersegment sales are not disclosed.
Identifiable assets of each industry segment are those assets used in
the Company's operations in such industry segments. Corporate assets are
principally miscellaneous special funds, cash and temporary cash investments,
other investments and unallocable property. The assets of the Company's
Canadian operations were $79,337,000, $80,553,000 and $84,202,000 at
December 31, 1994, 1993 and 1992, respectively.
<PAGE>
Operations Information:
<TABLE>
<CAPTION>
Year Ended
December 31, 1994
Thousands of Dollars
UTILITY Electric Natural Gas
<S> <C> <C>
Sales to unaffiliated customers. . . . . . . $ 427,686 $ 107,105
Intersegment sales . . . . . . . . . . . . . 5,924 917
Pre-tax operating income . . . . . . . . . . 98,070 29,576
Earnings from unconsolidated investments . .
Depreciation, depletion, and amortization. . 40,699 9,445
Capital expenditures . . . . . . . . . . . . 108,933 41,969
Identifiable assets. . . . . . . . . . . . . 1,414,673 373,427
<CAPTION>
Oil and
ENTECH Coal* Natural Gas Other
<S> <C> <C> <C>
Sales to unaffiliated customers. . . . . . $ 255,247 $ 97,994 $ 24,096
Intersegment sales . . . . . . . . . . . . 42,201 254 787
Pre-tax operating income . . . . . . . . . 48,344 13,647 1,147
Earnings from unconsolidated investments . (2,740) 68
Depreciation, depletion and amortization . 12,649 18,464 1,945
Capital expenditures . . . . . . . . . . . 16,115 32,417 492
Identifiable assets. . . . . . . . . . . . 291,224 179,261 33,769
<CAPTION>
INDEPENDENT POWER GROUP
<S> <C>
Sales to unaffiliated customers. . . . . . . $ 93,647
Intersegment sales . . . . . . . . . . . . . 1,461
Pre-tax operating income . . . . . . . . . . 10,912
Earnings from unconsolidated investments . . 2,080
Depreciation, depletion, and amortization. . 3,112
Capital expenditures . . . . . . . . . . . . 6,154
Identifiable assets. . . . . . . . . . . . . 159,138
<CAPTION>
CORPORATE
<S> <C>
Sales to unaffiliated customers. . . . . . .
Intersegment sales . . . . . . . . . . . . .
Pre-tax operating income . . . . . . . . . .
Earnings from unconsolidated investments . .
Depreciation, depletion and amortization . .
Capital expenditures . . . . . . . . . . . . $ 1,231
Identifiable assets. . . . . . . . . . . . . 61,205
* Sales under one coal contract with Houston Light and Power Company amounted to
$101,845,000.
</TABLE>
<PAGE>
Operations Information:
<TABLE>
Year Ended
December 31, 1993
Thousands of Dollars
<CAPTION>
UTILITY Electric Natural Gas
<S> <C> <C>
Sales to unaffiliated customers. . . . . . . $ 426,746 $ 110,696
Intersegment sales . . . . . . . . . . . . . 7,532 778
Pre-tax operating income . . . . . . . . . . 112,530 30,942
Earnings from unconsolidated investments . .
Depreciation, depletion and amortization . . 39,151 8,971
Capital expenditures . . . . . . . . . . . . 83,308 28,871
Identifiable assets. . . . . . . . . . . . . 1,325,073 355,641
<CAPTION>
Oil and
ENTECH Coal* Natural Gas Other
<S> <C> <C> <C>
Sales to unaffiliated customers. . . . . . $ 227,285 $ 117,659 $ 24,429
Intersegment sales . . . . . . . . . . . . 39,637 741 700
Pre-tax operating income . . . . . . . . . 45,220 14,974 714
Earnings from unconsolidated investments . (2,130) (3,228) (177)
Depreciation, depletion, and amortization. 10,193 19,327 2,133
Capital expenditures . . . . . . . . . . . 26,253 38,547 1,875
Identifiable assets. . . . . . . . . . . . 276,158 169,310 36,374
<CAPTION>
INDEPENDENT POWER GROUP
<S> <C>
Sales to unaffiliated customers. . . . . . . $ 119,189
Intersegment sales . . . . . . . . . . . . . 5,528
Pre-tax operating income . . . . . . . . . . (4,465)
Earnings from unconsolidated investments . . 3,117
Depreciation, depletion and amortization . . 2,887
Capital expenditures . . . . . . . . . . . . 4,542
Identifiable assets. . . . . . . . . . . . . 163,550
<CAPTION>
CORPORATE
<S> <C>
Sales to unaffiliated customers. . . . . . .
Intersegment sales . . . . . . . . . . . . .
Pre-tax operating income . . . . . . . . . .
Earnings from unconsolidated investments . .
Depreciation, depletion, and amortization. .
Capital expenditures . . . . . . . . . . . . $ 156
Identifiable assets. . . . . . . . . . . . . 59,921
* Sales under one coal contract with Houston Light and Power Company amounted to
$98,569,000.
</TABLE> <PAGE>
Operations Information:
<TABLE>
Year Ended
December 31, 1992
Thousands of Dollars
<CAPTION>
UTILITY Electric Natural Gas
<S> <C> <C>
Sales to unaffiliated customers. . . . . . . $ 402,402 $ 97,485
Intersegment sales . . . . . . . . . . . . . 4,783 1,054
Pre-tax operating income . . . . . . . . . . 104,574 22,305
Earnings from unconsolidated investments . .
Depreciation, depletion and amortization . . 37,180 8,302
Capital expenditures . . . . . . . . . . . . 76,111 20,233
Identifiable assets. . . . . . . . . . . . . 1,267,634 337,256
<CAPTION>
Oil and
ENTECH Coal* Natural Gas Other
<S> <C> <C> <C>
Sales to unaffiliated customers. . . . . . $ 228,873 $ 90,252 $ 30,624
Intersegment sales . . . . . . . . . . . . 45,892 1,021 467
Pre-tax operating income . . . . . . . . . 48,892 13,220 1,296
Earnings from unconsolidated investments . (682) 709 (1,151)
Depreciation, depletion and amortization . 11,259 19,607 2,665
Capital expenditures . . . . . . . . . . . 10,761 29,722 3,586
Identifiable assets. . . . . . . . . . . . 246,397 163,066 39,992
<CAPTION>
INDEPENDENT POWER GROUP
<S> <C>
Sales to unaffiliated customers. . . . . . . $ 93,053
Intersegment sales . . . . . . . . . . . . . 2,552
Pre-tax operating income . . . . . . . . . . 2,668
Earnings from unconsolidated investments . . 1,839
Depreciation, depletion and amortization . . 2,720
Capital expenditures . . . . . . . . . . . . 19,489
Identifiable assets. . . . . . . . . . . . . 164,777
<CAPTION>
CORPORATE
<S> <C>
Sales to unaffiliated customers. . . . . . .
Intersegment sales . . . . . . . . . . . . .
Pre-tax operating income . . . . . . . . . .
Earnings from unconsolidated investments . .
Depreciation, depletion, and amortization. .
Capital expenditures . . . . . . . . . . . . $ 601
Identifiable assets. . . . . . . . . . . . . 66,300
* Sales under one coal contract with Houston Light and Power Company amounted to
$72,729,000.
/TABLE
<PAGE>
SUPPLEMENTARY DATA
OIL AND NATURAL GAS PRODUCING ACTIVITIES
<TABLE>
For the years ended December 31, 1994, 1993 and 1992 net recoverable oil and natural
gas reserves, excluding royalty volumes and volumes controlled under purchase
contract, of the Utility and Entech operations were estimated as follows:
<CAPTION>
1994
U.S. CANADA STORAGE
PROVED DEVELOPED AND UNDEVELOPED RESERVES:
<S> <C> <C> <C>
UTILITY OPERATIONS:
Natural Gas (Mmcf):
Beginning Balance 80,070 98,871 56,318
Production (4,742) (3,350)
Additions 87 570 230
(Sales) and Purchases of Reserves in Place
Revisions - Other 5,147 480
Revisions - Price
Ending Balance 80,562 96,571 56,548
ENTECH OPERATIONS:
Natural Gas (Mmcf):
Beginning Balance 140,923 59,071
Production (9,444) (7,785)
Additions 4,683 13,830
(Sales) and Purchases of Reserves in Place 2,250 5,866
Revisions - Other 14,385 4,987
Revisions - Price 365 3,314
Ending Balance 153,162 79,283
Natural Gas
Liquids (Bbls):
Beginning Balance 3,682,700 1,508,100
Production (376,650) (172,600)
Additions 103,300 365,300
(Sales) and Purchases of Reserves in Place (116,298) 81,184
Revisions - Other (199,552) 217,216
Revisions - Price 16,800 300
Ending Balance 3,110,300 1,999,500
Oil (Bbls):
Beginning Balance 6,238,700 4,511,600
Production (440,040) (709,248)
Additions 77,800 1,497,400
(Sales) and Purchases of Reserves in Place 821,276 (215,042)
Revisions - Other (740,736) (135,310)
Revisions - Price 122,700 (14,400)
Ending Balance 6,079,700 4,935,000
1994
U.S. CANADA
PROVED DEVELOPED RESERVES:
UTILITY OPERATIONS:
Natural Gas (Mmcf):
Ending Balance 79,731 96,571
ENTECH OPERATIONS:
Natural Gas (Mmcf):
Ending Balance 89,305 65,454
Natural Gas Liquids (Bbls):
Ending Balance 2,588,700 1,634,200
Oil (Bbls):
Ending Balance 3,194,600 3,437,600
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
1993
U.S. CANADA STORAGE
PROVED DEVELOPED AND UNDEVELOPED RESERVES:
<S> <C> <C> <C>
UTILITY OPERATIONS:
Natural Gas (Mmcf):
Beginning Balance 83,264 101,220 59,075
Production (5,587) (3,927)
Additions 788 (2,757)
(Sales) and Purchases of Reserves in Place
Revisions - Other 2,393 790
Revisions - Price
Ending Balance 80,070 98,871 56,318
ENTECH OPERATIONS:
Natural Gas (Mmcf):
Beginning Balance 133,421 41,620
Production (10,740) (6,735)
Additions 24,414 17,758
(Sales) and Purchases of Reserves in Place (130) 1,024
Revisions - Other (4,937) (74)
Revisions - Price (1,105) 5,478
Ending Balance 140,923 59,071
Natural Gas
Liquids (Bbls):
Beginning Balance 1,071,700 907,500
Production (143,059) (134,509)
Additions 597,100 452,766
(Sales) and Purchases of Reserves in Place (861,059) (8,353)
Revisions - Other 3,030,018 236,058
Revisions - Price (12,000) 54,638
Ending Balance 3,682,700 1,508,100
Oil (Bbls):
Beginning Balance 3,877,900 4,793,400
Production (528,408) (917,992)
Additions 3,157,100 1,208,328
(Sales) and Purchases of Reserves in Place 55,811 (115,014)
Revisions - Other (127,288) (373,231)
Revisions - Price (196,415) (83,891)
Ending Balance 6,238,700 4,511,600
1993
U.S. CANADA
PROVED DEVELOPED RESERVES:
UTILITY OPERATIONS:
Natural Gas (Mmcf):
Ending Balance 79,239 98,871
ENTECH OPERATIONS:
Natural Gas (Mmcf):
Ending Balance 89,372 51,437
Natural Gas Liquids (Bbls):
Ending Balance 3,088,600 1,314,300
Oil (Bbls):
Ending Balance 3,190,000 4,265,400
/TABLE
<PAGE>
<TABLE>
<CAPTION>
1992
U.S. CANADA STORAGE
PROVED DEVELOPED AND UNDEVELOPED RESERVES:
<S> <C> <C> <C>
UTILITY OPERATIONS:
Natural Gas (Mmcf):
Beginning Balance 87,970 102,609 59,545
Production (5,724) (2,951)
Additions (470)
(Sales) and Purchases of Reserves in Place 266
Revisions - Other 752 1,562
Revisions - Price
Ending Balance 83,264 101,220 59,075
ENTECH OPERATIONS:
Natural Gas (Mmcf):
Beginning Balance 119,245 36,887
Production (8,758) (6,748)
Additions 6,874 5,288
(Sales) and Purchases of Reserves in Place 2,603 227
Revisions - Other 9,603 2,771
Revisions - Price 3,854 3,195
Ending Balance 133,421 41,620
Natural Gas
Liquids (Bbls):
Beginning Balance 685,600 1,395,400
Production (138,226) (87,997)
Additions 517,581 700
(Sales) and Purchases of Reserves in Place (1,185)
Revisions - Other 6,745 (426,218)
Revisions - Price 26,800
Ending Balance 1,071,700 907,500
Oil (Bbls):
Beginning Balance 3,981,000 3,773,615
Production (590,573) (963,192)
Additions 731,174 1,106,684
(Sales) and Purchases of Reserves in Place 73,934 89,369
Revisions - Other (401,035) 694,224
Revisions - Price 83,400 92,700
Ending Balance 3,877,900 4,793,400
1992
U.S. CANADA
PROVED DEVELOPED RESERVES:
UTILITY OPERATIONS:
Natural Gas (Mmcf):
Ending Balance 82,449 101,220
ENTECH OPERATIONS:
Natural Gas (Mmcf):
Ending Balance 82,596 38,353
Natural Gas Liquids (Bbls):
Ending Balance 1,071,700 895,800
Oil (Bbls):
Ending Balance 3,406,000 4,076,500
</TABLE>
<PAGE>
SUPPLEMENTARY DATA
Oil and Natural Gas Producing Activities (Cont.)
As determined by engineers, utility natural gas reserves were revised
during 1994, 1993 and 1992 due to a change in projected performance or a
change in the Company's ownership interest in specific fields.
In 1994, Entech's U.S. oil and natural gas reserves increased as a
result of the acquisition of oil interests in Kansas and the drilling of 25
development wells and 6 exploratory wells in Colorado, Montana, Oklahoma, and
Wyoming. Natural gas liquid reserves decreased due to a lower liquid recovery
factor experienced at the Fort Lupton, Colorado, gas processing plant. Higher
oil market prices contributed to an upward revision in U.S. reserves. The
Canadian companies participated in 21 development wells and 7 exploratory
wells. Significant natural gas and natural gas liquid reserves were added as
a result of exploratory well discoveries in the Grand Prairie and Saddle Lake
areas of Alberta. A development well in the Caroline area in Alberta extended
the new pool discovery from 1993. Significant oil reserves were added at
Manyberries because of a new pool discovery and development drilling in 1994.
In 1993, Entech's U.S. oil and natural gas reserves increased as a
result of the drilling of 55 development wells and 10 exploratory wells in
Colorado, North Dakota, Wyoming, Oklahoma and Kansas. Natural gas liquid
reserves increased due to the startup of the Fort Lupton, Colorado, gas
processing plant in September 1993. Lower oil market prices contributed to
downward revisions in U.S. reserves. The Canadian companies participated in
26 development and 13 exploratory wells. Significant gas reserves were added
from discoveries in the exploratory wells. Additions in oil reserves were the
result of two successful secondary recovery schemes completed in the
Manyberries area in Southern Alberta during 1993. Revisions due to price and
performance resulted in a net increase in natural gas liquid reserves and a
net decrease in oil reserves.
In 1992, the drilling of 43 development wells and one exploratory well
in Colorado, Wyoming, and Oklahoma, resulted in additions to Entech's oil and
gas reserves in the United States. Price changes also added to the reserves
of existing properties. The Canadian companies participated in 59 development
and two exploratory wells, resulting in the addition of significant oil and
gas reserves. Revisions due to price and improved performance provided a net
increase in oil and gas reserves. Natural gas liquid reserves decreased due
to a downward revision in unit working interest in the recently developed
Shell Caroline area in Alberta.
<PAGE>
The following table presents information for 1994, 1993 and 1992 on the
capitalized costs relating to utility natural gas producing activities, costs
incurred in utility natural gas property acquisition, exploration and
development activities and certain utility natural gas production costs
reflected in results of operations. As a regulated public utility, the
Company is authorized to earn a rate of return on its utility natural gas
plant rate base. The Company's cost of acquiring utility natural gas reserves
and the net cost of natural gas in underground storage are included in the
natural gas plant which is a part of the utility rate base. Due to the
commingling of produced natural gas with purchased and royalty natural gas for
sale to utility customers and application of the ratemaking process to the
utility natural gas producing activities, the Company is unable to identify
revenues resulting solely from utility natural gas producing activities.
Accordingly, the information on revenues, income taxes, results of operations
and estimated future net cash flows and changes therein relating to proved
utility natural gas reserves are not presented for the Company's utility
natural gas producing activities.
<TABLE>
<CAPTION>
1994 1993 1992
United United United
States Canada States Canada States Canada
UTILITY OPERATIONS Thousands of Dollars
<S> <C> <C> <C> <C> <C> <C>
At December 31:
Capitalized costs relating
to natural gas producing
activities . . . . . . . $ 95,713 $ 36,904 $ 90,711 $ 35,786 $ 90,416 $ 35,592
Accumulated depreciation,
depletion and valuation
allowances . . . . . . . 48,913 19,386 44,516 18,815 43,003 18,500
Net capitalized costs. . $ 46,800 $ 17,518 $ 46,195 $ 16,971 $ 47,413 $ 17,092
For the year ended
December 31:
Costs incurred in natural
gas property acquisition,
exploration and
development activities:
Acquisition of
properties . . . . . $ 414 $ 259 $ 46 $ 27 $ 148 $ 7
Exploration. . . . . . 358 231 386 244 361 237
Development. . . . . . 5,158 1,203 1,528 496 1,208 329
Costs reflected in results
of operations:
Production costs . . . . 5,090 1,348 5,403 1,391 4,789 1,119
Exploration expenses . . 128 231 148 244 361 237
Development expenses . . 165 197 90 59 159 130
Depreciation, depletion
and valuation
provisions . . . . . . 2,607 487 2,564 283 2,421 511
</TABLE>
<PAGE>
The following table presents information for 1994, 1993 and 1992 on the
capitalized costs relating to Entech oil and natural gas producing activities,
costs incurred in Entech oil and natural gas property acquisition, exploration
and development activities and results of Entech operations for oil and
natural gas producing activities:
<TABLE>
<CAPTION>
1994 1993 1992
United United United
States Canada States Canada States Canada
ENTECH OPERATIONS Thousands of Dollars
At December 31:
<S> <C> <C> <C> <C> <C> <C>
Capitalized costs relating
to oil and natural gas
producing activities . . $145,639 $ 78,667 $136,949 $ 88,596 $121,119 $ 85,306
Accumulated depreciation,
depletion and valuation
allowances . . . . . . . 39,534 27,247 36,725 34,426 31,428 28,743
Net capitalized costs. $106,105 $ 51,420 $100,224 $ 54,170 $ 89,691 $ 56,563
For the year ended
December 31:
Costs incurred in oil and
natural gas property
acquisition, exploration
and development
activities:
Acquisition of
properties . . . . . $ 8,134 $ 5,866 $ 1,700 $ 2,638 $ 2,629 $ 1,774
Exploration. . . . . . 2,513 1,924 2,838 2,711 1,554 1,839
Development. . . . . . 11,514 4,068 26,279 5,721 15,729 9,183
ENTECH OPERATIONS
Results of operations for
oil and natural gas
producing activities:
Revenues . . . . . . . . $ 25,319 $ 22,542 $ 30,713 $ 23,435 $ 25,739 $ 23,541
Production costs . . . . 7,261 7,404 9,459 7,629 7,685 7,908
Exploration expenses . . 1,610 1,426 2,123 2,184 1,317 1,829
Depreciation, depletion
and valuation
provisions . . . . . . 10,533 7,669 10,386 8,707 9,895 9,515
5,915 6,043 8,745 4,915 6,842 4,289
Income tax expenses. . . 25 2,679 978 2,179 687 1,901
Results of operations from
producing activities
(excluding corporate
overhead and interest
cost). . . . . . . . . . $ 5,890 $ 3,364 $ 7,767 $ 2,736 $ 6,155 $ 2,388
</TABLE>
<PAGE>
SUPPLEMENTARY DATA
Oil and Natural Gas Producing Activities (Cont.)
Estimated future cash flows are computed by applying year-end prices and
contract prices, when appropriate, of oil and natural gas to year-end
quantities of proved reserves. Estimated future development and production
costs are determined by estimating the expenditures to be incurred in
developing and producing the proved oil and natural gas reserves at the end of
the year, based on year-end costs. Estimated future income tax expenses are
calculated by applying year-end statutory tax rates to estimated future pretax
net cash flows related to proved oil and natural gas reserves, less the tax
basis of the properties involved. The future income tax expenses give effect
to permanent differences, tax credits and deferred taxes relating to proved
oil and natural gas reserves.
These estimates are furnished and calculated in accordance with
requirements of the Financial Accounting Standards Board and the Securities
and Exchange Commission (SEC). Management believes the usefulness of these
projections is limited because of the unpredictable variances in expenses,
capital forecasts and crude oil and natural gas prices. Estimates of future
net cash flows presented do not represent management's assessment of future
profitability or future cash flow to the Company. Management's investment and
operating decisions are based upon reserve estimates that include proved
reserves prescribed by the SEC as well as probable reserves, and upon
different price and cost assumptions from those used here.
<PAGE>
Standardized Measure of Discounted Future
Net Cash Flows and Changes Therein Relating to
Proved Oil and Natural Gas Reserves
<TABLE>
<CAPTION>
December 31
1994 1993
United United
States Canada States Canada
Thousands of Dollars
<S> <C> <C> <C> <C>
Future cash inflows. . . . . . . . $ 603,543 $ 185,877 $ 597,493 $ 166,455
Future production and
development costs. . . . . . . . 200,004 69,043 227,093 44,367
Future income tax expenses . . . . 114,953 29,952 106,670 31,003
Future net cash flows. . . . . . . 288,586 86,882 263,730 91,085
10% annual discount for
estimated timing
of cash flows. . . . . . . . . . 122,835 23,382 113,062 22,320
Standardized measure of
discounted future net
cash flows . . . . . . . . . . . $ 165,751 $ 63,500 $ 150,668 $ 68,765
The following are the principal sources of change in the standardized measure of
discounted future net cash flows:
Sales and transfers of oil and
gas produced, net of
production costs . . . . . . . . $ (18,058) $ (15,137) $ (21,254) $ (15,807)
Net changes in prices,
development and production
costs. . . . . . . . . . . . . . 1,939 (15,010) (4,707) 4,744
Extensions, discoveries, and
improved recovery, less
related costs. . . . . . . . . . 13,454 18,687 45,772 23,655
Revisions of previous quantity
estimates. . . . . . . . . . . . 12,868 3,449 (4,521) 2,346
Accretion of discount. . . . . . . 18,839 8,198 15,745 6,470
Net change in income taxes . . . . (4,683) 1,895 (10,327) (9,016)
Other. . . . . . . . . . . . . . . (9,276) (7,347) (91) (4,128)
Extensions, discoveries, and improved recovery, less related costs,
represent the present value of current year reserve additions valued at
year-end prices less actual unit production costs for the current year. For
the years 1994 and 1993, the amount described as other is primarily the result
of changes in the timing of production.
</TABLE>
<PAGE>
Quarterly Financial Data
<TABLE>
Operating revenues, operating income and net income in thousands of
dollars and net income per common share for the four quarters of 1994 and 1993
are shown in the tables below. Operating revenues and income include
intersegment sales and expenses. Due to the seasonal nature of the utility
business, the annual amounts are not generated evenly by quarter during the
year.
<CAPTION>
Quarter Ended
Dec. 31, Sept. 30, June 30, Mar. 31,
1994 1994 1994 1994
<S> <C> <C> <C> <C>
Utility Operating Revenues . . . . $ 166,711 $ 110,394 $ 104,315 $ 160,212
Utility Operating Income . . . . . 55,546 8,670 10,728 52,702
Utility Net Income . . . . . . . . 27,843 130 1,162 26,274
Entech Operating Revenues. . . . . 109,503 107,796 91,379 109,229
Entech Operating Income. . . . . . 15,715 15,574 12,141 17,036
Entech Net Income. . . . . . . . . 13,896 12,393 9,772 11,827
Independent Power Group
Operating Revenues . . . . . . . 27,070 27,404 21,729 20,985
Independent Power Group
Operating Income . . . . . . . . 6,555 5,573 84 780
Independent Power Group Net
Income (Loss). . . . . . . . . . 3,686 5,758 (225) 1,076
Consolidated Net Income. . . . . . 45,425 18,281 10,709 39,177
Net Income Per Share of Common
Stock. . . . . . . . . . . . . . 0.82 0.31 0.17 0.70
Quarter Ended
Dec. 31, Sept. 30, June 30, Mar. 31,
1993 1993 1993 1993
Utility Operating Revenues . . . . $ 169,249 $ 107,143 $ 100,411 $ 168,949
Utility Operating Income . . . . . 63,395 14,609 7,902 57,566
Utility Net Income (Loss). . . . . 31,958 1,638 (1,736) 28,202
Entech Operating Revenues. . . . . 107,227 108,887 84,781 104,021
Entech Operating Income. . . . . . 16,747 14,706 7,862 16,058
Entech Net Income. . . . . . . . . 17,557 11,214 6,723 11,696
Independent Power Group
Operating Revenues . . . . . . . 31,707 31,464 35,095 29,568
Independent Power Group
Operating Loss . . . . . . . . . (591) (448) (262) (47)
Independent Power Group Net
Income (Loss). . . . . . . . . . 610 (795) (3) 147
Consolidated Net Income. . . . . . 50,125 12,057 4,984 40,045
Net Income Per Share of Common
Stock. . . . . . . . . . . . . . 0.93 0.21 0.08 0.76
</TABLE>
<PAGE>
ITEM 9. DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS
See Item 1. Business - "Executive Officers."
Information on Directors is incorporated by reference from the Company's
Notice of 1995 Annual Meeting of Shareholders and Proxy Statement, pages 1-3.
ITEM 11. EXECUTIVE COMPENSATION
Incorporated by reference from Notice of 1995 Annual Meeting of
Shareholders and Proxy Statement, pages 5-8.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Incorporated by reference from Notice of 1995 Annual Meeting of
Shareholders and Proxy Statement, pages 3-4.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Incorporated by reference from Notice of 1995 Annual Meeting of
Shareholders and Proxy Statement, page 14.
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a) Please refer to Item 8, "Financial Statements and Supplementary Data"
for a complete listing of all consolidated financial statements and
financial statement schedules.
(b) The Company filed the following reports on Form 8-K:
Date Subject
None
<PAGE>
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
3. Exhibits Incorporation by Reference
Previous
Previous Exhibit
Filing Designation
3(a) Restated Articles of Incorporation 33-42882 4(a)
3(a)(1) Restated Articles of Incorporation 33-56739 3(a)
3(a)(2) Amendments to the Restated Articles
of Incorporation 33-56739 3(a)
3(b) By-laws, as amended 33-42882 4(b)
3(b)(1) Amendments to By-laws
4(a) Mortgage and Deed Trust 2-5927 7(e)
4(b) First Supplemental Indenture 2-10834 4(e)
4(c) Second Supplemental Indenture 2-14237 4(d)
4(d) Third Supplemental Indenture 2-27121 2(a)-5
4(e) Fourth Supplemental Indenture 2-36246 2(a)-6
4(f) Fifth Supplemental Indenture 2-39536 2(a)-7
4(g) Sixth Supplemental Indenture 2-49884 2(a)-8(a)
4(h) Seventh Supplemental Indenture 2-52268 2(a)-9
4(i) Eighth Supplemental Indenture 2-53940 2(a)-10
4(j) Ninth Supplemental Indenture 2-55036 2(a)-11
4(k) Tenth Supplemental Indenture 2-63264 2(a)-12
4(l) Eleventh Supplemental Indenture 2-86500 2(a)-13
4(m) Twelfth Supplemental Indenture 33-42882 4(c)
4(n) Thirteenth Supplemental Indenture 33-55816 4(a)-14
4(o) Fourteenth Supplemental Indenture 33-64576 4(c)
4(p) Fifteenth Supplemental Indenture 33-64576 4(d)
4(q) Sixteenth Supplemental Indenture 33-50235 99(a)
4(r) Seventeenth Supplemental Indenture 33-56739 99(a)
4(s) Eighteenth Supplemental Indenture 33-56739 99(b)
Instruments defining the rights of holders of long-term debt
which are not required to be filed with the Commission will be
furnished to the Commission upon request.
Incorporation by Reference
Previous
Previous Exhibit
Filing Designation
4(t) Rights Agreement dated as of 33-42882 4(d)
June 6, 1989, between The
Montana Power Company and First
Chicago Trust Company of New
York, as Rights Agent
10(a)(i) Benefit Restoration Plan for 33-42882 10(a)(i)
Senior Management Executives
and Board of Directors
10(a)(ii) Deferred Compensation Plan for 33-42882 10(a)(ii)
Non-Employee Directors
<PAGE>
Incorporation by Reference
Previous
Previous Exhibit
Filing Designation
10(a)(iii) Long-Term Incentive Stock 1-4566 10(a)(iii)
Ownership Plan 1992
Form 10-K
10(a)(iv) The Montana Power Company 33-28096 4(c)
Employee Stock Ownership Plan
(Revised)
10(a)(v) Termination Compensation 1-4566 10(a)(v)
Agreements with Senior 1992
Management Executives Form 10-K
10(a)(v)(1) Amendments to Termination
Compensation Agreements with
Senior Management Executives
10(c) Participation Agreements among 33-42882 10(c)
United States Trust Company
of New York, Burnham Leasing
Corporation, and SGE (New York)
Associates, Certain Institutions,
The Montana Power Company and
Bankers Trust Company
12 Statement re computation of ratio
of earnings to Fixed Charges
21 Subsidiaries of the registrant
27 Financial Data Schedule
<PAGE>
THE MONTANA POWER COMPANY AND SUBSIDIARIES
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Thousands of Dollars
<TABLE>
<CAPTION>
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
Balance Additions
at Charged to Charged to Balance
beginning costs and other at close
Description of period expenses accounts Deductions of period
<S> <C> <C> <C> <C> <C>
(Note a)
Year Ended:
December 31, 1994
Reserves deducted
in balance sheet
from assets to
which they apply:
Doubtful accounts
Utility $ 748 $ 781 $ $ 721 $ 808
Entech 643 156 (9) 174 616
Total $ 1,391 $ 937 $ (9) $ 895 $ 1,424
December 31, 1993
Reserves deducted
in balance sheet
from assets to which
they apply:
Doubtful accounts
Utility $ 688 $ 764 $ $ 704 $ 748
Entech 529 391 17 294 643
Total $ 1,217 $ 1,155 $ 17 $ 998 $ 1,391
December 31, 1992
Reserves deducted
in balance sheet
from assets to which
they apply:
Doubtful accounts
Utility $ 628 $ 1,361 $ $ 1,301 $ 688
Entech 387 345 3 206 529
Total $ 1,015 $ 1,706 $ 3 $ 1,507 $ 1,217
NOTES:
(a) Deductions are of the nature for which the reserves were created. In the case of the
reserve for doubtful accounts, deductions from this reserve are reduced by recoveries
of amounts previously written off.
/TABLE
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
THE MONTANA POWER COMPANY
By /s/ Daniel T. Berube
Daniel T. Berube
(Chairman of the Board)
Date March 21, 1995
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
registrant and in the capacities and on the dates indicated.
Signature Title Date
/s/ Daniel T. Berube Principal Executive
Daniel T. Berube Officer and Director March 21, 1995
(Chief Executive Officer)
/s/ J. P. Pederson Principal Financial
J. P. Pederson and Accounting Officer March 21, 1995
(Vice President and Chief and Director
Financial Officer)
/s/ Alan F. Cain Director March 21, 1995
Alan F. Cain
/s/ R. D. Corette Director March 21, 1995
R. D. Corette
<PAGE>
/s/ Kay Foster Director March 21, 1995
Kay Foster
/s/ Robert P. Gannon Director March 21, 1995
Robert P. Gannon
/s/ Beverly D. Harris Director March 21, 1995
Beverly D. Harris
/s/ Chase T. Hibbard Director March 21, 1995
Chase T. Hibbard
/s/ Daniel P. Lambros Director March 21, 1995
Daniel P. Lambros
/s/ Carl Lehrkind, III Director March 21, 1995
Carl Lehrkind, III
/s/ James P. Lucas Director March 21, 1995
James P. Lucas
/s/ Arthur K. Neill Director March 21, 1995
Arthur K. Neill
/s/ George H. Selover Director March 21, 1995
George H. Selover
/s/ N. E. Vosburg Director March 21, 1995
N. E. Vosburg
<PAGE>
Consent of Independent Accountants
We hereby consent to the incorporation by reference in the Prospectus
constituting part of the Registration Statement on Form S-3 No. 33-56739, to
the incorporation by reference in the Prospectus constituting part of the
Registration Statement on Form S-3 No. 33-64922, to the incorporation by
reference in the Prospectus constituting part of the Registration Statement on
Form S-3 No. 33-43655, to the incorporation by reference in the Prospectus
constituting part of the Registration Statement on Form S-8 No. 33-64576, to
the incorporation by reference in the Prospectus constituting part of the
Registration Statement on Form S-8 No. 33-24952, to the incorporation by
reference in the Prospectus constituting part of the Registration Statement on
Form S-8 No. 33-28096, to the incorporation by reference in the Prospectus
constituting part of the Registration Statement on Form S-3 No. 33-32275 and
to the incorporation by reference in the Prospectus constituting part of the
Registration Statement on Form S-3 No. 33-55816 of our report dated
February 10, 1995 appearing on page 51 of The Montana Power Company's Annual
Report on Form 10-K for the year ended December 31, 1994.
PRICE WATERHOUSE LLP
Portland, Oregon
March 23, 1995
<PAGE>
EXHIBIT INDEX
Exhibit (3)(b)(1)
Amendments to By-laws
Exhibit 10(a)(v)(1)
Amendments to Termination Compensation
Agreements with Senior Management Executives
Exhibit 12
Statement re computation of ratio earnings to Fixed Charges
Exhibit 21
Subsidiaries of the registrant
Exhibit 27
Financial Data Schedule
BYLAWS
OF
THE MONTANA POWER COMPANY
Adopted on : September 22, 1992
As Amended on : December 13, 1994
<PAGE>
THE MONTANA POWER COMPANY
AMENDMENTS TO BYLAWS
Article Amendment Date of Amendment
11 Establishment of the December 13, 1994
number of Directors as
fourteen (14).
(See Attachment A hereto.)
<PAGE>
ATTACHMENT A
THE MONTANA POWER COMPANY
CERTIFICATION OF RESOLUTION
I, R. M. Ralph, Assistant Secretary of The Montana
Power Company, a corporation, hereby certify that the
following is a full, true and correct copy of Resolution
duly adopted by the Board of Directors of The Montana Power
Company at a meeting duly called and held December 13, 1994
and that said Resolution is in full force and effect as of
the date of this certificate.
RESOLVED, that effective January 1, 1995, the
first sentence of Section 11 of the Bylaws of The
Montana Power Company is hereby amended to reduce the
number of Directors to fourteen (14) as follows:
SECTION 11. The affairs of the Corporation shall
be managed by a Board of fourteen (14) Directors.
IN WITNESS WHEREOF, I have hereunto set my hand and the
Seal of said Corporation this 6th day of January 1995.
/s/ R. M. Ralph
R. M. Ralph, Assistant Secretary
(SEAL)
MPC\pkma25.by
The following Amendment is similar in all material respects to
Amendments with Messrs. Berube, Cromer, Gannon, and Neill.
The Amendment adds the following language to your agreement after
subparagraph (b) on page 4:
(c) Your Awards of Dividend Equivalents which are
outstanding at the date of termination of your
employment will be accelerated and be payable to you as
follows:
(i) Actual annual performance will be calculated
to the end of the calendar year (s) prior to
the date of termination of your employment;
(ii) Performance for the years remaining in an
Award Period which end after the date of
termination of your employment will be deemed
to be sufficient such that 100% of all the
performance measures would have been
achieved; and
(iii) Payout will be made no later than 60 days
from the date of termination of employment by
calculating the amount due using the above
assumptions in the methodology prescribed in
the Dividend Equivalent Award.
The following Amendment is similar in all material respects to an
Amendment with Messrs. Murphy.
The Amendment adds the following language to your agreement after
subparagraph (b) on page 4:
(c) The restrictions on your Award of Restricted Stock
which is outstanding at the date of termination of your
employment will be removed and unrestricted stock issued to
you as follows:
(i) Performance for the years remaining in an
Award Period which end after the date of
termination of your employment will be deemed
to be sufficient such that 100% of all the
performance measures would have been
achieved; and
(ii) Unrestricted stock will be issued no later
than 60 days from the date of termination of
employment by calculating the amount due
using the above assumptions and the
methodology prescribed in the Restricted
Stock Award.
These Amendments are effective October 1, 1994.
EXHIBIT 12
THE MONTANA POWER COMPANY
Computation of Ratio of Earnings to Fixed Charges
(Dollars in Thousands)
Twelve Months
Ended
December 31, 1994
------------------
Net Income $115,963
Income Taxes 53,152
----------
$169,115
----------
Fixed Charges:
Interest $ 44,096
Amortization of Debt Discount,
Expense and Premium 1,666
Rentals 36,586
----------
$ 82,348
----------
Earnings Before Income Taxes
and Fixed Charges $251,463
==========
Ratio of Earnings to Fixed Charges 3.05X
==========
SUBSIDIARIES OF REGISTRANT Exhibit 21
Percentage
of Voting
Securities
Owned by
Registrant
Canadian-Montana Gas Company Limited
An Alberta Corporation 100
Canadian-Montana Pipe Line Company
An Alberta Corporation 100
Glacier Gas Company
A Montana Corporation 100
Colstrip Community Services Company
A Montana Corporation 100
Continental Energy Services, Inc.
A Montana Corporation 100
EMPECO, Inc.
A Montana Corporation
(A wholly-owned subsidiary of Continental
Energy Services, Inc.) 100
EMPECO II, Inc.
A Montana Corporation
(A wholly-owned subsidiary of Continental
Energy Services, Inc.) 100
EMPECO III, Inc.
A Montana Corporation
(A wholly-owned subsidiary of Continental
Energy Services, Inc.) 100
EMPECO IV, Inc.
A Montana Corporation
(A wholly-owned subsidiary of Continental
Energy Services, Inc.) 100
EMPECO V, Inc.
A Montana Corporation
(A wholly-owned subsidiary of Continental
Energy Services, Inc.) 100
EMPECO VI - TE, Inc.
A Montana Corporation
(A wholly-owned subsidiary of Continental
Energy Services, Inc.) 100
SUBSIDIARIES OF REGISTRANT Exhibit 21
Percentage
of Voting
Securities
Owned by
Registrant
EMPECO VII - TX3, Inc.
A Montana Corporation
(A wholly-owned subsidiary of Continental
Energy Services, Inc.) 100
North American Energy Services Company
A Washington Corporation
(A 50%-owned subsidiary of Continental
Energy Services, Inc.) 50
North American Contract Employee Services
A Washington Corporation
(A wholly-owned subsidiary of North
American Energy Services Company) 50
ECI Holdings, Ltd.
Investment in English Partnership in a
Gas-fired Cogeneration Project
(A 47.5% owned subsidiary of Continental
Energy Services, Inc.) 50
Entech, Inc.
A Montana Corporation 100
Western Energy Company
A Montana Corporation 100
Western Syncoal Company
A Montana Corporation
(A wholly-owned subsidiary of Western
Energy Company) 100
Montana Mineracao Participacoes, Ltda.
A Brazilian Corporation 100
Financiera Ulken Sociedad Anonima (SA)
A Uruguayan Corporation
(A wholly-owned subsidiary of Montana
Mineracao Participacoes, Ltda.) 100
SUBSIDIARIES OF REGISTRANT Exhibit 21
Percentage
of Voting
Securities
Owned by
Registrant
Northwestern Resources Co.
A Montana Corporation 100
Altana Exploration Company
A Montana Corporation 100
Intercontinental Energy Corporation
A Texas Corporation
(A wholly-owned subsidiary of Altana
Exploration Company) 100
Entech Altamont, Inc.
A Montana Corporation 100
Roan Resources, Ltd.
An Alberta Corporation 100
North American Resources Company
A Montana Corporation 100
Tetragenics Company
A Montana Corporation 100
TRI Touch America, Inc.
A Montana Corporation 100
Basin Resources, Inc.
A Colorado Corporation 100
Horizon Coal Services, Inc.
A Montana Corporation 100
North Central Energy Company
A Colorado Corporation 100
Trinidad Railway, Inc.
A Montana Corporation 100
Entech Gas Ventures, Inc.
A Montana Corporation 100
Note: The above listed companies are included in the
Consolidated Financial Statements of the registrant.
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED BALANCE SHEET AT 12/31/94, THE CONSOLIDATED INCOME STATEMENT AND
CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE 12 MONTHS ENDED 12/31/94 AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-START> JAN-01-1994
<PERIOD-END> DEC-31-1994
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,452,554
<OTHER-PROPERTY-AND-INVEST> 497,044
<TOTAL-CURRENT-ASSETS> 294,630
<TOTAL-DEFERRED-CHARGES> 268,469
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,512,697
<COMMON> 667,344
<CAPITAL-SURPLUS-PAID-IN> 2,442
<RETAINED-EARNINGS> 285,734
<TOTAL-COMMON-STOCKHOLDERS-EQ> 955,520
0
101,416
<LONG-TERM-DEBT-NET> 588,876
<SHORT-TERM-NOTES> 113,989
<LONG-TERM-NOTES-PAYABLE> 8,430
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 16,980
0
<CAPITAL-LEASE-OBLIGATIONS> 582
<LEASES-CURRENT> 732
<OTHER-ITEMS-CAPITAL-AND-LIAB> 726,172
<TOT-CAPITALIZATION-AND-LIAB> 2,512,697
<GROSS-OPERATING-REVENUE> 1,005,970
<INCOME-TAX-EXPENSE> 55,226
<OTHER-OPERATING-EXPENSES> 804,867
<TOTAL-OPERATING-EXPENSES> 860,093
<OPERATING-INCOME-LOSS> 145,877
<OTHER-INCOME-NET> 13,817
<INCOME-BEFORE-INTEREST-EXPEN> 159,694
<TOTAL-INTEREST-EXPENSE> 46,102
<NET-INCOME> 113,592
7,227
<EARNINGS-AVAILABLE-FOR-COMM> 106,365
<COMMON-STOCK-DIVIDENDS> 85,193
<TOTAL-INTEREST-ON-BONDS> 30,165
<CASH-FLOW-OPERATIONS> 203,886
<EPS-PRIMARY> 2.00
<EPS-DILUTED> 2.00
</TABLE>
