UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
______________________________________________________________________________
(Mark One)
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended December 31, 1998
-OR-
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
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 59701-9394
(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
8.45% Cumulative Quarterly Income New York Stock Exchange
Preferred Securities, Series A
of Montana Power Capital I, a
subsidiary of The Montana Power
Company
Securities registered pursuant to Section 12(g) of the Act:
Preferred Stock
(Title of Class)
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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 [ ].
The aggregate market value of the voting stock held by nonaffiliates of the
registrant was $3,380,598,127 at March 12, 1999.
On March 16, 1999, the Company had 55,077,919 shares of common stock
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
(1) Notice of 1999 Annual Meeting of Shareholders and Proxy Statement,
pages 1-44, is incorporated into Part III of this report.
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PART I
This Form 10-K contains forward-looking statements within the meaning of
Section 21E of the Securities Exchange Act of 1934. Forward-looking statements
should be read with the cautionary statements and important factors included in
this Form 10-K at Part II, Item 7, "Management's Discussion and Analysis of
Financial Conditions and Results of Operations - Safe Harbor for Forward-
Looking Statements." Forward-looking statements are all statements other than
statements of historical fact, including without limitation those that are
identified by the use of the words "anticipates", "estimates", "expects",
"intends", "believes", and similar expressions.
ITEM 1. BUSINESS
OVERVIEW: The Montana Power Company (the Company) and its subsidiaries
engage in a number of diversified energy and communication related businesses.
The Company operates a regulated Utility which generates, purchases, transmits,
and distributes electricity and purchases, transports, and distributes natural
gas. The Company's Nonutility operations principally conduct
telecommunications operations which sell long distance, Internet, and dedicated
line services and equipment and design, develop, construct, operate, maintain,
and manage a fiber-optic network and digital microwave facilities. Other
Nonutility operations include the mining and sale of coal and lignite, and
exploration for, and the development, production, processing, and sale of oil
and natural gas. The Company also conducts the trading of electricity and the
trading and marketing of natural gas. In addition, the Company manages long-
term power sales, and develops and invests in independent power projects and
other energy-related businesses. The Company was incorporated in 1961 under
the laws of the State of Montana as the successor to a corporation formed in
1912. See Part II, Item 8, "Financial Statements and Supplementary Data -
Note 12 to the Consolidated Financial Statements" for further information on
the Company's business segments.
RECENT DEVELOPMENTS:
? Montana's Electric Industry Restructuring and Customer Choice Act (Electric
Act) and Natural Gas Restructuring and Customer Choice Act (Gas Act) became
law in May 1997.
? In November 1997, significantly all of the Utility's natural gas production
assets were transferred to an unregulated affiliate. The Company also
implemented a fixed-price supply contract through 2002 between its
unregulated gas supply division and its regulated distribution division to
serve the remaining customers who have not chosen other suppliers.
? In July 1998, the Company and the owners of Colstrip Units 3 and 4
generating plants settled coal contract disputes and future coal price
reopeners.
? In August 1998, the Company announced it is exiting the electric commodity
trading and marketing businesses, but will continue natural gas and natural
gas liquids commodity trading and marketing.
? In November 1998, the Company announced an agreement (Agreement) to sell
the Company's interest in 12 of its 13 Utility hydroelectric facilities,
all four coal-fired thermal generating plants, a Nonutility leasehold
interest in Colstrip Unit 4, a power purchase contract with Basin Electric
Power Cooperative (Basin) and two power exchange agreements to PP&L Global,
Inc.
? In December 1998, a special purpose entity (SPE) wholly owned by the
Company issued $62,700,000 of asset-backed transition bonds.
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? In December 1998, the Company resolved a dispute with the purchaser of
lignite from the Jewett Mine involving the price of lignite and whether
other fuels could be substituted for lignite.
? In January 1999, the Company received and recorded $257,000,000 representing
prepayment of all amounts due for the remaining initial term of one
telecommunications contract.
With the sale of the Company's interest in its electric generating
facilities and the exit from the electric trading and marketing business, the
Company no longer will be a primarily a vertically integrated electric and
natural gas utility. The Company expects to maintain its traditional
regulated transmission and distribution utility businesses in Montana, the
coal and lignite mines that serve mine-mouth generating plants, the
independent power investments and operations and the natural gas exploration,
development, production, trading, and marketing. The Company will also
continue to invest in new opportunities such as telecommunications.
See Part II, Item 7, "Management's Discussion and Analysis of Financial
Conditions and Results of Operations" and Item 8, "Financial Statements and
Supplementary Data - Notes 4 and 9 to the Consolidated Financial Statements"
for further discussion of recent developments and changes in the Company's
operations.
UTILITY OPERATIONS:
SERVICE AREA AND SALES: The Utility's service territory comprises
107,600 square miles or approximately 73 percent of Montana. It serves
approximately 603,000 residents or 80 percent of the population within the
service territory. Additionally, energy is provided to cooperatives that serve
approximately 76,000 residents. The dominant segments of Montana's economy
include agriculture and livestock, which is the largest industry; tourism and
recreation; coal and metals mining; oil and natural gas production; and the
forest-products industry, including production of pulp and paper, plywood and
lumber.
Electric service is provided to 191 communities, the rural areas
surrounding them, and Yellowstone National Park. Firm electric power is sold
at wholesale to two rural electric cooperatives and natural gas service is
provided to 109 communities.
ELECTRIC UTILITY: Total firm capability of the Utility's electric system
at December 31, 1998 was 1,510,700 kW. Of this capability, the Utility's
generating facilities provided 1,157,400 kW, and 353,300 kW was provided by
firm Electric Utility power purchase and exchange arrangements. Also refer to
Part II, Item 8, "Financial Statements and Supplementary Data - Note 3 to the
Consolidated Financial Statements" for further discussion of power purchases.
The maximum demand on the resources in 1998 was 1,560,000 kW on
December 21, 1998. The total firm capability on that date was 1,396,000 kW.
Also on that date, the Electric Utility's reserve margin, as a percentage of
maximum demand, was 13 percent.
During the year ended December 31, 1998, the sources of the Utility
electric supply were hydro, 37 percent; coal, 45 percent; and purchased power,
18 percent. The cost of coal burned has been as follows:
Year Ended December 31
1998 1997 1996
Average cost per million Btu's $ 0.59 $ 0.59 $ 0.59
Average cost per ton (delivered) 9.99 9.93 10.06
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The Company's electric system forms an integral part of the Northwest
Power Pool, which consists of the major electric suppliers in the Pacific
Northwest region of the United States, in British Columbia, and also in parts
of Alberta, Canada. The Company 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. The Company is also a member of the Western Systems Coordinating
Council, organized by 84 member systems and 21 affiliates in the 14 western
states, British Columbia, Alberta, and Mexico to assure reliability of
operations and service to their customers. The Company participates in an
interconnection agreement with Avista Corporation, IdaCorp, Inc., 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 that 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.
FERC has announced its intention to conduct a rulemaking during 1999 on
FERC's authorities to require transmission owners to participate in regional
transmission entities such as independent system operators (ISO) or independent
transmission companies, "transcos". The Company will participate in the FERC
rulemaking process and is evaluating possible participation in a regional
transmission entity.
Regardless of the timing of the sale of the Company's generating assets
and power purchase and exchange contracts, the Company is obligated to continue
to provide electric power supply through the transition period to customers in
its service territory who have not chosen, or have not had an opportunity to
choose to purchase energy from another power supplier. Such service will
require the Company to have available a power supply sufficient to meet those
customers' electric loads. The Agreement includes transition service
agreements under which the Company will purchase electricity to supply
customers in its service territory who have not chosen, or have not had an
opportunity to choose to purchase energy from another power supplier throughout
the transition period. Once the transition period is complete, the Electric
Utility may be required to offer electric supply as the supplier of last resort
for customers who have not chosen other suppliers. The Company anticipates
that any costs related to this electric supply would be recovered through rates
charged to such customers. Through December 1998, approximately 50 customers,
representing approximately 10 percent of the Utility's pre-choice load has
chosen alternate suppliers. See Part II, Item 8, "Financial Statements and
Supplementary Data - Note 4 to the Consolidated Financial Statements".
NATURAL GAS UTILITY: Natural gas supply requirements in 1998 totaled
19,961 Mmcf, of which 7,095 Mmcf were from third party contracts with Montana
suppliers and 1,797 Mmcf from third party contracts with Canadian suppliers. A
total of 11,069 Mmcf, or approximately 55.4 percent of the natural gas supply
requirements for the year, was purchased from an unregulated subsidiary,
Montana Power Gas Company (MP Gas). MP Gas has access to reserves in both
Montana and Canada.
Total volumes of natural gas transported were 27,368 Mmcf, 26,020 Mmcf,
and 26,969 Mmcf for 1998, 1997, and 1996 respectively. The 1999
transportation volumes are anticipated to be 27,890 Mmcf. The Company filed a
core aggregation pilot program (pilot program) in February 1998 with the
Montana Public Service Commission (PSC), providing supplier choice for
residential and small commercial/industrial customers. The pilot program
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provided all of the Utility's core customers with an opportunity to purchase
their gas supply from other sources beginning in November 1998. Approximately
6 percent of residential and small commercial/industrial customers have
expressed an interest in supplier choice, but no contracts have been signed at
this time. The regulated Natural Gas Utility will continue to provide gas
transmission, storage, and distribution service to its customers.
As a result of the natural gas restructuring order effective on
November 1, 1997, natural gas customers with annual consumption of 5,000
dekatherms or more are eligible to be served through unbundled gas
transportation service. Consequently, the number of customers previously
receiving bundled service who have elected unbundled transportation service
has increased from 24 to over 232. Substantially all of these customers
obtain their supplies directly from other sources.
Total 1999 natural gas requirements, estimated to be 20,580 Mmcf, are
anticipated to be supplied from MP Gas and other purchase contracts.
Approximately 30 percent of purchases under contracts with outside suppliers
expire each year beginning in 1999 through 2002. As a result of the natural
gas restructuring order, these contracts may not be renegotiated to the extent
that the Gas Utility has less load due to customer choice.
REGULATION AND RATES: The Company's public utility business in Montana
is subject to the jurisdiction of the PSC. The PSC has jurisdiction over the
setting of bundled retail electric and natural gas rates, electric distribution
tariffs, gas transportation tariffs, issuance of securities and certain
limitations on borrowing by the Company. The Federal Energy Regulatory
Commission (FERC) also has jurisdiction over the Company, under the Federal
Power Act, as a licensee of hydroelectric projects and as a public utility with
respect to wholesale sales of electricity, unbundled transmission of
electricity and interstate interruptible transportation of natural gas. The
importation of natural gas from Canada requires approval by the Alberta Energy
and Utilities Board, the National Energy Board of Canada, and the United States
Department of Energy.
Montana's Electric Industry Restructuring and Customer Choice Act and
Natural Gas Restructuring and Customer Choice Act providing for customer
choice for electric and natural gas supply became law in May 1997.
Also refer to Part II, Item 7, "Management's Discussion and Analysis of
Financial Conditions and Results of Operations - Competitive Environment" and
Part II, Item 8, "Financial Statements and Supplementary Data - Note 4 to the
Consolidated Financial Statements" for further discussion on changes in utility
regulation.
COMPETITIVE ENVIRONMENT: Refer to Part II, Item 7, "Management's
Discussion and Analysis of Financial Conditions and Results of Operations -
Competitive Environment".
NONUTILITY OPERATIONS:
OVERVIEW: The Company's Nonutility operations for coal, oil and natural
gas, telecommunications, and independent power operations are principally
operated under a holding company, Entech, Inc., a wholly owned subsidiary of
the Company. Other Nonutility business is conducted by various subsidiaries,
none of which is significant.
COAL OPERATIONS: Coal operations are operated primarily conducted by
Western Energy Company (Western) and Northwestern Resources Co. 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.
Western's principal customers from this mine are the owners of the four mine-
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mouth Colstrip units. These customers accounted for approximately 94 percent
of 1998 coal sales volumes. The remainder of Rosebud coal was sold under spot-
market sale agreements and contracts in Minnesota, North Dakota, and Montana.
During 1998, Western mined and sold 10,499,000 tons, of which 3,547,000 tons
were sold to the Company. Western's Rosebud Mine production is estimated to be
10,614,000 tons in 1999 and 10,761,000 tons in 2000.
Northwestern's Jewett Mine, located in central Texas, supplies surface-
mined lignite under a long-term lignite sale agreement (LSA) to the two
electric generating units, located adjacent to the mine, that are owned by
Reliant Energy. Total deliveries in 1998 were 8,831,959 tons. The estimated
production for 1999 and 2000 are 8,100,000 and 7,600,000 tons, respectively.
After 2001, production is estimated to be approximately 8,000,000 tons
annually. During 1998, Northwestern and Reliant Energy, formerly know as
Houston Lighting & Power, signed a letter of intent regarding amendments to
the LSA. This amendment allows Reliant Energy to blend petroleum coke with
the lignite at a 20/80 ratio. The blending is contingent upon the receipt of
permits from the Texas Railroad Commission. The total tons under contract did
not change. Northwestern will produce the contracted tons over an extended
period.
OIL AND NATURAL GAS OPERATIONS: Oil and natural gas operations are
operated primarily under North American Resources Company, MP Gas and Altana
Exploration Co., all of which are United States subsidiaries, and Altana
Exploration Ltd. and Canadian Montana Gas Company, both Canadian subsidiaries.
Natural gas, natural gas liquids, oil commodity trading and marketing, and
related energy services are provided by the Company's subsidiary, The Montana
Power Trading and Marketing Company (MPT&M). MPT&M competes for former natural
gas supply customers of the Company's Utility operations who have exercised
choice. Oil and natural gas operations are engaged in exploration, production,
gathering, processing, and marketing of oil and natural gas in the United
States and Canada. U.S. producing oil and natural gas properties are
principally located in the states of Wyoming, Colorado, Oklahoma, and Montana.
Canadian properties are principally located in the Province of Alberta, Canada.
A subsidiary has entered into agreements to supply 92 Bcf of natural gas to
four co-generation facilities over a period of 6 to 12 years for which there is
sufficient proven, developed and undeveloped reserves and controls related
sales of production sufficient to supply all of the remaining natural gas
required by those agreements. None of the reserves are dedicated to supply
these agreements.
Natural gas production in both the United States and Canada is currently
sold pursuant to short-term, spot-market and long-term contracts. Approximately
95,981 Mmcf, or 81 percent of Canadian natural gas reserves, are dedicated to
long-term contracts expiring at various times through 2005. In addition to
serving these contracts, the Company intends to concentrate its efforts on
natural gas production in support of the expanding market development
objectives.
INDEPENDENT POWER OPERATIONS: Independent power operations develops,
acquires, operates, maintains, and manages facilities and resources to provide
electricity and other energy-related services.
Colstrip 4 Lease Management Division sells the Company's 242 MW leased
share of Colstrip Unit 4 generation principally to the Los Angeles Department
of Water and Power and to Puget Sound Energy, Inc. under contracts with terms
coexistent with the lease through December 29, 2010. The leasehold interest
and its related assets and liabilities and sales contract obligations are
intended to be sold to PP&L Global, Inc. with the regulated electric generating
facilities and power purchase contracts.
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Continental Energy Services (CES) develops and invests in independent
power projects. During 1998, CES sold its share of the Lockport Project in the
state of New York and participated in a power purchase agreement settlement on
another project in New York. The plant from this project is currently being
dismantled and the partnership will be dissolved in 1999. CES currently holds
ownership interests in five operating natural gas-fired projects located in
Texas, Washington, and the United Kingdom, one heavy oil-fired project located
in Jamaica and two natural gas-fired independent power projects under
construction in Pakistan and Grimes County, Texas. CES, through a wholly owned
subsidiary, is the managing general partner of a 255 MW project located in
Texas. In addition, CES is participating with others in the development of a
coal-fired project in India. Refer to Part I, Item 2, "Properties -
Independent Power Properties".
TELECOMMUNICATIONS OPERATIONS: The Company's telecommunications
business, Touch America, develops, constructs, operates, and maintains a
fiber-optic network and digital microwave facilities. Touch America also
provides a full range of wholesale and retail telecommunications services
including long-term capacity sales to other telecommunications carriers, long
distance, Internet, and dedicated private line services, and equipment sales.
Touch America offers telecommunications services in seven states and has
staffed offices in Minneapolis, Minnesota; Bismarck, North Dakota; Billings,
Bozeman, Helena, Butte, Great Falls, Kalispell, and Missoula, Montana; Boise,
Idaho; Spokane and Seattle, Washington; Eugene, Oregon; Casper and Cheyenne,
Wyoming; and Denver, Colorado. As Touch America's network expands, it expects
to open new offices. The Company has also entered the wireless communications
market through the use of its 24 Local Multipoint Distribution Services
licenses and its 12 Personal Communications Services licenses.
Currently, Touch America's fiber network extends approximately 10,000
miles from Chicago, Illinois west to Seattle, south to Los Angeles,
California, with both a coastal route via Portland, Oregon and Sacramento,
California and an inland route via Boise, Salt Lake City, Utah, and Las Vegas,
Nevada, and from Denver north through Wyoming and Montana to the Canadian
border. At the end of 1998, 6,000 of the 10,000 miles were in service, and by
mid-1999, the entire network is expected to be in service.
The Seattle to Los Angeles inland route was accomplished through a joint
construction effort among Touch America, Williams Companies, and Enron Corp.,
known as the FTV partnership. Touch America served as the construction and
services manager for the construction project. The segments from Las Vegas to
Los Angeles and Seattle to Portland were acquired through a fiber swap. Some
of the dark fiber (i.e., unlit fiber with no electronic equipment) on the
route has been sold to other telecommunications companies, and some has been
exchanged for fiber on other routes. The remaining fibers will be divided
between the three partners, and Touch America will operate and maintain its
portion.
In other exchange arrangements, Touch America received fiber on a
coastal route from Portland through Sacramento to Los Angeles, and it received
fiber from Minneapolis/St. Paul, Minnesota through Green Bay, Wisconsin to
Chicago. In total, Touch America's current fiber network spans 14 states.
Touch America has plans for expansion that will extend the existing
network by some 8,000 miles and give the Company a continental network by the
end of 2000. Currently underway is an expansion project that extends from
Salt Lake City through Wyoming to Denver and from Denver to Dallas, Texas
through Amarillo, Texas. This expansion should be complete by the end of 1999
and will extend Touch America's reach to 16 states.
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Touch America's network is comprised of up-to-date fiber technology and
includes SL, SMF28, and LEAF fiber. The Company also has installed or is
upgrading to Dense Wave Division Multiplexing (DWDM) technology, which greatly
increases the capacity of each fiber strand.
COMPETITIVE ENVIRONMENT: Current production from the Rosebud and Jewett
Mines is sold under long-term contracts to mine-mouth customers. Western
supplies Colstrip Units 1 through 4 under the terms of contracts obligating
the Colstrip Units to purchase all of the fuel required by the plants from
Western. Currently, all of the coal requirements for these units are supplied
from the Rosebud Mine. The coal supply agreement between the Company and the
owners of Colstrip Units 1 and 2 provides for a price re-opener in 2001. The
Company and the owners of Colstrip Units 3 and 4, however, entered into an
Amended and Restated Coal Supply Agreement dated August 28, 1998, and, among
other contract amendments, eliminated future price re-openers for this coal
supply agreement. The Company expects to profitably serve both of these
contracts over their remaining lives. The Rosebud Mine has production
capacity that exceeds the mine-mouth customers' fuel requirements. In the
sale of this capacity, it faces competition from Montana and Wyoming Powder
River Basin producers located south of the mine. These producers generally
experience lower operating costs and the Wyoming coal also has a lower sulfur
content than that from Rosebud. The Company, therefore, anticipates only
modest contract sales and likely no significant spot market sales for the
foreseeable future. The sale of the generation assets does not affect the
terms of the coal supply agreements with Colstrip Units 1 through 4.
The Jewett Mine sells its entire production to the two 800 MW Limestone
Units owned by Reliant Energy.
Also refer to Part II, Item 7, "Management's Discussion and Analysis of
Financial Conditions and Results of Operations - Coal Operations" and Part II,
Item 8, "Financial Statements and Supplementary Data - Note 2 to the
Consolidated Financial Statements" for further information on the fuel supply
agreements.
The Nonutility oil and natural gas businesses compete with major oil and
natural gas companies and other independent and individual producers and
operators to acquire property, to develop, produce and market oil, natural gas
and natural gas liquids and to contract for equipment and services. The
Company believes it has production, development and long-term marketing
capabilities, experience in acquiring properties, and the financial resources
to enable it to compete effectively.
Most of CES' current revenues are derived from long-term power supply
contracts. Some long-term power supply contracts in the nonutility power
industry are under pressure from customers to reconsider pricing. CES'
strategy is to work with its partners and customers to attempt to mitigate
effects of contracts which may reflect pricing that is higher than current
market.
The telecommunications business competes with major and regional
companies to provide long distance, Internet, and private line network
services, and telecommunication equipment sales and maintenance. In this
competitive and evolving business, the telecommunication unit competes in part
by constructing and maintaining a low cost fiber network.
ENVIRONMENT:
For information on Environment see Part II, Item 7, "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Environmental Issues."
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EMPLOYEES:
At December 31, 1998, the Company and its subsidiaries employed
2,906 persons, including 370 employees at the jointly owned Colstrip Units 1
through 4. Of the 2,906 persons, 1,060 are members of collective bargaining
units consisting of 15 unions. Current union contracts will expire at various
times during the next three years. It is expected that approximately 500
employees, union and non-union, may be directly affected by the sale of the
Company's generating assets and the exit from electric trading and marketing
business. See Part II, Item 8, "Financial Statements and Supplementary Data -
Note 4 to the Consolidated Financial Statements" for further information
regarding the sale.
FOREIGN AND DOMESTIC OPERATIONS:
Financial information relating to the segment information for foreign and
domestic operations and export sales other than the information previously
disclosed regarding the Company's Canadian subsidiaries are not considered
material.
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ITEM 2. PROPERTIES
UTILITY OPERATIONS:
The Company's Mortgage and Deed of Trust (Mortgage) imposes a first
mortgage lien on all physical properties owned, exclusive of subsidiary company
assets, and certain property and assets specifically excepted. The Company's
use of the proceeds from the sale of its Montana generating facilities may be
subject to restrictions imposed by the Mortgage.
ELECTRIC PROPERTIES: The Company's Utility 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 683,000 kW, and 12 hydroelectric projects and one
storage dam, with total net median water capability of 474,400 kW. See Part
II, Item 8, "Financial Statements and Supplementary Data - Note 4 to the
Consolidated Financial Statements". The thermal units are (1) Colstrip Unit 3,
which has a net capability of 740,000 kW, of which the Company owns 222,000 kW,
(2) Colstrip Units 1 and 2, with a combined net capability of 614,000 kW, of
which the Utility owns 307,000 kW, and (3) the wholly owned 154,000 kW Corette
Plant. Western supplies all of the Colstrip coal requirements under long-term
contracts. The Corette Plant is supplied under a short-term contract from a
Wyoming mine. Reliability of service is enhanced by the location of
hydroelectric generation on two separate watersheds with different
precipitation characteristics and by various sources of thermal generation.
In addition to the Utility's hydroelectric and thermal resources, it
currently receives electricity through 18 contracts totaling 353,300 kW of firm
winter peak capacity. These contracts vary in type, size, seller, and ending
dates. See Part II, Item 8, "Financial Statements and Supplementary Data -
Notes 3 and 4 to the Consolidated Financial Statements" for more information
concerning commitments and the Company's intended sale of its generation
assets.
Hydroelectric projects are licensed by the FERC under licenses that
expire on varying dates through 2035. The Company is in the process of
relicensing its nine dams located on the Missouri and Madison rivers. See Part
II, Item 8, "Financial Statements and Supplementary Data - Note 2 to the
Consolidated Financial Statements".
At December 31, 1998, the Utility owned and operated 6,855 miles of
transmission lines and 15,818 miles of distribution lines.
The Company's transmission system serves a majority of the state of
Montana. The system integrates generation located in both the Columbia River
and Missouri River drainages and is directly interconnected with the
transmission systems of three investor owned utilities and two federal power
marketing agencies. The Company provides nondiscriminatory transmission
services pursuant to an open access transmission tariff filed with the FERC.
The following table represents average revenues received per kWh by
customer classification for electricity from all sources for the years 1998,
1997, and 1996.
Year Ended December 31
Customer Classification 1998 1997 1996
Residential $0.066 $0.064 $0.061
Commercial 0.060 0.059 0.055
Industrial 0.042 0.041 0.041
Sales for Resale 0.027 0.019 0.018
Government and Municipal 0.087 0.085 0.077
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NATURAL GAS PROPERTIES: The Utility currently produces minimal amounts
of natural gas from fields in southern Montana and Wyoming to maintain natural
gas storage leases and to supply fuel for electric generation. The Utility
transferred significantly all of its natural gas production properties in the
United States and all of its Canadian natural gas production properties to an
unregulated subsidiary on November 1, 1997, as a result of the Company's
natural gas restructuring filing with the PSC. The assets, liabilities,
equity, and results of operations of the regulated Utility's Canadian
subsidiary, Canadian-Montana Gas Company, Limited, have also been included in
the unregulated oil and natural gas operations as of that date.
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, 1998, the Gas Utility and its subsidiaries owned and
operated 2,103 miles of natural gas transmission lines and 3,527 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 Part II, Item 8, "Financial Statements and
Supplementary Data".
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
1996 5,055 230 6,749 4,694 950 4,850
1997 3,764 292 8,290 3,402 679 7,132
1998 - - 10,741 - - 9,440
The following table presents average revenues received per Mcf by
customer classification for natural gas from all sources for the years 1998,
1997, and 1996. Revenues per Mcf are computed based on volumes at varying
pressure bases as billed.
Year Ended December 31
Customer Classification 1998 1997 1996
Residential $4.77 $4.72 $4.72
Commercial 4.75 4.53 4.54
Industrial 4.47 4.30 4.32
Other gas utilities 4.06 4.04 3.41
NONUTILITY OPERATIONS:
COAL PROPERTIES: Western leases and produces coal from Montana
properties. Northwestern leases and produces lignite from properties in Texas.
</PAGE>
<PAGE>
Western's subsidiaries, Western SynCoal Company (SynCoal), and SynCoal Inc. own
a patented coal enhancement process. SynCoal and SynCoal Inc. own the Rosebud
SynCoal Partnership, which owns and operates a coal enhancement process
demonstration plant at the Rosebud Mine.
Western has coal mining leases covering approximately 508,287,000 proved
and probable, and recoverable, tons of surface-mineable coal reserves averaging
less than 1.6 pounds of sulfur dioxide per million Btu at Colstrip.
Approximately 218,328,000 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 153,400,000 proved and probable, and recoverable,
tons of surface-mineable lignite reserves. Northwestern has dedicated all of
these reserves to Reliant Energy, which owns two electric generating units
located adjacent to the mine.
In addition, Northwestern has proved and probable and recoverable
reserves totaling approximately 75,750,000 tons located in central Texas. These
reserves are in close proximity to the Jewett Mine.
The Company, through its wholly owned subsidiary, North Central Energy
owned approximately 36,000 acres of land in southern Colorado associated with
a former coal mining operation. The improvements have been removed or sold
and the land has been or is being reclaimed. The Company has sold
approximately 31,300 acres and is currently negotiating the sale of the
remaining property.
OIL AND NATURAL GAS PROPERTIES: Information on the Nonutility natural gas
and oil wells and the owned or leased acreage in which they are located, as of
December 31, 1998, is presented below.
United
States Canada
Gross productive natural gas wells 1,459 402
Net productive natural gas wells 1,065.40 308.95
Gross productive oil wells 84 124
Net productive oil wells 83.35 56.73
Gross producing acres 652,580 232,730
Net producing acres 490,544 190,399
Gross undeveloped acres 503,487 304,302
Net undeveloped acres 347,680 234,123
The wells located in Canada include multiple completions of 21 gross
productive natural gas wells or 18.25 net productive gas wells. The U.S. wells
listed above include multiple completions of 267 gross productive natural gas
wells or 205 net productive natural gas wells, and 2 gross productive oil wells
or 2 net productive oil wells.
The foregoing acreage located in the United States and Canada are
primarily in the Rocky Mountain States and Alberta.
During 1999, total exploration, acquisition, and development expenditures
(expense and capital) are anticipated to be approximately $34,498,000 in the
United States and approximately $20,493,000 in Canada.
</PAGE>
<PAGE>
The following table presents information on Nonutility oil and natural
gas exploratory and development wells drilled during 1998, 1997, and 1996.
United States Canada
1998 1997 1996 1998 1997 1996
Net productive natural gas
exploratory wells 0.96 1.86 0.33 3.34 4.30 0.55
Net productive oil
exploratory wells - 1.00 - - - 2.23
Net productive natural gas
development wells 53.84 41.50 2.58 73.50 1.30 1.83
Net productive oil
development wells - 2.87 - 0.98 15.11 9.78
Net dry exploratory wells 1.13 0.34 1.75 0.50 1.13 0.50
Net dry development wells 0.45 0.25 1.81 7.00 - 0.04
For information on properties acquired, see Part II, Item 8, "Financial
Statements and Supplementary Data".
No significant change has occurred and no event has taken place since
December 31, 1998, which would materially affect the estimated quantities of
proved reserves. For information pertaining to the net recoverable oil and
natural gas reserves, see Part II, Item 8, "Financial Statements and
Supplementary Data".
All Nonutility natural gas volumes are at a pressure base of 14.73 psia
at 60 degrees Fahrenheit.
Nonutility oil and natural gas reserve estimates have not been filed with
any other federal or any foreign government agency during the past twelve
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 1998, 1997, and
1996.
<TABLE>
<CAPTION>
Year Ended December 31
1998 1997 1996
United United United
States Canada States Canada States Canada
<S> <C> <C> <C> <C> <C> <C>
Average sales price:
Per Mcf of natural gas $ 1.45 $ 1.39 $ 1.94 $ 1.38 $ 1.54 $ 1.10
Per barrel of oil 12.96 11.36 20.42 18.77 19.74 16.88
Per barrel of natural gas liquids 9.10 10.12 10.12 15.64 10.56 14.44
Average production cost:
Per barrel of oil equivalent $ 3.95 $ 2.95 $ 4.13 $ 3.02 $ 3.94 $ 3.10
</TABLE>
NOTE: Natural gas production was converted to barrel of oil
equivalents based on a ratio of 6 Mcf to 1 barrel of oil.
Nonutility oil, natural gas, and natural gas liquids production was sold
under short-term and long-term contracts at posted prices or under forward
market arrangements. From 1997 to 1998, Nonutility average sales prices
changed due to fluctuations in the market. Nonutility average production cost
in the U.S. decreased as a result of the prior year inclusion of non-recurring
environmental and compliance work required on the processing facilities.
</PAGE>
<PAGE>
During 1997 the oil and gas operations completed two major acquisitions.
The Company purchased Vessels Energy's (Vessels) oil and gas assets in
Colorado's Denver-Julesburg (D-J) Basin. With the completion of this
acquisition late in 1997, annual hydrocarbon production in the D-J Basin
increased from 3,800 Mmcf of natural gas to approximately 5,600 Mmcf. The
acquisition included more than 565 wells, an 800-mile gas-gathering system, and
a natural gas processing and fractionating plant. The plant and gathering
system has been integrated with the Company's existing Fort Luption plant.
In 1997, the Company, through a Canadian subsidiary, purchased the stock
of Questar Exploration Incorporated. In January 1998, these assets were fully
integrated into the Canadian subsidiary. This acquisition is expected to
increase hydrocarbon production in Alberta by 6,144 Mmcf and 298,000 barrels of
natural gas liquids in 1998.
</PAGE>
<PAGE>
INDEPENDENT POWER PROPERTIES: Independent power operations sell power
from the Company's 242 MW Colstrip 4 leased interest and associated common and
transmission facilities. The leasehold interest and its related assets and
liabilities and sales contract obligations are intended to be sold with the
regulated electric generating facilities and power purchase contracts.
The Company, through its independent power operations, also partially
owns or has contract rights in a number of Nonutility power generation
projects.
<TABLE>
Projects in Operation:
<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 (a) Sweetwater, TX 49.9% 255 128 Texas Utilities U.S. Gypsum
(1989) Electric Co.
Tenaska-Paris(b) Paris, TX 10.0% 223 22 Texas Utilities Campbell
(1989) Electric Co. Soup Co.
Teesside United Kingdom 3.2%(c) 1,725 56 Various U.K. --
(1993) customers
Tenaska- Ferndale, WA 25.1% 245 61 Puget Sound Tosco Corp.
Ferndale (1994) Energy
Doctor Bird Old Harbour, 17.6% 74 13 Jamaica Public None
Jamaica Service
(1995)
Tenaska- Cleburne, TX 13.4% 258 35 Brazos REA City of
Cleburne (1997) Cleburne
TOTAL IPG SHARE OF RATED CAPACITY MW 315
<FN>
(a) CES is the managing partner of this project (through its wholly owned subsidiary
Enserch Development Corporation One, Inc).
(b) This co-generation facility has a long-term contract with NARCO (a Nonutility
subsidiary) to purchase a portion of its natural gas supply.
(c) Interest is the contractual right to utilize one-third of 168 MWs of capacity to
produce electricity for sale from a 1,725 MW natural gas-fired electric generating
facility.
</FN>
</TABLE>
</PAGE>
<PAGE>
<TABLE>
Projects Under Construction:
<CAPTION>
IPG
Share
of
Location Rated Rated
(Anticipated Capa- Capa-
Commercial Ownership city city Customer
Project Operation) or Interest MW MW Electricity Thermal
<S> <C> <C> <C> <C> <C> <C>
Tenaska Grimes County, 25% 830 208 Power Team, a None
Frontier Texas division of
(Grimes (2000) PECO Energy
County) Company
Uch Power Uch Pakistan 3.2% 586 19 Pakistan Water None
Limited (1999) & Power
Department
<CAPTION>
Projects Under Development:
IPG
Share
of
Rated Rated
Devel- Capa- Capa-
opment city city Customer
Project Location Interest MW MW Electricity Thermal
<S> <C> <C> <C> <C> <C> <C>
India- State of Andhra (d) 500 (d) State of Andhra None
Krishnapatnam Pradesh Pradesh
<FN>
(d) The ownership interest, if any, has not been determined.
</FN>
</TABLE>
TELECOMMUNICATIONS PROPERTIES: Touch America has an approximately
10,000-mile fiber-optic network ranging from Chicago west to Seattle, south to
Los Angeles, with both a coastal route via Portland and Sacramento and an
inland route via Boise, Salt Lake City, and Las Vegas, and from Denver north
through Wyoming and Montana to the Canadian border. Approximately 1,200 miles
of the network from Denver, Colorado to the Canadian border is held through an
indefeasible right of use (IRU) which extends through December 2010 and is
subject to two ten year extensions, at Touch America's option. Approximately
2,000 miles of the network from Seattle, to St. Paul, is held through an IRU
extending through early 2022. Touch America continues to expand its network
capacity. The additional miles of fiber network through a joint construction
effort among Touch America, Williams Companies, and Enron Corp. widened Touch
America's service territory to 14 states. The Company owns 12 Personal
Communication Services (PCS) licenses in 12 marketing areas between
Minneapolis, and Seattle, along the route of the fiber-optic network, which
presents an opportunity for wireless telephone service in that region. In
February 1998, the Company also acquired 24 Local Multipoint Distribution
Services (LMDS) licenses, in 24 marketing areas along the Seattle to
Minneapolis route and the Montana to Denver route.
Touch America's network is comprised of up-to-date fiber technology and
includes LS, SMF28, and LEAF fiber. The Company also has installed or is
upgrading to Dense Wave Division Multiplexing (DWDM) technology, which
essentially quadruples the capacity of each fiber strand.
</PAGE>
<PAGE>
ITEM 3. LEGAL PROCEEDINGS
The Company and North American Resources Company (NARCO), a wholly owned
subsidiary of Entech, are defendants in litigation initiated in October, 1995
by Paladin Associates, Inc. (Paladin), a natural gas broker transporting
natural gas on the Company's pipeline system. The litigation is pending in the
federal district court in Montana. Paladin alleges that the Company, NARCO,
and Northridge Petroleum Marketing, a Canadian corporation, violated antitrust
law, breached contractual obligations and committed torts for which Paladin is
entitled to collect monetary damages as remedies. Paladin is seeking actual
damages it estimates to be approximately $10,000,000, which if trebled would be
$30,000,000. In addition, it seeks punitive damages regarding its tort claims
in an amount the court may determine.
The Company and NARCO deny Paladin's allegations. Because the alleged
wrongful and illegal actions were subject to state and federal regulation, the
Company will assert a "state action" defense. Summary judgment motions and
motions to limit issues at the trial are pending the Court's determination.
Trial is scheduled in January 2000. While it is confident regarding this
matter, the Company cannot predict the ultimate outcome.
Litigation involving Entech's wholly owned subsidiary, Northwestern
Resources Company (Northwestern), and TCA Building Company (TCA) regarding the
validity of certain lignite leases in the "Donie Block" at the Jewett Mine is
pending. TCA initiated a state action against Northwestern in Texas district
court in 1995. Among TCA's allegations, were allegations that Northwestern
breached an obligation to assist TCA in mining its property; that
Northwestern's alleged promises underlying the obligation were tainted by
fraud; and, that Northwestern wrongfully interfered with TCA's solicitation of
bids to sell lignite. TCA also alleged that Northwestern otherwise wrongfully
interfered with a contract and a business opportunity for TCA to sell lignite.
TCA sought damages of between $8,000,000 and $13,500,000, in addition to
exemplary damages.
The Texas district court granted Northwestern's motion for summary
judgment on all of TCA's claims, except the claim that Northwestern wrongfully
interfered with TCA's efforts to solicit bids from mining companies that would
mine its lignite. Northwestern plans to file a new motion for summary
judgment. If the court denies Northwestern's motion, trial will occur in the
fall of 1999. Northwestern is confident regarding its case, however, it
cannot predict the ultimate outcome of this matter.
Refer to Part II, Item 7, "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Environmental Issues" and to
Part II, Item 8, "Financial Statements and Supplementary Data - Note 2 to the
Consolidated Financial Statements" for further information pertaining to legal
proceedings.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
EXECUTIVE OFFICERS OF THE REGISTRANT
The Montana Power Company Officers:
In 1998, R. P. Gannon, 54, was elected Chairman of the Board and Chief
Executive Officer. He had previously served as Chief Executive Officer and
President from 1997 - 1998, and as Chief Operating Officer - Utility Operations
from 1992-1996.
</PAGE>
<PAGE>
In 1996, J. P. Pederson, 56, was elected Vice President, Chief Financial
and Information Officer. He had previously served as Vice President and Chief
Financial Officer from 1991-1996.
In 1996, P. K. Merrell, 46, was elected Vice President, Human Resources
and Secretary. She had previously served as Vice President and Secretary from
1993-1996 and as Secretary from 1992-1993.
In 1991, M. E. Zimmerman, 50, was elected Vice President and General
Counsel.
In 1996, D. S. Smith, 55, was elected Controller. He had previously
served as Controller for Entech from 1988-1996.
In 1996, E. M. Senechal, 49, was elected Treasurer. She had previously
served as Vice President and Treasurer for Entech from 1984-1996.
In 1997, W. S. Dee, 58, was elected Vice President, Marketing. He had
previously been employed as a consultant with Leo Burnett, Inc., an advertising
agency, from 1993 to 1996.
Energy Services:
In 1996, J. D. Haffey, 53, was elected Executive Vice President and Chief
Operating Officer. He had previously served as Vice President - Administration
and Regulatory Affairs from 1993-1996 and as Vice President - Regulatory
Affairs for the Utility Division from 1987-1993.
In 1996, D. A. Johnson, 53, was elected Vice President, Distribution
Services. He had previously served as Vice President - Utility Services from
1993-1996 and as Vice President - Gas Supply and Transportation for the Utility
Division from 1984-1993.
In 1996, P. J. Cole, 41, was elected Vice President, Business Development
and Regulatory Affairs. He had previously served as Treasurer for the Utility
Division from 1993-1996 and as Assistant Treasurer from 1992-1993.
In 1997, W. A. Pascoe, 42, was elected Vice President, Transmission
Services. He had previously served as Assistant Vice President, Transmission
Services from May 1996 to April 1997 and as Manager of Transmission and Power
Transactions from 1990-1996.
Energy Supply:
In 1996, R. F. Cromer, 53, was elected Executive Vice President and Chief
Operating Officer. He had previously served as President and Chief Operating
Officer - Continental Energy Services, Inc. from 1992-1996.
In 1996, M. C. Enterline, 49, was elected Vice President - Colstrip
Project Division for the Energy Supply Division. He had previously served as
Vice President, Colstrip Project Division from 1995-1996, as Manager of
Business and Change Management from 1994-1995 and as Superintendent of Colstrip
Units l and 2 from 1988-1994.
Telecommunications:
In 1998, M. J. Meldahl, 49, was elected Executive Vice President and
Chief Operating Officer. He had previously served as Vice President,
Communication Services, and Vice President, Technology Division - Entech from
1988-1996.
</PAGE>
<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
1998 and 1997. The number of common shareholders of record on December 31,
1998, was 38,790.
Dividends
Declared
Per
1998 High Low Share
1st quarter $ 36.813 $ 29.063 $ 0.40
2nd quarter 38.500 33.813 0.40
3rd quarter 45.250 33.250 0.40
4th quarter 57.125 41.125 0.40
Dividends
Declared
Per
1997 High Low Share
1st quarter $ 22.625 $ 21.000 $ 0.40
2nd quarter 23.312 21.000 0.40
3rd quarter 26.625 21.000 0.40
4th quarter 32.250 24.125 0.40
</PAGE>
<PAGE>
<TABLE>
<CAPTION>
ITEM 6. SELECTED FINANCIAL DATA
The Montana Power Company and Subsidiaries
Balance Sheet Items (000)
1998 1997 1996
<S> <C> <C> <C>
Assets:
Utility plant $2,246,847 $2,216,198 $2,236,309
Less accumulated depreciation
and depletion 732,385 684,960 705,119
Net Utility plant 1,514,462 1,531,238 1,531,190
Nonutility property 864,981 781,406 666,679
Less accumulated depreciation
and depletion 297,933 260,567 256,489
Net Nonutility property 567,048 520,839 410,190
Total net plant and property 2,081,510 2,052,077 1,941,380
Other assets 846,585 753,819 756,835
Total Assets $2,928,095 $2,805,896 $2,698,215
Liabilities and Shareholders' Equity:
Common shareholders' equity $1,112,103 $1,037,534 $ 999,657
Unallocated stock held by trustee
for retirement savings plan (23,298) (25,945) (28,360)
Preferred stock 57,654 57,654 57,654
Mandatorily redeemable preferred
securities of trust 65,000 65,000 65,000
Long-term debt 698,329 653,168 633,339
Other liabilities 1,018,307 1,018,485 970,925
Total Liabilities $2,928,095 $2,805,896 $2,698,215
</TABLE>
</PAGE>
<PAGE>
<TABLE>
<CAPTION>
ITEM 6. SELECTED FINANCIAL DATA
The Montana Power Company and Subsidiaries
Balance Sheet Items (000)
1995 1994 1993
<S> <C> <C> <C>
Assets:
Utility plant $2,156,959 $2,021,981 $1,891,432
Less accumulated depreciation
and depletion 663,216 619,195 572,141
Net Utility plant 1,493,743 1,402,786 1,319,291
Nonutility property 633,079 600,299 596,769
Less accumulated depreciation
and depletion 252,612 207,486 198,951
Net Nonutility property 380,467 392,813 397,818
Total net plant and property 1,874,210 1,795,599 1,717,109
Other assets 711,881 717,098 668,918
Total Assets $2,586,091 $2,512,697 $2,386,027
Liabilities and Shareholders' Equity:
Common shareholders' equity $ 976,043 $ 988,100 $ 945,651
Unallocated stock held by trustee
for retirement savings plan (30,565) (32,580) (34,419)
Preferred stock 101,416 101,416 101,419
Mandatorily redeemable preferred
securities of trust
Long-term debt 616,574 588,876 571,870
Other liabilities 922,623 866,885 801,506
Total Liabilities $2,586,091 $2,512,697 $2,386,027
</TABLE>
</PAGE>
<PAGE>
<TABLE>
<CAPTION>
Income Statement Items (000)
1998 1997 1996
<S> <C> <C> <C>
Revenues $1,253,724 1,023,597 $ 973,208
Expenses:
Operations 528,196 420,032 386,775
Maintenance 81,064 82,702 75,409
Selling, general and administrative 128,741 116,054 104,535
Taxes other than income taxes 96,181 92,967 84,400
Depreciation, depletion and
amortization 114,267 95,340 86,403
Writedowns of long-lived assets
948,449 807,095 737,522
Income from operations 305,275 216,502 235,686
Interest expense and other income:
Interest 60,851 54,667 48,770
Distributions on mandatorily
redeemable preferred securities
of subsidiary trust 5,492 5,492
Other income - net (4,862) (34,159) (4,445)
61,481 26,000 44,325
Income taxes 78,174 61,870 71,975
Net income 165,620 128,632 119,386
Dividends on preferred stock 3,690 3,690 8,358
Net income available for common stock $ 161,930 $ 124,942 $ 111,028
Basic earnings per share of common
stock:
Utility operations $ 0.94 $ 1.08 $ 1.13
Nonutility operations 2.01 1.21 0.90
$ 2.95 $ 2.29 $ 2.03
Diluted earnings per share of
common stock $ 2.94 $ 2.28 $ 2.03
Dividends declared per share of
common stock $ 1.60 $ 1.60 $ 1.60
Average shares outstanding (000) 54,981 54,649 54,634
Earnings coverage of fixed
charges, SEC Method 3.34x 2.94x 3.21x
</TABLE>
</PAGE>
<PAGE>
<TABLE>
<CAPTION>
Income Statement Items (000)
1995 1994 1993
<S> <C> <C> <C>
Revenues $ 953,224 $1,005,970 $1,024,285
Expenses:
Operations 426,425 443,870 485,032
Maintenance 74,593 81,735 76,256
Selling, general and administrative 95,212 98,829 95,415
Taxes other than income taxes 86,599 95,950 89,254
Depreciation, depletion and
amortization 84,635 84,483 80,831
Writedowns of long-lived assets 74,297
841,761 804,867 826,788
Income from operations 111,463 201,103 197,497
Interest expense and other income:
Interest 43,656 42,817 48,023
Other income - net (10,704) (10,532) (11,857)
32,952 32,285 36,166
Income taxes 21,574 55,226 54,120
Net income 56,937 113,592 107,211
Dividends on preferred stock 7,227 7,227 4,353
Net income available for common stock $ 49,710 $ 106,365 $ 102,858
Basic earnings per share of common
stock:
Utility operations $ 1.22 $ 0.91 $ 1.07
Nonutility operations (0.30) 1.09 0.91
$ 0.92 $ 2.00 $ 1.98
Diluted earnings per share
of common stock $ 0.92 $ 2.00 $ 1.97
Dividends declared per share of
common stock $ 1.60 $ 1.60 $ 1.585
Average shares outstanding (000) 54,121 53,125 52,040
Earnings coverage of fixed
charges, SEC Method 1.96x 3.05x 2.86x
</TABLE>
</PAGE>
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Safe Harbor for Forward-Looking Statements:
The Company is including the following cautionary statements to make
applicable and take advantage of the safe harbor provisions of the Private
Securities Litigation Reform Act of 1995 for any forward-looking statements
made by, or on behalf, of the Company in this Annual Report on Form 10-K.
Forward-looking statements include statements concerning plans, objectives,
goals, strategies, future events or performance and underlying assumptions and
other statements, which are other than statements of historical facts. Such
forward-looking statements may be identified, without limitation, by the use
of the words "anticipates", "estimates", "expects", "intends", "believes," and
similar expressions. From time to time, the Company or one of its
subsidiaries individually may publish or otherwise make available forward-
looking statements of this nature. All such forward-looking statements,
whether written or oral, and whether made by or on behalf of the Company or
its subsidiaries, are expressly qualified by these cautionary statements and
any other cautionary statements which may accompany the forward-looking
statements. In addition, the Company disclaims any obligation to update any
forward-looking statements to reflect events or circumstances after the date
hereof.
Forward-looking statements made by the Company are subject to risks and
uncertainties that could cause actual results or events to differ materially
from those expressed in, or implied by, the forward-looking statements. These
forward-looking statements include, among others, statements concerning the
Company's revenue and cost trends, cost recovery, cost-reduction strategies
and anticipated outcomes, pricing strategies, planned capital expenditures,
financing needs, and availability, changes in the utility industry and the
impacts of the year 2000 issue. Investors or other users of the forward-
looking statements are cautioned that such statements are not a guarantee of
future performance by the Company and that such forward-looking statements are
subject to risks and uncertainties that could cause actual results to differ
materially from those expressed in, or implied by, such statements. Some, but
not all, of the risks and uncertainties include general economic and weather
conditions in the areas in which the Company has operations, competitive
factors and the impacts of restructuring in the electric, natural gas and
telecommunications industries, sanctity and enforceability of contracts,
market prices, environmental laws and policies, federal and state regulatory
and legislative actions, drilling successes in oil and natural gas operations,
changes in foreign trade and monetary policies, laws and regulations related
to foreign operations, tax rates and policies, rates of interest and changes
in accounting principles or the application of such principles to the Company.
Results of Operations:
The following discussion presents significant events or trends which have
had an effect on the operations of the Company during the years 1996 through
1998 or which are expected to have an impact on operating results in the
future.
Net Income Per Share of Common Stock:
The Company's net income available for common stock increased to
$161,930,000 in 1998 compared to $124,942,000 and $111,028,000 in 1997 and
1996, respectively. The following table shows the sources of consolidated net
income on a basic per share basis.
</PAGE>
<PAGE>
Year Ended December 31
1998 1997 1996
Utility Operations $ 0.94 $ 1.08 $ 1.13
Nonutility Operations 2.01 1.21 0.90
Consolidated $ 2.95 $ 2.29 $ 2.03
1998 Compared to 1997
Consolidated net income for the year ended December 31, 1998 was $2.95
per share, an increase of 66 cents or 29 percent over 1997 earnings of $2.29
per share.
The financial performance in 1998 reflects the Nonutility business
successes the Company had, which significantly offset the impacts of utility
deregulation and very weak oil and gas prices. The independent power and
telecommunications businesses provided a significant increase in annual
earnings. Besides the impact of deregulation, the Utility operations were
adversely affected by weather that was 6 percent warmer than normal.
Approximately 61 cents of the fourth-quarter earnings resulted from two
events. An arbitration panel ruled that the Bonneville Power Administration
breached the power purchase agreement with an independent power project at
Frederickson, Washington, in which the Company was an investor, resulting in
receipt of about $44,000,000. The sale of the Company's interest in the
Lockport, New York project netted approximately $14,000,000.
Increased rates, general business growth, and increased secondary sales
resulted in an increase of $17,000,000 in electric revenues, while natural gas
revenues decreased by $15,000,000 due mostly to customer choice and warmer
weather. Although lower maintenance expenses reduced power-supply costs, the
Utility also was affected by charges associated with curtailment of a benefit
plan and a writedown of land, which had been held for future generating plant
construction.
Nonutility earnings reflected the independent power transactions
mentioned earlier, as well as the settlement in the third quarter with a power
purchaser which increased earnings by approximately 16 cents per share.
Touch America, the Company's telecommunications subsidiary, recorded
$11,000,000 in gains from sales of dark fiber on its share of Portland to Los
Angeles expansion. Revenues from telecommunications operations increased to
nearly $100,000,000 from approximately $48,000,000 last year as a result of a
full year's operation of its expanded fiber-optic network linking Seattle and
Minneapolis-St. Paul and Denver to Canada, dark fiber sales and increased long-
distance revenue.
Coal tonnage sold increased by 6 percent, but prices were relatively flat
and higher revenues were mostly offset by increased operating expenses.
Oil and gas earnings declined when compared with 1997 primarily due to
production constraints and prices well below 1997 levels.
1997 Compared to 1996
Consolidated net income for the year ended December 31, 1997 was $2.29
per share, an increase of 26 cents over 1996 earnings of $2.03 per share.
</PAGE>
<PAGE>
Net gains from the sales of non-strategic oil, natural gas and coal
properties, and an investment in a Brazilian gold mine contributed
significantly to 1997 Nonutility increased earnings. Also, earnings from
telecommunications operations increased because the Company began receiving
revenues from its expanded fiber-optic network late in the third quarter.
Increased earnings from coal operations due to higher sales volumes to Colstrip
Units 3 and 4 were more than offset by price reductions resulting primarily
from a settlement with Puget Sound Energy (Puget). Earnings from independent
power operations decreased primarily due to reduced long-term power sales
revenues resulting from the Puget settlement and the absence of a gain
recognized in 1996 on the sale of a portion of an asset. Nonutility earnings
also benefited from the settlement of a long-standing income tax dispute with
the Internal Revenue Service (IRS).
Utility earnings decreased 5 cents per share in 1997 due primarily to
weather related reductions in general business revenues and higher power supply
costs resulting from increased steam plant maintenance, power purchases from
qualifying facilities and the settlement of a power supply contract dispute.
These negatives were partially offset by higher rates, customer growth, the
expiration in 1996 of two higher-priced power purchase contracts, and the
absence of severance costs recorded in the fourth quarter of 1996. The income
tax settlement mentioned above also positively impacted the Utility.
RECENT DEVELOPMENTS:
? Montana's Electric Industry Restructuring and Customer Choice Act (Electric
Act) and Natural Gas Restructuring and Customer Choice Act (Gas Act) became
law in May 1997.
? In November 1997, significantly all of the Utility natural gas production
assets were transferred to an unregulated affiliate. A fixed-price supply
contract through 2002 between the unregulated gas supply division and the
regulated distribution division to serve the remaining customers who have
not chosen other suppliers was implemented.
? In July 1998, the Company and the owners of Colstrip Units 3 and 4
generating plants settled coal contract disputes and future coal price
reopeners.
? In August 1998, the Company announced it is exiting the electric commodity
trading and marketing businesses, but will continue natural gas and natural
gas liquids commodity trading and marketing.
? In November 1998, the Company announced that it had entered into an
agreement (Agreement) to sell the Company's interest in 12 of its 13
Utility hydroelectric facilities, all four coal-fired thermal generating
plants, a Nonutility leasehold interest in Colstrip Unit 4, a power
purchase contract with Basin Electric Power Cooperative (Basin) and two
power exchange agreements.
? In December 1998, a special purpose entity (SPE) that is a wholly owned
subsidiary of the Company issued $62,700,000 of asset-backed securities,
known as transition bonds.
? In December 1998, the Company resolved a dispute with the purchaser of
lignite from the Jewett Mine involving the price of lignite and whether
other fuels could be substituted for lignite.
? In January 1999, the Company received and recorded $257,000,000 representing
prepayment of all amounts due for the remaining initial term of one
telecommunications contract.
See Item 8, "Financial Statements and Supplementary Data - Notes 4 and 9
to the Consolidated Financial Statements" for further information.
In 1998, the Company received 45 percent of its revenues and 33 percent
of its net income from regulated utility operations compared to 55 percent of
</PAGE>
<PAGE>
revenues and 49 percent of net income in 1997. The Company's diverse
unregulated businesses, engaged in coal, oil and natural gas, independent
power and telecommunications operations provided 55 percent of revenues and 67
percent of net income in 1998 compared to 45 percent of revenues and 51
percent of net income in 1997.
With the sale of the Company's interest in its electric generating
facilities and the exit from the electric trading and marketing business, the
Company no longer will be primarily a vertically integrated electric and
natural gas utility. The Company expects to maintain its traditional
regulated transmission and distribution utility businesses in Montana, the
coal and lignite mines that serve mine-mouth generating plants, the
independent power investments and operations and the natural gas exploration,
development, production, trading, and marketing. The Company will also
continue to invest in new opportunities such as telecommunications.
Competitive Environment: Utility Changes
Many state legislatures are considering the introduction of competition
in the electric and natural gas businesses. The Company's regulated electric
and natural gas businesses are already transitioning to competition in
accordance with the Electric Act and the Gas Act, which became law in May
1997. The move to competition provides for customer choice to wholesale and
retail customers for energy commodity and related services.
Electric Utility
General - The Electric Act provided for choice of electricity supply for
the Company's large industrial customers by July 1, 1998, for pilot programs
for residential and small commercial customers beginning November 2, 1998, and
for all customers no later than July 1, 2002. Through December 1998,
approximately 50 customers, representing approximately 10 percent of the
Utility's pre-choice load have chosen alternate suppliers. Transmission and
distribution services will remain fully regulated by Federal Energy Regulatory
Commission (FERC) and/or the Montana Public Service Commission (PSC). The
Electric Act also defines the PSC's role in regulating distribution services,
licensing suppliers in the state, and promulgating rules regarding anti-
competitive and abusive practices.
Generation and Supply - Proceeds from the sale of the interests in the
generating plants, and the Basin and exchange contracts will vary depending
upon various factors, and are anticipated to be between $740,000,000 and
$988,000,000. These factors include the amount of the Company's related
transmission facilities included in the sale and the sales by other parties of
their interests in the Colstrip Units.
Based on the Company's current estimate of proceeds and carrying value
of the Nonutility assets related to the Colstrip Unit 4 leasehold interest,
the Company expects to recognize an immaterial gain on the sale. The
leasehold interest is currently accounted for as an operating lease with
annual lease payments of approximately $32,000,000 over the remaining term of
the lease.
With respect to the sale of the regulated generation assets, the Company
first expects to recover the book value of those assets, estimated to be
$550,000,000 and the costs of the sale transaction. Proceeds in excess of the
book value and transaction costs are expected to reduce the amounts to be
collected from ratepayers in the form of competitive transition charges (CTC).
Included in the CTC's are the power purchase contracts with qualifying
facilities (QF) which could result in above-market costs currently estimated
between $300,000,000 and $500,000,000 throughout their duration, the
</PAGE>
<PAGE>
generation regulatory assets which are currently estimated at $150,000,000 and
the above-market generation costs over the transition period, if any. The
divestiture of these generating plants and the sale of the contract for
purchased power from Basin also will help to largely resolve issues associated
with the Company's transition costs in a filing currently before the PSC.
The Company is currently evaluating options for dealing with the QF
contracts, which were not included in the sales agreement. Divestiture of
these QF contracts could take the form of a buy-down, buy-out or a
restructuring of the contract. The lowest cost option with the most favorable
terms will be selected in this process. Owners of the QF contracts must, by
contract, approve any reassignment of the contract and FERC approval may also
be necessary. Since recovery of above-market qualifying facility power-
purchase contract costs was specifically provided in the legislation, the
Company does not expect the exclusion of these contracts from the sale to have
a material impact on results of operations.
The Company is also evaluating potential options with regard to the
Milltown Dam, which was not included in the sales agreement. The Company is a
Potentially Responsible Party (PRP) for environmental remediation at the
Milltown Dam Site, where toxic heavy metals are in the silts resting behind
the dam. However, because of federal legislation specifically regarding
Milltown, the Company's position is that it has no responsibility for any
remediation of the alleged releases under CERCLA.
The generation sale agreement includes transition service agreements
under which the Company will purchase electricity to supply customers in its
service territory who have not chosen, or have not had an opportunity to
choose to purchase energy from another power supplier throughout the
transition period. Once the transition period is complete, the Electric
Utility may be required to offer electric supply as the supplier of last
resort for customers who have not chosen other suppliers. The Company
anticipates that any costs related to this electric supply would be recovered
through rates charged to those customers.
The regulated generation assets to be sold currently comprise
approximately $500,000,000 of the Utility's plant in service upon which it was
allowed to earn a return of approximately 9 percent. Actual after-tax rate of
return earned on the Company's electric plant in service was approximately 8.5
percent for the year ended December 31, 1998. However, since specific classes
of assets cannot be separated in a regulated environment with fully bundled
rates charged to customers, the Company cannot accurately estimate the
separate results of operations for these generation assets.
The Company is evaluating numerous possible uses for the proceeds
realized from the sale. Proceeds could be used to reduce outstanding debt,
buy back a number of the Company's outstanding common or preferred shares of
stock or proceeds up to the book value of the assets sold may be invested in
any of the Company's existing business segments or new ventures. The
Company's Mortgage and Deed of Trust imposes a lien on all physical properties
including the generation assets and pollution control equipment on some of the
thermal generating facilities, therefore, restrictions may exist on the use of
proceeds.
Although the sale is subject to the satisfaction of various conditions
and the receipt of required regulatory approvals, the Company anticipates this
transaction will be completed by the end of 1999.
The Company has several commitments to sell electricity under contracts,
which have terms expiring over the next six years. One such contract includes
a fixed-price for a portion of the deliveries. When the sale of the Company's
generation assets is finalized, and to the extent this contract is not
</PAGE>
<PAGE>
addressed in the electric restructuring transition process, the Company will
be subject to the commodity price risks associated with supplying that portion
of the contract. The Company is currently evaluating the potential options
related to this contract. However, due to the uncertainties relating to the
supply requirements under the contract, the timing of sale of the generation
assets and the eventual outcome of the electric restructuring process, the
Company is unable at this time to determine the potential future impacts of
this contract on the Company's results of operations.
See Item 8, "Financial Statements and Supplementary Data - Notes 3 and 4
to the Consolidated Financial Statements" for further information.
Transmission -- In 1996, the FERC issued Order Nos. 888 and 889
requiring Open-Access Non-Discriminatory Transmission Services by Public and
Transmitting Utilities, and stating standards of conduct regarding open
access. These orders require public utilities owning transmission lines to
file open-access tariffs making transmission service available to all buyers
and sellers of wholesale electricity; require utilities to use the tariffs for
their own wholesale sales and purchases; and allow utilities to recover
wholesale stranded costs, subject to certain conditions.
The Company's FERC open-access transmission tariffs became effective in
July 1996. In January 1997, the Company adopted Standards of Conduct and
established an Open-Access Same-time Information System (OASIS) to comply with
FERC Order No. 889. The Company provides nondiscriminatory transmission
services pursuant to this open access transmission tariff filed with the FERC.
FERC has announced its intention to conduct a rulemaking during 1999 on
FERC's authority to require transmission owners to participate in regional
transmission entities such as an independent system operators (ISO) or
independent transmission companies.
Distribution -- Distribution service will continue to be regulated by
the PSC and provided by the Company's regulated Distribution operations. The
Company anticipates competition for these services from large customers
bypassing the Company's system and municipalities as well as on-site or
distributed generation.
Wholesale -- The Electric Utility currently provides wholesale service
to Central Montana Electric Power Cooperative, Inc. (Central), which manages a
contract for purchases of power from the Electric Utility for a group of
Montana cooperatives. Central has terminated its contract with the Company,
effective June 2000, and will acquire its energy from another supplier.
Central's 120 MW load approximates 6 percent of the Company's pre-choice
system load.
Natural Gas Utility
General - The changes which are occurring on the Company's natural gas
business will have a significant operational impact on the Company as it faces
greater competition for resources and for customers. Competitors include
privately owned independent natural gas producers and suppliers, and other
investor-owned utilities and their unregulated subsidiaries.
Because the Utility's investment in natural gas production properties
has been removed from rate base, there will be a corresponding decrease in
Utility operating income. When combined with other items in the filing, the
November 1997 PSC restructuring order resulted in a net reduction in annual
natural gas revenues by $2,800,000, or 2.3 percent, and froze base rates for
two years. A non-bypassable Universal System Benefits Charge for public
purpose programs was also implemented.
</PAGE>
<PAGE>
The Company does not anticipate a materially negative impact on earnings
due to the reduction in natural gas supply revenues from customers choosing
other suppliers, since the decrease is expected to be offset by reduced supply
costs, CTC charges, transportation and distribution revenues and transition
bond financing savings. However, there can be no assurance that such trends
will not have an adverse impact on the Company's Utility natural gas business
in the future.
The Gas Act allows utilities to voluntarily offer customers choice of
natural gas supply and authorizes the use of transition bonds as a method of
financing transition obligations at lower costs. The Gas Act also defines the
role the PSC will have in regulating transmission and distribution services,
licensing suppliers in the state, and promulgating rules regarding anti-
competitive and abusive practices.
Production -- As previously discussed, in 1997, the Company's
unregulated Supply Division assumed ownership of significantly all of the
natural gas production assets, except delivered gas purchase contracts, which
have been retained by the regulated Natural Gas Utility. The difference
between book value and the agreed-upon transfer value, and the regulatory
assets associated with natural gas production are being recovered over 15
years from transmission and distribution customers as a component of CTC
charges. At December 31, 1998, approximately $56,000,000 of CTC charges had
not yet been collected from customers.
As a result of the transfer of Utility natural gas production assets
discussed previously, the assets, liabilities, equity, and results of
operations of the regulated Utility's Canadian subsidiary, Canadian-Montana
Gas Company, Limited, have been included in the unregulated oil and natural
gas operations as of that date. Production from these transferred properties
is now sold in large part back to the Utility distribution operations under a
fixed price contract through the transition period ending July 1, 2002. After
this transition period, the contract terminates and production will be sold in
the competitive market in the unregulated operations.
Transmission, Storage and Distribution -- Transmission, storage, and
distribution services will remain regulated, and rates for such services will
continue to be subject to approval by the PSC and/or FERC.
</PAGE>
<PAGE>
<TABLE>
<CAPTION>
UTILITY OPERATIONS
Year Ended December 31
1998 1997 1996
Thousands of Dollars
ELECTRIC UTILITY:
<S> <C> <C> <C>
REVENUES:
Revenues $ 450,719 $ 435,986 $ 430,171
Intersegment revenues 7,576 4,685 5,793
458,295 440,671 435,964
EXPENSES:
Power supply 137,415 143,224 138,679
Transmission and distribution 40,182 38,359 37,255
Selling, general and administrative 53,017 50,872 47,691
Taxes other than income taxes 46,316 45,540 43,568
Depreciation and amortization 56,524 51,674 46,648
333,454 329,669 313,841
INCOME FROM ELECTRIC OPERATIONS 124,841 111,002 122,123
NATURAL GAS UTILITY:
REVENUES:
Revenues (other than gas supply
cost revenues) 75,112 105,220 107,782
Gas supply cost revenues 31,940 17,135 20,746
Intersegment revenues 727 588 649
107,779 122,943 129,177
EXPENSES:
Gas supply costs 31,940 17,135 20,746
Other production, gathering and exploration 2,284 8,572 9,966
Transmission and distribution 15,556 14,163 14,679
Selling, general and administrative 20,191 17,889 16,476
Taxes other than income taxes 14,084 15,251 14,842
Depreciation, depletion and amortization 8,705 11,939 11,638
92,760 84,949 88,347
INCOME FROM GAS OPERATIONS 15,019 37,994 40,830
INTEREST EXPENSE AND OTHER INCOME:
Interest 56,357 52,191 46,663
Distributions on company obligated
mandatorily redeemable preferred
securities of subsidiary trust 5,493 5,492
Other income - net (3,724) (7,128) (402)
58,126 50,555 46,261
INCOME BEFORE INCOME TAXES 81,734 98,441 116,692
INCOME TAXES 26,559 35,643 46,687
DIVIDENDS ON PREFERRED STOCK 3,690 3,690 8,358
UTILITY NET INCOME AVAILABLE FOR COMMON STOCK $ 51,485 $ 59,108 $ 61,647
</TABLE>
</PAGE>
<PAGE>
UTILITY OPERATIONS:
Weather affects the demand for electricity and natural gas, especially
among residential and commercial customers. Very cold winters increase demand,
while mild winter weather reduces demand. The weather's effect is measured
using degree-days. A degree-day is the difference between the average daily
actual temperature and a baseline temperature of 65 degrees. Heating degree-
days result when the average daily actual temperature is less than the
baseline. As measured by heating degree-days, the 1998 temperatures for the
Company's service territory were 6 percent warmer than 1997 and 6 percent
warmer than the historic average. Temperatures in 1997 were 10 percent warmer
than 1996 and comparable to the historic average.
Weather, streamflow conditions, and the wholesale power markets in the
Northwest and California influence the Company's electric wholesale revenues,
power-purchase expenses and output of thermal generation. Regional opportunity
purchased-power prices were higher in 1998 than 1997 and consequently, the
Company did not displace its thermal generation as it has in prior years.
Margins on off-system sales are tightening as competition among suppliers
increases.
Accounting for the Effects of Regulation:
For its regulated operations, the Company follows Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain
Types of Regulation." As a result, the Company has recorded regulatory assets
and liabilities that are intended to be recognized in expenses and revenues in
future periods. Should any portion of these operations cease to meet the
criteria of SFAS No. 71 for various reasons, including changes in regulation
or a change in the competitive environment for those operations, the Company
would discontinue the application of SFAS No. 71 for that portion of the
operations for which the statement no longer applied. If the Company was to
discontinue application of SFAS No. 71 for all or a portion of its operations,
the regulatory assets and liabilities related to those portions would have to
be eliminated from the balance sheet and included in income in the period when
the discontinuation occurred unless recovery of those costs was provided
through rates charged to those customers in a portion of the business that
remains regulated. In conjunction with the ongoing changes in the electric
and natural gas industries, the Company will continue to evaluate the
applicability of this accounting principle to those businesses.
As a consequence of the issuance by the PSC of the natural gas
restructuring order and the related transfer of significantly all of the
Utility natural gas production assets to the Company's unregulated operations,
the Company's natural gas production assets were removed from SFAS No. 71
accounting in the fourth quarter of 1997. Recovery of the Company's existing
natural gas production related regulatory assets and the difference between
book value and the agreed-upon transfer value was provided in the PSC order as
competitive transition charges (CTC). Accordingly, the CTC's are currently
being recovered through rates over a 15-year period. Therefore the
discontinuance of SFAS No. 71 for these assets did not have a material impact
on the results of operations for 1997.
The timing of the removal of the electric generating assets from SFAS No.
71 is expected to coincide with the conclusion of the sale of the assets, which
is anticipated to be completed by the end of 1999. The Company expects a
decision on the remaining issues, including the amount of transition costs,
once the sale is completed. Recovery of existing regulatory assets related to
electric generation, subject to regulatory review, is provided in the electric
restructuring legislation. Based upon its anticipated recovery of these
regulatory assets, the Company believes that the discontinuation of regulatory
accounting for the generation assets will not have a material impact on the
Company's financial position or results of operations. See Item 8, "Financial
Statements and Supplementary Data - Notes 1 and 4 to the Consolidated
Financial Statements".
</PAGE>
<PAGE>
<TABLE>
<CAPTION>
Electric Utility:
1998 Compared to 1997
Revenues and
Power Supply Expenses Volumes Customers
(Thousands of Dollars) (Thousands of MWh) (Yearly Average)
1998 1997 1998 1997 1998 1997
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues:
Residential,
Commercial &
Government $280,462 $270,276 4% 4,424 4,342 2% 280,023 275,916 1%
Industrial 108,053 107,038 1% 2,580 2,580 0% 3,508 3,339 5%
General Business 388,515 377,314 3% 7,004 6,922 1% 283,531 279,255 2%
Sales to Other
Utilities 48,111 47,178 2% 1,902 2,663 (29)% 73 84 (13)%
Other 14,093 11,494 23%
Intersegment 7,576 4,685 62% 125 149 (16)% 230 230 0%
Total $458,295 $440,671 4% 9,031 9,734 (7)% 283,834 279,569 2%
Power Supply
Expenses:
Hydroelectric $ 22,266 $ 22,887 (3)% 3,742 4,126 (9)%
Steam 50,952 57,057 (11)% 4,516 4,290 5%
Purchases
and Other 64,197 63,280 1% 2,058 2,538 (19)%
Total Power Supply $137,415 $143,224 (4)% 10,316 10,954 (6)%
Dollars Per kWh $ 1.332 $ 1.308
</TABLE>
Revenues from general business customers increased during the period
primarily due to higher rates. As a result of electric deregulation,
beginning July 1, 1998, electric trading activity, including buying and
selling of electricity in the secondary markets, was conducted as a Nonutility
activity. However, sales of electricity generated by the Company, in excess
of the needs for core customers, continue to be reflected in "sales to other
utilities" in the table above.
Sales to other utilities increased as a result of an increase in average
prices and increased steam generation due to decreased plant maintenance. This
increase was despite a decrease in volumes sold due to the transfer of the
electric trading activity to Nonutility operations in the third quarter of
1998.
Other revenues increased as a result of an actuarial pension plan
adjustment along with increased secondary sales.
Power supply expenses decreased primarily due to lower steam maintenance,
which was partially offset by increased purchased power costs. Although less
power was purchased through electric trading activities as a result of the
transfer of this electric trading activity to Nonutility operations, purchased
power costs increased due to higher prices.
Increased selling, general and administrative (SG&A) expenses resulted
primarily from increased outsourcing costs and higher benefit charges
associated with curtailment of a benefit plan. Partially offsetting the
increase was the absence of severance costs in the current year. Depreciation
expense increased primarily due to the write-down of land held for future use
and software costs in accordance with SFAS No. 121.
</PAGE>
<PAGE>
<TABLE>
<CAPTION>
1997 Compared to 1996
Revenues and
Power Supply Expenses Volumes Customers
(Thousands of Dollars) (Thousands of MWh) (Yearly Average)
1997 1996 1997 1996 1997 1996
Revenues:
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Residential,
Commercial &
Government $270,276 $257,625 5% 4,342 4,414 (2)% 275,916 271,683 2%
Industrial 107,038 108,156 (1)% 2,580 2,580 0% 3,339 3,257 3%
General Business 377,314 365,781 3% 6,922 6,994 (1)% 279,255 274,940 2%
Sales to Other
Utilities 47,178 52,125 (9)% 2,663 2,761 (4)% 84 79 6%
Other 11,494 12,265 (6)%
Intersegment 4,685 5,793 (19)% 149 332 (55)% 230 230 0%
Total $440,671 $435,964 1% 9,734 10,087 (3)% 279,569 275,249 2%
Power Supply
Expenses:
Hydroelectric $ 22,887 $ 19,423 18% 4,126 4,064 2%
Steam 57,057 47,185 21% 4,290 4,272 0%
Purchases
and Other 63,280 70,209 (10)% 2,538 2,557 (1)%
Total Power Supply $143,224 $136,817 4% 10,954 10,893 1%
Dollars Per kWh $ 1.308 $ 1.256
</TABLE>
Revenues from general business customers increased in 1997 primarily due
to higher tariff rates and customer growth. A weather-related reduction in
volumes sold moderated this increase. Reduced sales to other utilities
resulting from the expiration of a high-priced firm sales contract in the
second quarter of 1996 were partially offset by higher prices and greater
volumes sold in the wholesale electric market. An actuarial pension plan
adjustment decreased other revenues as well as SG&A expenses.
Steam generation expenses were up in 1997 due to additional maintenance
costs at the Corette plant. Decreases in purchases and other power supply
expenses were mainly related to the expiration of two high-priced firm purchase
contracts in the first half of 1996 and reduced opportunity purchase prices.
Partially offsetting these decreases were higher qualifying facility rates, the
settlement of a supply contract dispute and the absence of a 1996 credit from a
third party who delivers energy to the Company's customers. Increased SG&A
expenses resulted primarily from increased consulting and computer upgrades,
reduced billing to third parties and marketing costs previously classified as
other operating expenses. The pension plan adjustment mentioned above and the
absence of 1996 permanent employee reduction costs moderated the SG&A expense
increase. Depreciation expense increased as a result of greater plant
investment and a mid-1996 change in the PSC-approved depreciation rates.
</PAGE>
<PAGE>
<TABLE>
<CAPTION>
Natural Gas Utility:
1998 Compared to 1997
Revenues Volumes Customers
(Thousands of Dollars) (Thousands of Mmcf) (Yearly Average)
1998 1997 1998 1997 1998 1997
Revenues:
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Residential,
Commercial &
Government $ 92,128 $105,246 (12)% 19,355 22,695 (15)% 145,172 141,130 3%
Industrial 1,380 2,659 (48)% 308 618 (50)% 394 399 (1)%
Subtotal 93,508 107,905 (13)% 19,663 23,313 (16)% 145,566 141,529 3%
Gas Supply Cost
Revenues (GSC) (31,940) (17,135) (86)%
General Business
without GSC 61,568 90,770 (32)% 19,663 23,313 (16)% 145,566 141,529 3%
Sales to Other
Utilities 606 786 (23)% 201 195 3% 3 4 (25)%
Transportation 13,497 9,919 36% 27,785 26,020 7% 23 42 (45)%
Other (559) 3,745 (115)%
Total $ 75,112 $105,220 (29)% 47,649 49,528 (4)% 145,592 141,575 3%
</TABLE>
Natural gas revenues, excluding gas supply cost revenues, decreased in
1998 primarily due to a weather related reduction in volumes sold. Slightly
higher tariff rates and customer growth partially moderated the revenue
decrease. A decrease in other revenues, due to the November 1997
restructuring of the natural gas utility and an increase in gas cost refunds
to the customer, was partially offset by an increase in transportation revenue
primarily as a result of a PSC order allowing natural gas customers with
annual loads greater than 5,000 dekatherms (Dkt) the right to choose their own
supplier effective November 1, 1997.
The restructuring of the natural gas utility also affected its operating
results for the period. In November 1997, significantly all of the Company's
regulated natural gas production assets were transferred to its Nonutility
affiliate, MP Gas. Since that time, operating expenses related to the
transferred assets have been included in the Company's Nonutility oil and
natural gas operations. The absence of these expenses, which are now
recognized in the Nonutility operations, resulted in reduced non-gas supply
cost revenues and expenses and other production, gathering and exploration
costs.
As a result of the restructuring mentioned above, the Utility has
contracted to purchase most of its gas from its Nonutility affiliate. The
contract price includes costs associated with the transferred assets and
returns on those assets. Gas cost revenues and expenses, which are always
equal due to regulated rate and accounting procedures, increased throughout
1998 due to the new purchase contract. Amortizations of prior period under-
collections also contributed to the increase.
Higher SG&A expense for the period resulted primarily from increased
amortizations of regulatory assets, which are currently being collected in
rates, as well as higher outsourcing charges.
Depreciation, depletion, and amortization decreased due to the transfer
of the natural gas production properties as discussed above.
</PAGE>
<PAGE>
<TABLE>
<CAPTION>
1997 Compared to 1996
Revenues Volumes Customers
(Thousands of Dollars) (Thousands of Mmcf) (Yearly Average)
1997 1996 1997 1996 1997 1996
Revenues:
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Residential,
Commercial &
Government $105,246 $109,795 (4)% 22,695 23,690 (4)% 141,130 137,222 3%
Industrial 2,659 2,921 (9)% 618 675 (8)% 399 421 (5)%
Subtotal 107,905 112,716 (4)% 23,313 24,365 (4)% 141,529 137,643 3%
Gas Supply Cost
Revenues (GSC) (17,135) (20,746) (17)%
General Business
without GSC 90,770 91,970 (1)% 23,313 24,365 (4)% 141,529 137,643 3%
Sales to Other
Utilities 786 868 (9)% 195 255 (24)% 4 3 33%
Transportation 9,919 9,582 4% 26,020 26,969 (4)% 42 42 0%
Other 3,745 5,362 (30)%
Total $105,220 $107,782 (2)% 49,528 51,589 (4)% 141,575 137,688 3%
</TABLE>
Natural gas revenues, excluding gas supply cost revenues, decreased in
1997 primarily due to a weather related reduction in volumes sold. Slightly
higher tariff rates and customer growth partially moderated the revenue
decrease. An actuarial pension plan adjustment decreased other revenues as
well as SG&A expenses. This SG&A adjustment, however, was more than offset by
increased consulting and computer upgrades which were moderated by the absence
of 1996 permanent employee reduction costs.
Other Income and Expense, Income Taxes and Preferred Dividends:
1998 Compared to 1997
Interest expense increased in 1998 due to additional long-term borrowing
and interest accrued on the Kerr Project mitigation liability as well as
interest on a federal income tax audit. This was partially offset by a
decrease in short-term borrowing and the absence of interest paid in 1997 in
conjunction with a contract settlement. Decreases in other income related to
interest income on the 1997 settlement of a dispute with the IRS which was
partially offset by the 1997 costs associated with the Flint Creek Dam
transfer to Granite County, Montana.
Income tax expense decreased in 1998 as a result of lower before-tax net
income and a reduced effective tax rate.
1997 Compared to 1996
Interest expense increased in 1997 due to additional borrowing and
interest accrued on the Kerr Project mitigation liability, which was recorded
in the second quarter of 1997. Increases in other income related to the
interest income on the 1997 settlement of a dispute with the IRS and the
absence of a 1996 loss on written-off property were partially offset by costs
associated with the Flint Creek Dam transfer to Granite County, Montana in the
second quarter of 1997.
Income tax expense declined in 1997 as a result of lower before-tax net
income, a reduced effective tax rate, and decreased tax accruals resulting
from the settlement of a dispute with the IRS.
</PAGE>
<PAGE>
Preferred dividends decreased in 1997 because the Company repurchased
and retired 139,200 shares of its $6.875 series and redeemed all outstanding
shares of its $2.15 series during the fourth quarter of 1996.
</PAGE>
<PAGE>
<TABLE>
<CAPTION>
NONUTILITY OPERATIONS
Year Ended December 31
1998 1997 1996
Thousands of Dollars
COAL:
<S> <C> <C> <C>
REVENUES:
Revenues $ 177,961 $ 167,623 $ 163,901
Intersegment revenues 38,796 34,164 31,448
216,757 201,787 195,349
EXPENSES:
Operations and maintenance 132,963 119,085 115,859
Selling, general and administrative 20,588 21,355 21,373
Taxes other than income taxes 24,050 23,455 20,883
Depreciation, depletion and amortization 6,596 9,043 5,653
184,197 172,938 163,768
INCOME FROM COAL OPERATIONS 32,560 28,849 31,581
OIL AND NATURAL GAS:
REVENUES:
Revenues: 208,116 163,656 124,532
Intersegment revenues 24,597 3,120 293
232,713 166,776 124,825
EXPENSES:
Operations and maintenance 176,981 118,266 76,975
Selling, general and administrative 20,925 10,723 10,152
Taxes other than income taxes 4,908 4,555 2,931
Depreciation, depletion and amortization 22,259 16,922 17,080
225,073 150,466 107,138
INCOME FROM OIL AND
NATURAL GAS OPERATIONS 7,640 16,310 17,687
INDEPENDENT POWER:
REVENUES:
Revenues 73,707 70,932 75,322
Earnings from unconsolidated investments 89,525 14,980 21,174
Intersegment sales 2,014 1,820 1,426
165,246 87,732 97,922
EXPENSES:
Operations and maintenance 65,009 63,837 64,274
Selling, general and administrative 4,746 4,290 5,223
Taxes other than income taxes 1,767 1,868 1,783
Depreciation and amortization 9,005 2,774 3,793
80,527 72,769 75,073
INCOME FROM INDEPENDENT POWER OPERATIONS $ 84,719 $ 14,963 $ 22,849
</TABLE>
</PAGE>
<PAGE>
<TABLE>
<CAPTION>
NONUTILITY OPERATIONS
Year Ended December 31
1998 1997 1996
Thousands of Dollars
TELECOMMUNICATIONS:
<S> <C> <C> <C>
REVENUES:
Revenues $ 87,748 $ 46,691 $ 27,641
Earnings from unconsolidated investments 10,909 435
Intersegment revenues 1,298 799 133
99,955 47,925 27,774
EXPENSES:
Operations and maintenance 27,110 22,385 18,316
Selling, general and administrative 12,172 8,825 5,498
Taxes other than income taxes 3,623 2,294 392
Depreciation and amortization 7,090 2,494 911
49,995 35,998 25,117
INCOME FROM TELECOMMUNICATIONS OPERATIONS. 49,960 11,927 2,657
OTHER OPERATIONS:
REVENUES:
Revenues 47,988 939 1,939
Intersegment revenues 1,913 5,719 44
49,901 6,658 1,983
EXPENSES:
Operations and maintenance 51,634 3,780 1,207
Selling, general and administrative 2,211 6,922 2,137
Taxes other than income taxes 1,431 6
Depreciation and amortization 4,089 493 679
59,365 11,201 4,023
LOSS FROM OTHER OPERATIONS (9,464) (4,543) (2,040)
INTEREST EXPENSE AND OTHER INCOME:
Interest 11,420 6,605 4,829
Other income - net (8,065) (31,160) (6,764)
3,355 (24,555) (1,935)
INCOME BEFORE INCOME TAXES 162,060 92,061 74,669
INCOME TAXES 51,615 26,227 25,288
NONUTILITY NET INCOME AVAILABLE FOR
COMMON STOCK $ 110,445 $ 65,834 $ 49,381
</TABLE>
</PAGE>
<PAGE>
NONUTILITY OPERATIONS:
Coal Operations:
Current production from the Rosebud and Jewett Mines is sold under long-
term contracts to mine-mouth customers. In 1998, the Company and the owners
of Colstrip Units 3 and 4 generating plants settled coal contract disputes and
future coal price reopeners. The resolution provides the Company with a
stable earnings platform by eliminating all future price reopeners and an
opportunity to enhance revenues through performance incentives, while reducing
the plants' delivered coal prices. The Company remains the full requirements
fuel supplier for all four Colstrip plants. Until mid-year 2000, the Company
will realize a modest profit reduction to account for the gross inequity
settlement and the elimination of over collections by the Company in some cost
categories. Under the new supply and transportation agreements, the delivered
coal price to Units 3 and 4 will be significantly reduced from current price
levels in increments beginning July 31, 2000 and 2001. With the pricing
structure in effect on those dates, the Company's contribution to consolidated
pretax income from the Colstrip 3 and 4 contracts is expected to be reduced by
approximately $12,000,000. With the elimination of the price reopeners and
the adoption of the new pricing structure, the Company does not anticipate any
further adjustments to profitability on these contracts throughout their
terms, which run through December 2019. The Company does not expect the sale
of its interests in the generating plants to significantly impact the results
of operations from the coal sales.
In December 1998, the Company resolved a dispute with the purchaser of
lignite from the Jewett Mine. The dispute between the two companies revolved
around the price of lignite and whether other fuels could be substituted for
lignite. The Company expects that if the market value of fuel stays flat when
the agreement is fully implemented after four years, the competitive-pricing
structure could result in a reduction of the Company's pretax income of
approximately $7,000,000. The Company can mitigate this impact through
efficiency and cost-savings measures.
1998 Compared to 1997
Income from coal operations increased by $3,700,000 primarily due to an
increase in the number of tons sold. Revenues from the Rosebud Mine increased
$9,500,000 including revenues from a synthetic fuel project. Volumes of coal
sold to the Colstrip Units in 1998 was 18 percent higher due to less down time
for repairs and scheduled maintenance at the Colstrip generating plants. These
increased volumes were partially offset by lower prices resulting from
contract dispute settlements with Puget in February 1997 and with the other
non-operating owners in August 1998. In addition, the Unit 3 and 4 coal
supply and transportation agreements were amended in the third quarter of 1998
resulting in lower prices. As discussed earlier, these changes will result in
modest profit reductions until mid-year 2000 with significant price reductions
thereafter. Revenues from the Jewett Mine rose $5,500,000 primarily as a
result of an increase in reimbursable mining expenses, partially offset by a 4
percent decrease in tons of coal sold.
Operation and maintenance (O&M) expense increased primarily due to
higher volumes at the Rosebud Mine and increased stripping costs at the Jewett
Mine. Depreciation, depletion, and amortization decreased primarily as a
result of the resolution of matters relating to the former Colorado mining
operations in 1995.
1997 Compared to 1996
Income from coal operations decreased primarily as a result of price
decreases and increased production costs and legal expenses. Revenues from
</PAGE>
<PAGE>
the Rosebud and Jewett mines increased $4,100,000 and $2,500,000,
respectively. At the Rosebud Mine, volumes of coal sold to Colstrip Units 3
and 4 increased nearly 37 percent over 1996 which was adversely impacted by
plant curtailments resulting from an abundance of low-cost hydroelectric power
in the region. This increase was largely offset by price reductions resulting
from the Puget settlement and a short-term contract modification on tons sold
to the other Colstrip partners along with a decrease in tons sold to Colstrip
Units 1 and 2 due to plant maintenance. Volumes of lignite sold at the Jewett
Mine increased 8 percent over 1996.
Operations and maintenance expense increased primarily due to higher
volumes of tons sold and increased overburden costs at the Rosebud Mine and
higher royalty expense at the Jewett Mine associated with mining more lignite
from the customer's leases. Taxes other than income taxes increased as a
result of higher revenues and volumes at the Rosebud Mine. Depreciation,
depletion, and amortization also increased due to the higher volumes and
changes in depreciation estimates.
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, and
the related percentage changes in volumes sold and prices received:
1998 1997
Oil -revenue $ (12) $ (3)
-volume (38)% (20)%
-price/bbl (38)% 10%
Natural gas -revenue $ 78 $ 36
-volume 103% 1%
-price/Mcf (23)% 35%
Miscellaneous -revenue $ - $ 9
1998 Compared to 1997
Income from oil and natural gas operations decreased primarily due to
lower market prices in 1998. In addition to lower prices, revenues from oil
operations decreased due to the sale of production properties in conjunction
with the Company's increased emphasis on its natural gas operations. Natural
gas revenues increased due to the sale of production from the Colorado
properties acquired in the second quarter of 1997 and from formerly regulated
assets transferred to oil and natural gas operations in the fourth quarter of
1997. In addition, marketing to wholesale customers in California started in
the second quarter of 1998. These increases were partially offset by the
lower prices in 1998.
Operation and maintenance expense increased due to the costs of
operating the acquired properties and transferred regulated assets. This
increase was partially offset by lower prices for purchased gas. These new
operations also accounted for the increases in SG&A and depreciation,
depletion, and amortization expenses.
1997 Compared to 1996
Oil and natural gas operations experienced a slight decrease in income
primarily due to decreased oil revenues and increased purchased gas costs.
Natural gas revenues increased primarily due to higher market prices, primarily
in the first and fourth quarters of the year and natural gas liquids revenues
</PAGE>
<PAGE>
from the Vessels plant acquired in 1997. Oil production decreased for the
reasons discussed above. Miscellaneous revenues increased due principally to
increases in processing and gathering revenues from the Vessels facilities.
Operations and maintenance expense increased $41,300,000 primarily due to
higher prices and increased volumes of purchased natural gas and additional
processing costs at the Vessels plant. Taxes other than income taxes also
increased due to the Vessels plant acquisition and higher production taxes.
Independent Power Operations:
1998 Compared to 1997
Income from independent power operations increased in 1998 by
$69,800,000. Earnings from unconsolidated investments increased $74,500,000
primarily due to the recognition of the Company's share in a settlement
resulting from an arbitration panel's ruling on a power purchase agreement
between one of the Company's independent power partnerships and the Bonneville
Power Administration. Additionally, a contract settlement between another of
its independent power partnerships and the power purchaser, along with the
sale of the Lockport, New York project also improved earnings for the year.
Expenses increased $7,800,000 primarily due to a $6,200,000 increase in
the amortization of the Company's independent power investments. Power supply
expenses increased $2,200,000 resulting from increased generation, which was
partially offset by a decrease in project development costs of $1,100,000.
1997 Compared to 1996
Excluding the 1996 gain on the sale of a portion of an investment,
earnings from unconsolidated investments increased $2,000,000 due to continued
growth in earnings from existing investments and additional earnings from an
investment that became operational in the first quarter of 1997. Offsetting
the increase was a $5,700,000 decrease in revenue resulting from a settlement
reached with Puget.
Operating expenses decreased largely from a $1,800,000 reduction in
purchase power expense combined with a $1,000,000 decrease in project
development expenses. The decrease was offset by a $1,700,000 increase in
fuel expense. During 1997, the Colstrip plant generated more energy than in
1996 due to less displacement of thermal generation. Depreciation expense
decreased $1,500,000 as a result of decreased amortization of independent
power investments due to a change in accounting method.
Telecommunications Operations:
In January 1999, the Company received and recorded $257,000,000
representing prepayment of all amounts due for the remaining initial term of
one telecommunications contract. The prepayment will be amortized over the
remaining 12-year term of the contract and will result in an annual decrease in
telecommunications revenues of approximately $21,600,000 in each year compared
to 1998.
1998 Compared to 1997
Net income from telecommunications operations increased primarily as a
result of a full year operation of its expanded fiber-optic network in 1998 as
compared to a partial year in 1997. Revenues from telecommunications
operations increased primarily due to sales on the Company's Washington to
Minnesota and Colorado to Canada fiber-optic network and a higher volume of
long-distance minutes sold. Revenues from the fiber-optic network did not
begin until late in the third quarter of 1997. The Company also has a one-
</PAGE>
<PAGE>
third interest in a limited liability company, which made dark fiber sales on
a Portland to Los Angeles fiber-optic network currently under construction.
These sales account for the $10,500,000 increase in earnings from
unconsolidated investments.
Expenses for 1998 are higher due to the operation of the Washington to
Minnesota and Colorado to Canada fiber-optic network mentioned above,
increased marketing expenses, and costs related to the increased long-distance
service.
1997 Compared to 1996
Earnings from telecommunications operations increased because the Company
began receiving revenues from its expanded fiber-optic network late in the
third quarter. A 31 percent increase in long-distance minutes resulted in a
$2,500,000 increase in revenues.
Operations and maintenance, taxes other than income and depreciation
increased $2,600,000, $1,900,000 and $1,500,000, respectively, as a result of
the operation of the expanded network. Selling, general and administrative
expenses increased primarily due to increased marketing efforts and advertising
costs.
Other Operations:
In August 1998, the Company announced it would exit the electric
commodity trading and marketing businesses. Due to the high volatility and
immaturity of the electric trading market and the Company's decision to sell
its generation assets, the Company believes that these activities create
unacceptable risks. The Company is in the process of developing its exit
strategy, but has remained in the electric trading business to take full
advantage of the opportunities to sell excess and buy needed electricity, and
fulfill contractual commitments, until the generation assets are sold. The
departure from these activities is not expected to have a material impact on
the Company's results from operations.
1998 Compared to 1997
Changes to revenues and expenses in other operations are primarily the
result of including the electric trading activities of the Montana Power
Trading and Marketing Company (MPT&M) and the Company's shared administrative
services functions in this section for 1998. From January through June, MPT&M
results reflect the purchase and resale of electricity that did not utilize
the Utility's electric system. Beginning in July 1998, all purchases and
resale of power in the secondary market are included in other operations.
1997 Compared to 1996
Revenue and expense increases in other operations relate primarily to the
Company's electric trading and marketing activity conducted by MPT&M.
Interest Expense and Other Income, and Income Taxes:
1998 Compared to 1997
Interest expense increased primarily due to increases in the amount of
outstanding borrowings to provide short-term financing for the Company's
expansion of its Nonutility operations and higher interest rates.
Other (income) and deductions - net decreased due to the 1997 gains and
losses discussed below and the absence of dividend income from the Brazilian
gold mine and interest income associated with a 1997 settlement with the IRS.
</PAGE>
<PAGE>
The increase in income tax expense resulted from higher pre-tax net
income as well as a credit to expense in 1997 associated with a settlement with
the IRS.
</PAGE>
<PAGE>
1997 Compared to 1996
Interest expense increased primarily due to increases in the amount of
outstanding borrowings to provide short-term financing for the Company's
expansion of telecommunication and oil and natural gas operations.
Other income - net increased due to the gains of approximately
$23,000,000 on the sales of non-strategic oil and natural gas properties, a
$10,300,000 gain on the sale of the investment in the Brazilian gold mine
offset by the loss on the sale of non-strategic Wyoming coal properties and
the absence of the 1996 gain on the sale of a portion of an independent power
investment.
The increase in income tax expense resulting from higher pre-tax net
income was mostly offset by the tax adjustment associated with the settlement
with the IRS.
LIQUIDITY AND CAPITAL RESOURCES:
Operating Activities:
Net cash provided by operating activities was $255,677,000 in 1998
compared to $201,091,000 in 1997 and $219,077,000 in 1996. The current year
increase of $54,586,000 was due primarily to the settlement resulting from an
arbitration panel's ruling on a power purchase agreement between one of the
Company's independent power partnerships and the Bonneville Power
Administration, a contract settlement between another of its independent power
partnerships and the power purchaser and the sale of the Lockport, New York
project. In addition, revenues increased from capacity and long-distance
sales by the telecommunications operations. These increases were partially
offset by an increase in receivables.
Cash from operating activities less dividends paid provided 103 percent
of net cash used for investing activities in 1998, 55 percent in 1997 and 64
percent in 1996.
One Touch America customer provided notice to exercise an option
allowing prepayment of all amounts due for the remaining initial term of the
contract. In January 1999, the Company received and recorded $257,000,000 as
deferred revenue. The prepayment will be amortized over the remaining term of
the contract. Tax laws require that the prepayment be reported as income in
the year received, therefore this will result in a 1999 tax payment of
approximately $100,000,000.
Investing Activities:
Net cash used for investing activities was $159,552,000 in 1998 compared
to $199,368,000 in 1997 and $193,587,000 in 1996. The current year decrease
of $39,816,000 was due primarily to a decrease in capital expenditures,
partially offset by a cash flow decrease due primarily to the prior year sale
of non-strategic oil and gas properties.
Capital expenditures during the prior three years and forecasted capital
expenditures for 1999 are as follows:
Forecasted Actual
1999 1998 1997 1996
Thousands of Dollars
Utility $ 88,000 $ 83,323 $ 138,318 $ 105,990
Nonutility 185,000 130,078 173,368 65,691
Total $ 273,000 $ 213,401 $ 311,686 $ 171,681
Of the Utility capital expenditures for 1998, 1997, and 1996, generation
accounted for $8,570,000, $74,428,000, and $19,307,000, respectively.
Generation is expected to account for $27,500,000 of the 1999 forecasted
</PAGE>
<PAGE>
Utility expenditures. The majority of the Utility's capital expenditures
during 1999 are expected to be spent on refurbishing electric and natural gas
transmission lines, extending and maintaining electric and natural gas
distribution lines and rehabilitation of steam and hydroelectric projects. The
majority of the Nonutility's capital expenditures during 1999 are expected to
be spent on the expansion and development of fiber-optic network development
and local access phone service in the telecommunications operations, drilling,
facilities and production enhancements of natural gas properties, future
project investments by the Independent Power Group as well as the
implementation of an enterprise resource planning system.
For 1999, the Company estimates that, by business unit, internally
generated funds will average 108 percent of its Utility construction program,
exclusive of the proceeds anticipated to be received from the sale of the
generation facilities, and 96 percent of Nonutility capital expenditures. Any
remaining capital expenditure balances, as well as the repayment of maturing
long-term debt, will be financed with short- and long-term debt and with 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.
Financing Activities:
On January 2, 1998, the Company used short-term borrowings to retire
$16,000,000 in sinking fund debentures.
On April 6, 1998, the Company issued $60,000,000 of floating rate
Medium-Term Notes, Series B, due April 6 2001, the proceeds of which were used
to reduce outstanding debt.
On October 1, 1998, the Company used short-term borrowings to retire
$2,500,000 in 8.9 percent series Medium-Term Notes.
On November 9, 1998, the Company used short-term borrowings to retire
$10,000,000 in 7.85 percent series Medium-Term Notes.
On November 24, 1998, the Company used short-term borrowings to retire
$10,000,000 in 5.9 percent series Medium-Term Notes.
Dividends paid on common and preferred stock were $91,598,000 in 1998,
$91,112,000 in 1997, and $95,284,000 in 1996. During 1998, the regular
quarterly dividend level was 40 cents per share of outstanding stock or $1.60
per share on an annual basis. The declaration of future dividends is at the
discretion of the Board of Directors.
The Company's Board of Directors has authorized a share repurchase
program over the next five years to repurchase up to 10,000,000 shares, or 18
percent, of the Company's outstanding common stock.
As of yearend 1998, the Company had 55,060,520 common shares
outstanding. The repurchase of common stock may be made, from time to time,
on the open market or in privately negotiated transactions. The number of
shares to be purchased and the timing of the purchases will be based on the
level of cash balances, general business conditions and other factors,
including alternative investment opportunities.
In 1998, the Company established a special purpose entity that is a
wholly owned subsidiary, MPC Natural Gas Funding Trust (Trust). In December
1998, the Trust issued $62,700,000 of 6.2 percent asset-backed securities,
known as transition bonds. The transition bond proceeds will be used to
reduce the Company's outstanding debt and equity. The bonds will be retired
from funds collected by the Trust through usage-based charges levied on
</PAGE>
<PAGE>
natural gas transmission and distribution customers. The retirements will
occur at six-month intervals beginning on September 15, 1999, and ending on
March 15, 2012. Retirements will be in varying amounts depending on revenues
collected from customers. At December 31, 1998, approximately $1,700,000 is
classified as due within one year in the Consolidated Balance Sheet.
The Company's consolidated borrowing ability under its Revolving Credit
and Term Loan Agreements was $178,300,000, of which $134,000,000 was unused at
December 31, 1998. The unused amount excludes $30,000,000 under the
Agreements which is currently being used to back a like amount of commercial
paper. The Company also has short-term borrowing facilities with commercial
banks that provide both committed and uncommitted lines of credit, and the
ability to sell commercial paper.
The Company's long-term debt as a percentage of capitalization was 37
percent in 1998, 1997, and 1996. Approximately $96,000,000 of long-term debt
will mature during the year 1999. 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.
While the Company does not expect to issue additional First Mortgage
Bonds in 1999, the restrictions upon the issuance of such bonds contained in
the Company's Mortgage and Deed of Trust would not preclude it from issuing
sufficient First Mortgage Bonds to meet its expected financing requirements for
the year. 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.
See Item 8, "Financial Statements and Supplementary Data - Notes 9
and 10 to the Consolidated Financial Statements" for further information on
financing activities.
PP&L Global has agreed to purchase the Company's interest in 12 of its 13
hydroelectric facilities, all four coal-fired thermal generating plants and a
leasehold interest in Colstrip Unit 4, along with a power purchase contract
with Basin and two power exchange agreements. Proceeds from the sale will vary
depending upon various factors, and are anticipated to be between $740,000,000
and $988,000,000. The Company is evaluating the potential uses for the
proceeds realized from the sale including investing in current businesses,
primarily telecommunications, as well as a repurchase of common stock and
possible debt repayment. The Company does not expect the generation sale
proceeds or the telecommunications prepayment to materially change its
consolidated capitalization percentages.
SEC RATIO OF EARNINGS TO FIXED CHARGES:
For the twelve months ended December 31, 1998, the Company's ratio of
earnings to fixed charges was 3.34 times. Fixed charges include interest, the
implicit interest of Unit 4 rentals and one-third of all other rental payments.
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 operations are not impacted because a
gas cost tracking procedure annually balances gas costs collected from
customers with the costs of supplying gas. As the Company's utility operations
transition to a more competitive environment and considering the intended sale
</PAGE>
<PAGE>
of the electric generating facilities and power purchase contracts, it is
anticipated that the Company will be less capital intensive in the future and
therefore, impacted less by inflation.
The Nonutility's long-term coal and co-generation natural gas supply
contracts and 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 materially affect results of operations.
YEAR 2000 COMPLIANCE:
The Year 2000 issue, known as Y2K, relates to the ability of systems,
including computer hardware, software, and embedded microprocessors, to
properly interpret date information relating to the year 2000. Many existing
systems, including some of the Company's systems, use only the last two digits
to refer to a year. Therefore, these systems may not properly recognize a
year that begins with "20" instead of "19". If not corrected, these systems
could fail or create erroneous results.
The Company has a corporate-wide strategy to address Y2K issues. An
Executive Steering Committee was established to coordinate and oversee
implementation of the strategy in the business units. The strategy includes a
three step process and a contingency plan. The first step involves
inventorying critical information technology (IT) systems and non-information
(non-IT) systems including third party computer hardware and software, and
embedded electronic microprocessors. During the second step, the Company
conducts certain analyses to determine the system's Y2K readiness. The third
step consists of replacing/repairing and testing the systems to ensure the
availability and integrity of the systems. Simultaneous with those three
steps, the Company is developing a contingency plan to address unanticipated
failure of the systems.
Inventorying of the critical IT systems is complete. This involves
computer systems within the Company's main business office, such as accounting
systems, human resource systems, materials management systems, and work
management systems. Analysis of the inventory is also complete. Of the IT
systems inventoried, over 50 percent have already been deemed ready based on
testing or representations from the manufacturers. The Company is working to
have all of its critical systems Y2K ready by July 1, 1999. Currently, the
Company believes that of the systems inventoried, one critical IT system, the
Customer Information System, which provides utility customer billing and field
operations support, is not Y2K compliant. The Company is pursuing a billing
outsourcing solution that is expected to be in place by August 1, 1999. In
the event this or any other critical system fails in spite of efforts to be
ready, contingency plans are being developed.
Inventorying of critical non-IT systems is 85 percent completed.
Analysis of the inventory is 80 percent completed. Approximately 70 percent
of the systems that have been inventoried have been deemed Y2K ready based on
testing or representations from the manufacturers. The Company is working to
have all of its non-IT critical systems Y2K ready by July 1, 1999. Among the
Company's critical non-IT systems that will not be ready by that date are the
Energy Management System, which provides system control and data acquisition
for the Company's electric transmission system, and continuous emission
monitoring systems, which monitor stack gas emissions at the Corette and
Colstrip Plants. A Y2K solution for the energy management system is expected
to be implemented by August 1, 1999, and for the emission monitors by
September 1, 1999. Contingency plans are being developed in the event systems
fail in spite of the Company's efforts to be ready.
</PAGE>
<PAGE>
The Year 2000 issue may also impact other entities with which the
Company transacts business or with which the Company's electric and natural
gas systems are interconnected. Each of the business units has been
contacting suppliers, vendors, and key customers to assess their Year 2000
readiness. Currently, the Company has not been advised that Y2K impacts to
vendors, customers, or suppliers' systems will significantly impact its
operations. In addition, because of the interconnected nature of electric
systems, the North American Electric Reliability Council (NERC) is
facilitating the preparations of electric systems in North America for
operation into the year 2000. As part of its Year 2000 program, NERC monitors
the monthly progress of industry efforts to prepare critical systems for the
year 2000. NERC has proposed national drills in April and September 1999 to
assess industry preparation. The Company plans to participate in such drills.
The Company has not established a formal process to track either
external or internal Y2K expenditures. Many of the measures that will
mitigate Y2K impacts coincide with normal operations and maintenance, so are
not accounted for separately as Y2K expenditures. For example, the capital
upgrade to the energy management system which is necessary in any event to
provide additional functionality will also result in a Y2K benefit and cost
$460,000. An additional $36,000 to test custom software associated with the
energy management system and the upgrade software is explicitly accounted for
as a Y2K expense. Likewise, the Company is implementing a new method of
customer billing which will cost $3,100,000 and although it will address the
Y2K issue, in any case, the new method was planned to satisfy deregulation
requirements. In addition, the central information services department,
estimates that through 1998 it has already spent approximately $1,100,000 to
address the Y2K issue and anticipates spending another $1,400,000 in 1999.
Although it is not currently possible to estimate the overall cost of required
modifications, the Company presently believes that the ultimate cost of this
work will not have a material effect on the Company's current financial
position, liquidity, or results of operations.
Except as described above, the Company expects all necessary
modifications and testing of its critical IT and critical non-IT systems to be
completed by July 1, 1999. Also, as previously discussed, contingency plans
will be in place. The most reasonably likely worst case Y2K scenario
envisioned by the Company is that some customers could experience
interruptions in service.
NEW ACCOUNTING PRONOUNCEMENTS:
In June 1998, the Financial Accounting Standards Board (FASB) issued
SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities".
SFAS No. 133 requires that all derivative instruments be recorded on an
entity's balance sheet at fair value. The statement also expands the
definition of a derivative. Changes in the fair value of the derivatives are
recognized each period either in current earnings or as a component of
comprehensive income, depending on whether the derivative is designated as
part of a hedge transaction, and if so, what type of hedge transaction. The
statement distinguishes between fair-value hedges, defined as hedges of the
Company's assets, liabilities, or firm commitments, and cash-flow hedges,
defined as hedges of future cash flows related to a variable rate asset or
liability or a forecasted transaction. Recognition of changes in the fair
value of a hedge, determined to be a fair-value hedge, will generally be
offset in the income statement by the recognition of the change in the fair
value of the hedged item. Recognition of changes in the fair value of a cash-
flow hedge will be reported as a component of comprehensive income. The gains
or losses on the derivative instruments that are reported in comprehensive
income will be reclassified into current earnings in the periods in which the
earnings are impacted by the variability of the cash flows of the hedged item.
The ineffective portion of all hedges will be recognized in current earnings.
</PAGE>
<PAGE>
The new statement is effective for all fiscal quarters of all fiscal
years beginning after June 15, 1999. The Company has not yet determined the
impact that the adoption of the new standard will have on its earnings or
financial position.
During 1998, the Emerging Issues Task Force (EITF) of the FASB released
Issue 98-10 (EITF 98-10), "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities". EITF 98-10 addresses the accounting for
energy contracts and requires that energy contracts entered into under
"trading activities" be marked to market with the gains or losses shown net in
the income statement. EITF 98-10 is effective for the fiscal years beginning
after December 15, 1998. In conjunction with its commodity risk management
activities, the Company calculates and evaluates mark to market information
for its trading activities on a regular basis. Mark to market analysis for
these activities at December 31, 1998 indicates that an immaterial loss would
have been required to be recognized in the results of operations had EITF 98-
10 been effective. Based upon a periodic review of the mark to market
analysis for these activities, the Company does not expect the adoption of
EITF 98-10 to have a material impact on its results of operations.
ENVIRONMENTAL ISSUES:
The Company is committed to protect, maintain, and enhance the
environment in its business operations. The diversity of the Company's
businesses subjects it to numerous federal, state and local environmental laws
and regulations relating to pollution control and prevention, and
environmental remediation. The primary federal environmental laws and
regulations affecting the Company are: The Clean Air Act; the Clean Water
Act; the Comprehensive Environmental Response, Compensation, and Liability Act
(CERCLA); the Resource Conservation and Recovery Act; the Oil Pollution
Prevention Act; the Safe Drinking Water Act; the Toxic Substances Control Act;
the Federal Insecticide, Fungicide, and Rodenticide Act; the Hazardous
Materials Transportation Act; the Emergency Planning and Community Right to
Know Act; the Surface Mining Control and Reclamation Act; and the National
Environmental Policy Act.
The Company maintains accruals for its minimum estimated costs
associated with reasonably foreseeable potential environmental clean-up costs;
it does not expect these costs to materially impact the results of its
operations.
CERCLA, and some of its state counterparts, give rise to loss
contingencies for future site remediation because they may require the Company
to remove or mitigate the adverse environmental effects resulting from the
disposal or release of certain substances at previously owned or present
Company sites, or at sites where these substances were disposed. The total
amount of costs associated with current site remediation efforts and future
remediation is unknown both because (1) the Company may not know of all sites
for which it is responsible and (2) it cannot currently predict with any
degree of certainty the total costs for those sites it has identified. Current
indications are that the known costs will not have a materially adverse effect
on the Company or its operations.
The Company is a Potentially Responsible Party (PRP) at the Silver Bow
Creek/Butte Area Superfund Site. A Consent Decree recognizing the Company's
"de minimis" contributor status will soon be submitted to the federal court
for approval. Upon approval of the Consent Decree, and payment of $100,000,
the Company will receive a release from further liability for clean-up costs.
. Further, the Consent Decree will provide the Company contribution protection
in the event other PRP's claim contribution for clean-up costs they expend.
Given the expected approval of the Consent Decree, the substantial financial
capability of other PRP's named by the Environmental Protection Agency (EPA),
</PAGE>
<PAGE>
and the very limited connection between the Company's property ownership and
the "mining-related" character of the alleged contamination of the Site, the
Company does not feel it has a significant exposure to material liability
regarding this overall Site.
The Company will, however, continue to address alleged soils
contamination of the 30 acres of this Site, which it owns. Expected clean-up
costs are not material.
The Company is a PRP at the Milltown Dam Site, where toxic heavy metals
are in the silts resting behind the dam. Because of federal legislation
specifically regarding Milltown, the Company's position is that it has no
responsibility for any of the alleged releases under CERCLA.
The Company has voluntarily cleaned up two sites where it operated
manufactured gas plants, spending approximately $675,000. It has inspected
and assessed a third site. Periodic ground water monitoring and reporting to
the Montana Department of Environmental Quality (MDEQ) is required at the two
sites where clean up is completed. The cost of this monitoring is not
expected to be material. Discussions with the MDEQ and local regulatory
agencies regarding the third site are not complete. Nevertheless, the Company
does not expect expenditures at this site to be material.
The MDEQ has listed the reservoir at the Thompson Falls Dam as a
Comprehensive Environmental Cleanup and Responsibility Act (CECRA) site -- the
state equivalent of a CERCLA National Priority List site. In 1985 and 1986,
researchers found elevated levels of heavy metals in sediments in the
reservoir. EPA declared the site a "No Further Action" site under CERCLA. The
MDEQ identified the site as a "Low Priority Site" because of low direct
contact hazard and the lack of evidence of migration to groundwater supplies.
Given the low priority designation for this site, no estimate of costs to
address the alleged contamination has been required.
All of the Company's coal-fired units are Phase II Units under Title IV
(Acid Rain) of the Clean Air Act Amendments of 1990 (Act) which imposes
certain sulfur dioxide and nitrogen oxide requirements. All of the Company's
coal-fired plants comply with the sulfur dioxide requirements.
The nitrogen oxide standard for Phase II Units, effective in the year
2000, is more stringent than the standard imposed upon Phase I Units. However,
the Act provides Phase II Units with the option to comply, beginning January
1, 1997, with the Phase I standards and defer, until 2008, compliance with the
more stringent Phase II standards. Because the Company has determined that
the Colstrip Units could meet the Phase I nitrogen oxide standards by January
1, 1997, it exercised this option for the Colstrip plants. For calendar years
1997 and 1998, the Colstrip plants met the early election standard. The
Company did not exercise this option for its Corette Plant. However, in 1997
the Company installed a low nitrogen oxide burner system on the Corette
boiler. The cost of the system and installation was approximately $1,000,000.
Since the system has been in place, it has performed well within the Phase II
standards. The costs associated with any modifications that ultimately may be
required to comply with Phase II nitrogen oxide standards have not been
determined.
In addition, all of the Company's coal-fired units have now received
Operating Permits under Title V (Permitting) of the Act. The permits were
effective on January 1, 1998 for Colstrip Units 1 and 2 and January 1, 1999,
for Colstrip Units 3 and 4 and the Corette plant. The Corette plant is also
operating under a State Implementation Plan, as administered by the MDEQ, for
control of sulfur dioxide emissions effective March 1998.
</PAGE>
<PAGE>
Surface and ground water impacts resulting from the operation of the
Colstrip Project's process water disposal system have been previously
documented. Study and mitigation efforts continue in consultation with the
MDEQ to address the impacts. Estimated maintenance expenses to monitor and
sustain the effectiveness of related groundwater collection systems are
$50,000 per year. Estimated capital expenditures for 1999-2001, the scheduled
remedy period, are $5,000,000.
In 1998, the Company employed a consultant to assess environmental
conditions at the generation facilities it sold. From the consultant, it
obtained estimates of future costs deemed reasonably necessary to address
identified issues. Consequently, the Company accrued $7,350,000 in 1998 for
its share of the estimated liability.
The Company's Canadian subsidiaries are involved with ongoing
abandonment and remediation of depleted wells and surface facilities in
Alberta. The remediation work addresses clean up under the direction of
Alberta Environmental and reflects normal activity within the oil and gas
industry. Approximately 35 sites are under active reclamation. Clean up of
70 sites has been completed through 1998, of which 31 sites are either
awaiting final inspection by Alberta Environmental, or are in the final
monitoring of vegetation growth prior to applying for clean-up certification.
Since 1995, the Company has spent approximately $800,000 (U.S.$) for clean up
of the identified sites. The Company believes that estimated additional
expenditures of $980,000 (U.S.$) will be required for clean up of affected
sites through the year 2003. The estimate is subject to change, pending
acquisitions or divestitures of Canadian properties, which may occur over the
five-year period.
In the purchase of all of the Company's electric generation assets,
except Milltown Dam, PP&L Global assumed pre- and post-closing environmental
liabilities associated with the purchased assets. The Company retained the
following liabilities regarding its interests sold:
? Payment of fines or penalties imposed by regulatory authorities
related to pre-closing activity.
? Liability for pre-closing "off-site" activity, such as
transportation, disposal, or storage of hazardous material to a site
other than the location of a sold generation asset.
? Remediation, if any, of the silts behind the Thompson Falls Dam.
The Company, along with the other sellers of interests in the Colstrip
Project, agreed to indemnify PP&L Global from losses arising from pre-closing
environmental conditions. The indemnity obligation, however, is limited:
? The indemnity for required remediation of pre-closing conditions,
whether known or unknown at the closing, is limited to 50 percent of
the loss. (The Company's share of such indemnity obligation at the
Colstrip Project is limited to its pro-rata share of 50 percent.)
? The indemnity for required remediation of pre-closing conditions
unknown at the time of closing is limited to a two-year period after
closing. The indemnity for required remediation of pre-closing
conditions known at the time of the closing continues indefinitely.
? The indemnity for required remediation of pre-closing conditions,
whether known or unknown, is capped at an amount equal to 10 percent
of the purchase price paid for the generation assets.
The Company does not expect this indemnity obligation to materially
adversely affect the financial results of its operations.
</PAGE>
<PAGE>
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
RISK MANAGEMENT:
The Company is exposed to the market risks associated with fluctuations
in commodity prices, interest rates, and changes in foreign currency
translation. To better manage the risks associated with commodity trading and
marketing activities, the Company implemented a comprehensive Energy Risk
Management program in 1998. In conjunction with this program, the Company
established a Risk Management Committee, which approves the risk-related
activities in which the Company participates, the types of instruments that may
be used, and recommends to the Company's Audit Committee of the Board of
Directors specific limits for trading activity.
TRADING INSTRUMENTS:
Commodity Price Exposure
The Company, primarily through its subsidiaries, is exposed to the
effects of market price fluctuations in the price of oil, natural gas, and
natural gas liquids, the price of electricity purchased and sold under firm
contracts and in the spot market and natural gas transportation costs.
Additionally, the Company is exposed to market price fluctuations for
instruments related to these products which are marketed and traded. The
Company has formal policies regarding the execution, recording, and reporting
of products and instruments related to the marketing and trading of
electricity, oil, natural gas, and natural gas liquids. The Company uses
various financial derivative instruments to manage the price risk associated
with its Nonutility producing assets, firm-supply commitments, and natural gas
transportation agreements. These financial derivative instruments include
swaps and options. See Item 8, "Financial Statements and Supplementary Data -
Note 1 to the Consolidated Financial Statements".
In August 1998, the Company announced it would exit the electric
commodity trading and marketing businesses. Due to the high volatility and
immaturity of the electric trading market and the Company's decision to sell
its electric generation assets, the Company believed that these activities
created unacceptable risks. Although the Company is in the process of
implementing its exit strategy, it has remained in the electric trading
business to efficiently sell surplus electricity from its generating plants and
buy electricity needed to supply its native Utility load and fulfill
contractual commitments. Neither remaining in the electric trading business on
a limited basis, nor eventually exiting from this business, is expected to have
a material impact on the Company's results from operations.
The Company's value-at-risk for natural gas physical and financial
transactions (VaR) is based on J.P. Morgan's RiskMetrics T approach (i.e.
variance/co-variance), which uses historical estimates of volatility and
correlation and values optionality using delta equivalents. Because actual
future changes in markets (prices, volatilities, and correlations) may be
inconsistent with historical observations, the Company's VaR may not accurately
reflect the potential for future adverse changes in fair values. The Company's
VaR is based on a forward 24-month time period and assumes a one-day holding
period and a 95 percent confidence level. As of December 31, 1998, the
Company's VaR calculation for these natural gas physical and financial
transactions was less than $2,000,000. At December 31, 1998, the Company held
no financial derivative contracts relating to oil or natural gas liquids.
The Company entered into a financial derivative transaction in
conjunction with one of its electric retail sales contracts. The negative
mark-to-market valuation of this instrument is recaptured when netted against
the positive mark-to-market valuation of a related offsetting physical
transaction with another counterparty. The decrease in fair market value of
the derivative instrument resulting from a hypothetical 10 percent adverse
change in market price is also offset by the increase in the fair market value
of the related offsetting physical transaction resulting from this market price
change.
</PAGE>
<PAGE>
Interest Rate Exposure
Currently, the Company does not use derivative financial instruments to
hedge against exposure to interest rate fluctuations on variable rate debt. The
Company 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. However, at December 31, 1998, the Company
believes it would not experience any materially adverse impacts from the risks
inherent in these instruments.
Foreign Currency Exposure
Currently, the Company does not use derivative financial instruments to
hedge against exposure to foreign currency exchange rate fluctuations. As a
result, at December 31, 1998, the Company has no financial instruments related
to foreign currency fluctuations which expose it to such market risks.
OTHER FINANCIAL INSTRUMENTS:
Commodity Price Exposure
At December 31, 1998, the Company's primary commodity risk related to its
Nonutility operation's contracts for the purchase or delivery of electricity,
natural gas, natural gas liquids, oil, coal, and lignite and the regulated
Utility operation's contracts for the purchase or delivery of electricity and
natural gas.
Within its regulated Utility operations, the Company has contracts for
the purchase or exchange of electricity under contracts with expiration terms
ranging from 2001 through 2031. At December 31, 1998, it is estimated that
these contracts could result in above-market costs of between $300,000,000 and
$500,000,000 throughout their duration. The exchange contracts and one of the
purchase contracts are included in the asset sale agreement with PP&L Global
and the Company is evaluating options for divestiture of the other contracts.
Although a hypothetical 10 percent adverse change in the market price for
electricity increases the potential above-market costs by $25,000,000 to
$30,000,000, the Company expects to recover the costs associated with these
contracts through the sale or through competitive transition charges (CTC's)
in the electric restructuring process. Therefore, these contracts are not
expected to expose the Company to market risks related to commodity price
fluctuations other than from the possibility of a regulatory lag or the
disallowance of recovery of those costs. See Item 8, "Financial Statements
and Supplementary Data - Note 4 to the Consolidated Financial Statements".
Also within its regulated Utility operations, the Company has contracts
for the purchase of fuel for one of its electric generating facilities from a
third party as well as contracts for the purchase of natural gas for resale
and contracts for the sale of electricity. Although the potential exists for
market risk within these contracts, the costs are expected to be recovered
through the rate making process and are not expected to expose the Company to
market risks related to commodity price fluctuations other than from the
possibility of a regulatory lag or the disallowance of recovery of those
costs.
In its Nonutility operations, the Company has various electric sales
contracts with fixed or variable prices or with cost reimbursement and fee
pricing structures with terms expiring from 1999 through 2023. Using mark-to-
market analysis and net present value calculations for the duration of the
contracts, the Company estimates the fair market value of these contracts is
approximately $52,000,000 at December 31, 1998. An analysis of fair value of
these contracts resulting from a hypothetical 10 percent adverse change in the
market price for the electricity throughout the contracts, which may differ
from actual results, indicates a decrease in the December 31, 1998 fair value
of approximately $3,000,000.
The Company has a full-lignite requirements supply agreement (LSA)
through July 2015 for the delivery of lignite to two mine-mouth electric
generating facilities. The contract currently provides for the reimbursement
</PAGE>
<PAGE>
of certain mining costs as well as management and dedications fees. Under a
settlement reached in late 1998, the pricing structure will change in mid-2002
and will be market price driven. The Company expects that if the market price
of fuel stays flat when the agreement is fully implemented, the competitive-
pricing structure could result in a reduction of the Company's pretax income of
approximately $7,000,000. Since transportation costs are a substantial portion
of other competitive supplies, the impact that would result from a hypothetical
10 percent adverse change in commodity prices of these competitive fuel
supplies is an approximate 2 percent decrease in the price received under the
contract. See Item 8, "Financial Statements and Supplementary Data - Note 2 to
the Consolidated Financial Statements".
The Company also has full-requirements contracts for the sale of coal to
four mine-mouth electric generating plants in Montana partially owned by the
Company. The contract for supply to two of these facilities provides for price
reopeners to adjust prices to reflect changes in mining costs but is not
directly tied to market price changes. Therefore, there is no direct market
risk associated with these contracts. The contracts for the other two
facilities requires that alternative supplies be continually evaluated by the
Company, however, due to the significant transportation costs of alternative
supplies, a hypothetical 10 percent decrease in commodity prices of these
competitive coal supplies should not impact these contracts.
At December 31, 1998, the Company had a very limited number of natural
gas liquids sales contracts and any market risk associated with these contracts
is immaterial.
Interest Rate Exposure
At December 31, 1998, the Company's primary interest rate exposure
related to the items defined as other financial instruments under the guidance
of SFAS No. 107, "Disclosures about Fair Value of Financial Instruments". These
financial instruments principally include the Company's cost basis investments
in independent power projects, reclamation fund, other significant investments,
mandatory redeemable preferred securities, and long-term debt. Market risk for
these financial instruments is estimated as the potential loss in fair value
which would result from a hypothetical 10 percent adverse change in interest
rates. See Item 8, "Financial Statements and Supplementary Data - Note 1 to
the Consolidated Financial Statements".
Based on the method used to estimate fair values for the purposes of
SFAS No. 107 analysis, the potential loss in the December 31, 1998 fair value
of the independent power projects, reclamation fund, and other significant
investments that would result from a hypothetical 10 percent adverse change in
interest rates would be immaterial. Based on the method used to estimate fair
values for the purposes of SFAS No. 107 analysis, potential loss in the
December 31, 1998 fair value of the mandatorily redeemable preferred
securities and long-term debt that would result from a hypothetical 10 percent
adverse change in interest rates would be approximately $5,300,000 and
$15,200,000, respectively.
Foreign Currency Exposure
The Company's oil and natural gas operations are engaged in exploration,
production, gathering, processing, and marketing of oil and natural gas in
Canada through Altana Exploration Ltd. and Canadian Montana Gas Company, both
Canadian subsidiaries. Both of these subsidiaries use Canadian dollars as
their functional currency. The Company also engages in natural gas trading and
marketing activities in Canada. However, at December 31, 1998, the Company
believes that the market risk associated with a hypothetical 10 percent adverse
change in foreign currency translation would be immaterial.
</PAGE>
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA
Page
Management's Responsibility for Financial Statements 57
Report of Independent Accountants 58
Consolidated Financial Statements:
Consolidated Statements of Income for the Years Ended 59
December 31, 1998, 1997 and 1996
Consolidated Balance Sheets as of December 31, 1998 and 1997 60-61
Consolidated Statements of Cash Flows for the Years Ended 62
December 31, 1998, 1997 and 1996
Consolidated Statements of Common Shareholders' Equity for the 63
Years Ended December 31, 1998, 1997 and 1996
Notes to Consolidated Financial Statements 64-93
Supplementary Data (Unaudited) 94-103
Financial Statement Schedules for the Years Ended December 31,
1998, 1997 and 1996:
Schedule II - Valuation and Qualifying Accounts and Reserves 108
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>
<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
Company. 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 judgments 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.
PricewaterhouseCoopers LLP, the Company's independent accountants, also
considered the systems in connection with its audit. Management has considered
the internal auditors' and PricewaterhouseCoopers 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 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 audited by PricewaterhouseCoopers LLP,
which is responsible for conducting its examination in accordance with
generally accepted auditing standards.
/s/ Robert P. Gannon /s/ J. P. Pederson
R. P. Gannon J. P. Pederson
Chairman of the Board and Vice President and Chief
Chief Executive Officer Financial and Information
Officer
</PAGE>
<PAGE>
Report of Independent Accountants
February 4, 1999
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, 1998
and 1997, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 1998, 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 audit to obtain
reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, 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.
/s/PricewaterhouseCoopers LLP
Portland, Oregon
</PAGE>
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENT OF INCOME
The Montana Power Company and Subsidiaries
Year Ended December 31
1998 1997 1996
Thousands of Dollars
(except per share amounts)
<S> <C> <C> <C>
REVENUES $ 1,253,724 $1,023,597 $ 973,208
EXPENSES:
Operations 528,196 420,032 386,775
Maintenance 81,064 82,702 75,409
Selling, general and administrative 128,741 116,054 104,535
Taxes other than income taxes 96,181 92,967 84,400
Depreciation, depletion and amortization 114,267 95,340 86,403
948,449 807,095 737,522
INCOME FROM OPERATIONS 305,275 216,502 235,686
INTEREST EXPENSE AND OTHER INCOME:
Interest 60,851 54,667 48,770
Distributions on mandatorily redeemable
preferred securities of subsidiary trust 5,492 5,492
Other income - net (4,862) (34,159) (4,445)
61,481 26,000 44,325
INCOME TAXES 78,174 61,870 71,975
NET INCOME 165,620 128,632 119,386
DIVIDENDS ON PREFERRED STOCK 3,690 3,690 8,358
NET INCOME AVAILABLE FOR COMMON STOCK $ 161,930 $ 124,942 $ 111,028
AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING (Basic) 54,981 54,649 54,634
BASIC EARNINGS PER SHARE OF COMMON STOCK $ 2.95 $ 2.29 $ 2.03
AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING (Diluted) 55,078 54,700 54,641
DILUTED EARNINGS PER SHARE OF COMMON STOCK $ 2.94 $ 2.28 $ 2.03
The accompanying notes are an integral part of these statements.
</TABLE>
</PAGE>
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEET
The Montana Power Company and Subsidiaries
ASSETS
December 31
1998 1997
Thousands of Dollars
<S> <C> <C>
PLANT AND PROPERTY IN SERVICE:
Utility plant $2,246,847 $2,216,198
Less - accumulated depreciation and depletion 732,385 684,960
1,514,462 1,531,238
Nonutility property 864,981 781,406
Less - accumulated depreciation and depletion 297,933 260,567
567,048 520,839
2,081,510 2,052,077
MISCELLANEOUS INVESTMENTS:
Independent power investments 24,268 51,534
Reclamation fund 41,542 47,312
Other 84,256 49,555
150,066 148,401
CURRENT ASSETS:
Cash and temporary cash investments 10,116 2,770
Accounts receivable 170,652 126,926
Notes receivable 29,089 4,061
Materials and supplies (principally at average cost) 42,292 39,471
Prepayments and other assets 57,331 49,673
Deferred income taxes 18,755 10,539
328,235 233,440
DEFERRED CHARGES:
Advanced coal royalties 14,312 16,698
Regulatory assets related to income taxes 121,735 122,903
Regulatory assets - other 154,193 158,573
Other deferred charges 78,044 73,804
368,284 371,978
$2,928,095 $2,805,896
The accompanying notes are an integral part of these statements.
</TABLE>
</PAGE>
<PAGE>
<TABLE>
<CAPTION>
LIABILITIES AND SHAREHOLDERS' EQUITY
December 31
1998 1997
Thousands of Dollars
<S> <C> <C>
CAPITALIZATION:
Common shareholders' equity:
Common stock (120,000,000 shares without par
value authorized; 55,060,520 and 54,728,709
shares issued) $ 702,511 $ 694,561
Retained earnings and other shareholders' equity 430,309 356,327
Accumulated other comprehensive income (loss) (20,717) (13,354)
Unallocated stock held by trustee for Retirement
Savings Plan (23,298) (25,945)
1,088,805 1,011,589
Preferred stock 57,654 57,654
Company obligated mandatorily redeemable preferred
securities of subsidiary trust which holds solely
company junior subordinated debentures 65,000 65,000
Long-term debt 698,329 653,168
1,909,788 1,787,411
CURRENT LIABILITIES:
Short-term borrowings 69,820 133,958
Long-term debt-portion due within one year 96,292 81,659
Dividends payable 22,765 22,684
Income taxes 24,857 3,803
Other taxes 51,777 47,818
Accounts payable 97,197 77,821
Interest accrued 13,156 13,836
Other current liabilities 40,087 39,358
415,951 420,937
DEFERRED CREDITS:
Deferred income taxes 323,906 340,251
Investment tax credits 33,819 35,182
Accrued mining reclamation costs 129,558 131,108
Other deferred credits 115,073 91,007
602,356 597,548
CONTINGENCIES AND COMMITMENTS (Notes 2 and 3)
$2,928,095 $2,805,896
The accompanying notes are an integral part of these statements.
</TABLE>
</PAGE>
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENT OF CASH FLOWS
The Montana Power Company and Subsidiaries
Year Ended December 31
1998 1997 1996
Thousands of Dollars
<S> <C> <C> <C>
NET CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 165,620 $ 128,632 $ 119,386
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation, depletion and amortization 114,267 94,664 88,744
Deferred income taxes (17,958) 10,677 15,430
Noncash earnings from unconsolidated
independent power investments (10,871) (14,016) (11,505)
Reclamation expenses and payments - net (1,550) 1,230 7,870
Deferred stripping expenses and
payments - net 291 (696) (787)
Losses (gains) on sales of property and
investments 4,669 (33,849) 2,532
Other - net 32,351 24,145 15,240
Changes in current assets and liabilities:
Accounts receivable (43,726) 21,338 9,686
Notes receivable (25,028) (1,578) 353
Materials and supplies (2,821) (149) 2,872
Deferred income taxes (8,216) 556 (2,198)
Accounts payable 19,376 15,603 (1,702)
Income taxes payable 21,054 (7,281) 1,146
Other assets and liabilities 8,219 (38,185) (27,990)
Net cash provided by operating activities 255,677 201,091 219,077
NET CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (213,401) (311,686) (171,681)
Reclamation funding 5,770 (4,311) (43,001)
Proceeds from property and investments 55,643 135,577 21,991
Additional investments (7,564) (18,948) (896)
Net cash used for investing activities (159,552) (199,368) (193,587)
NET CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends paid (91,598) (91,112) (95,284)
Sales of common stock 7,421 2,201 798
Redemption of preferred stock (44,415)
Issuance of long-term debt 139,947 103,375 82,890
Retirement of long-term debt (80,411) (71,634) (22,236)
Issuance of mandatorily redeemable preferred
securities (67) 62,625
Net change in short-term borrowing (64,138) 29,256 8,354
Net cash used for financing activities (88,779) (27,981) (7,268)
CHANGE IN CASH FLOWS 7,346 (26,258) 18,222
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR 2,770 29,028 10,806
CASH AND CASH EQUIVALENTS, END OF YEAR $ 10,116 $ 2,770 $ 29,028
SUPPLEMENTAL DISCLOSURES OF CASH FLOW:
Cash paid during the year for:
Income taxes, net of refunds $ 90,663 $ 50,797 $ 52,470
Interest 67,777 59,681 49,962
The accompanying notes are an integral part of these statements.
</TABLE>
</PAGE>
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENT OF COMMON SHAREHOLDERS' EQUITY
The Montana Power Company and Subsidiaries
Year Ended December 31
1998 1997 1996
Thousands of Dollars
COMMON STOCK:
<S> <C> <C> <C>
Balance at beginning of year $ 694,561 $ 691,853 $ 691,043
Issuances (331,811; 97,715;
and 16,513 shares) 7,950 2,708 810
Balance at end of year 702,511 694,561 691,853
RETAINED EARNINGS AND OTHER SHAREHOLDERS'
EQUITY:
Balance at beginning of year 356,327 318,977 296,191
Net income 165,620 128,632 119,386
Dividends on common stock ($1.60
per share each year) (88,008) (87,494) (87,432)
Dividends on preferred stock (3,690) (3,690) (8,358)
Other 60 (98) (810)
Balance at end of year 430,309 356,327 318,977
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Balance at beginning of year (13,354) (11,173) (11,191)
Net income 165,620 128,632 119,386
Foreign currency translation adjustments (7,363) (2,181) 18
Total comprehensive income 158,257 126,451 119,404
Deduct net income included in comprehensive
Income. (165,620) (128,632) (119,386)
Other comprehensive income (loss) (7,363) (2,181) 18
Balance at end of year (20,717) (13,354) (11,173)
UNALLOCATED STOCK HELD BY TRUSTEE FOR
RETIREMENT SAVINGS:
Balance at beginning of year (25,945) (28,360) (30,565)
Distributions 2,647 2,415 2,205
Balance at end of year (23,298) (25,945) (28,360)
TOTAL COMMON SHAREHOLDERS' EQUITY AT
END OF YEAR $1,088,805 $1,011,589 $ 971,297
The accompanying notes are an integral part of these statements.
</TABLE>
</PAGE>
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - Summary of significant accounting policies:
Basis of accounting:
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.
Use of estimates:
Preparing financial statements requires the use of estimates. Management
makes appropriate estimates and judgments based upon available information.
Actual results may differ from accounting estimates as new events occur or
additional information is obtained.
Consolidation principles:
The Consolidated Financial Statements include the accounts of the Company
and its subsidiaries, all of which are wholly owned. Significant intercompany
balances and transactions have been eliminated. Independent power investments
are accounted for using either the cost or equity method depending on the
Company's ability to exercise control over the operations of the particular
investment.
</PAGE>
<PAGE>
Plant, property, depreciation and amortization:
The year-end balances of the major classifications of property, plant,
and equipment are detailed in the following table:
December 31
1998 1997
Thousands of Dollars
Utility plant:
Electric:
Generation (including
jointly-owned) $ 724,483 $ 718,504
Transmission 373,630 364,638
Distribution 550,844 520,213
Other 192,899 216,925
Natural Gas:
Production and storage 75,658 70,337
Transmission 152,804 148,295
Distribution 146,896 138,676
Other 29,633 38,610
Total Utility 2,246,847 2,216,198
Nonutility plant:
Coal 237,913 241,835
Oil and natural gas 388,153 363,193
Technology 113,474 86,617
Electric generation 76,189 75,585
Other 49,252 14,176
Total Nonutility 864,981 781,406
Total Plant $3,111,828 $2,997,604
The cost of additions to and replacement of plant, including an allowance
for funds used during construction (AFUDC) of utility plant, is capitalized.
The rate used to compute AFUDC is determined in accordance with a formula
established by the Federal Energy Regulatory Commission (FERC) and was an
average of 8.3 percent for 1998, 8.0 percent for 1997, and 7.2 percent for
1996. Costs of utility depreciable units of property retired plus costs of
removal less salvage are charged to accumulated depreciation and no gain or
loss is recognized. Gain or loss is recognized upon the sale or other
disposition of Nonutility property. Maintenance and repairs of plant and
property as well as replacements and renewals of items determined to be less
than established units of plant are charged to operating expenses.
With respect to the sale of the regulated generation assets, the Company
first expects to recover the book value of those assets and the costs of the
sale transaction. Proceeds in excess of the book value and transaction costs
are expected to reduce the amounts to be collected from ratepayers in the form
of competitive transition charges (CTC).
Included in the plant classifications are Utility plant under
construction in the amounts of $37,966,000 and $39,425,000 for 1998 and 1997,
respectively and Nonutility plant under construction in the amounts of
$10,990,000 and $17,259,000 for 1998 and 1997, respectively. Also included in
the table above are electric generating and transmission assets held for sale
with an approximate cost and accumulated depreciation of $901,000,000 and
$327,000,000, respectively.
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
</PAGE>
<PAGE>
depreciation and depletion approximated 3.0 percent for 1998 and 1997 and 2.9
percent for 1996 of the depreciable and depletable Utility plant at the
beginning of the year.
The Company's Nonutility oil and natural gas operations use the
successful efforts method of accounting for exploration and development costs.
Jointly owned electric plant:
The Company is a joint-owner of Colstrip Units 1, 2, and 3 and of
transmission facilities serving these Units. At December 31, 1998, 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 $186,627 $286,200 $45,265
Plant under construction 273 413 --
Accumulated depreciation 101,608 113,371 14,231
*This is an approximate ownership percentage based on capacity rights
on the various segments of the transmission system.
The Company also owns $42,437,000 and $33,370,000 of the Nonutility
Colstrip Unit 4 share of common production plant and transmission plant which
is included in Nonutility plant "Electric generation" in the property, plant
and equipment table above. Production plant under construction was $406,000.
The accumulated depreciation related to Unit 4 production and transmission
plant was $18,633,000 and $8,501,000, 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.
Reclamation fund:
As a result of a restructured coal supply agreement (CSA) entered into in
August 1998, the Company maintains a reclamation fund representing restricted
cash necessary to meet its estimated reclamation obligation under the CSA. The
funds required for these reclamation obligations will be invested until
reclamation is performed. At December 31, 1998, the fund was invested entirely
in a money market account. The Company regularly accrues an expense and an
offsetting liability associated with its reclamation obligation. The
reclamation fund had no effect on the Company's accumulated liability.
Utility and Telecommunication revenue and expense recognition:
Operating revenues are recorded on the basis of service rendered. In
order to match revenues with associated expenses, the Company accrues unbilled
revenues for electric, natural gas, and telecommunication services delivered to
customers but not yet billed at month-end.
Regulatory assets and liabilities:
For its regulated operations, the Company follows SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation". Pursuant to this
pronouncement, certain expenses and credits, normally reflected in income as
incurred, are recognized when included in rates and recovered from or refunded
</PAGE>
<PAGE>
to the customers. As such, the Company has recorded the following regulatory
assets and liabilities that will be recognized in expenses and revenues in
future periods when the matching revenues are collected.
1998 1997
Assets Liabilities Assets Liabilities
Thousands of Dollars
Income taxes $119,080 $ 119,643
Colstrip Unit 3
carrying charge 40,325 42,156
Conservation programs 33,353 33,965
Competitive transition
charges 56,059 58,983
Investment tax credits $ 33,819 $ 35,182
Other 43,308 9,474 42,344 8,743
Subtotal 292,125 43,293 297,091 43,925
Less:
Current portions 16,197 5,057 15,615 2,522
Total $ 275,928 $ 38,236 $ 281,476 $ 41,403
Income taxes reflect the impacts of temporary differences that will be
recovered in rates in future periods. The Montana Public Service Commission
(PSC) provided in its August 1985 order a carrying charge and recovery of
depreciation that were deferred and are being amortized to income over the
remaining 23-year life of Colstrip Unit 3 to compensate the Company for
unrecovered costs of its investment for the period the plant was in service
from January 10, 1984 to August 29, 1985. Conservation programs represent the
Company's Demand Side Management (DSM) programs that are in rate base and are
being amortized to income over a ten-year period. The CTC's, which relate to
natural gas properties that were removed from regulation on November 1, 1997,
are being recovered through rates over 15 years. Investment tax credits and
account balances included in Other are either being amortized currently or are
those items subject to regulatory confirmation in future regulatory
proceedings.
Changes in regulation or changes in the competitive environment could
cause recovery of these costs through rates to become uncertain, resulting in
the Company not meeting the criteria of SFAS No. 71. If the Company were to
discontinue application of SFAS No. 71 for some or all of its operations, the
regulatory assets and liabilities related to those portions would have to be
eliminated from the balance sheet and included in income in the period when
the discontinuation occurred unless recovery of those costs was provided
through rates charged to those customers in a portion of the business that
remains regulated. In conjunction with the ongoing changes in the electric
and natural gas industries, the Company will continue to evaluate the
applicability of this accounting principal to those businesses.
As a consequence of the issuance by the PSC of the natural gas
restructuring order, the Company's natural gas production assets were removed
from SFAS No. 71 accounting in the fourth quarter of 1997. The timing of the
removal of the electric generating assets from SFAS No. 71 is expected to
coincide with the sale of the Company's interests in the generating
facilities. Recovery of the Company's existing regulatory assets related to
electric generation is provided in the electric restructuring legislation. For
further information on the sale of the Company's interest in the generating
facilities see Note 4 - "Deregulation and Asset Divestiture".
Cash and cash equivalents:
The Company considers all liquid investments with original maturities of
three months or less to be cash equivalents.
</PAGE>
<PAGE>
Storm damage and environmental remediation costs:
The estimated costs of storm damage and environmental remediation
obligations for Utility operations are charged against established, regulator
approved operating reserves when such losses are probable and reasonably
estimatable. The reserves are adequate to provide for all known obligations
and may be increased, if appropriate, by adjusting the annual accrual rate.
The reserves' balances at December 31, 1998 and 1997 were approximately
$2,000,000 and $2,600,000, respectively, and are included in current
liabilities on the Consolidated Balance Sheet.
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 and Nonutility
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 and liabilities" in
this note and also Note 5 - "Income tax expense".
Net income per share of common stock:
Basic net income per share of common stock is computed for each year
based upon the weighted average number of common shares outstanding. In
accordance with SFAS No. 128, "Earnings per Share", diluted net income per
share of common stock reflects the potential dilution that could occur if
securities or other contracts to issue common stock were exercised or converted
into common stock or resulted in the issuance of common stock that shared in
the earnings of the Company.
Asset impairment:
In accordance with SFAS No. 121, "Accounting for the Impairment of Long-
Lived Assets and for Long-Lived Assets to be Disposed Of", the Company
periodically reviews long-lived assets for impairment whenever events or
changes in circumstances indicate that the carrying amount of an asset may not
be recoverable. In 1998, the Company recorded an expense of $1,600,000 in
accordance with SFAS No. 121.
Comprehensive income:
SFAS No. 130, "Reporting Comprehensive Income", defines comprehensive
income as the change in equity of a business enterprise during a period from
transactions and other events and circumstances from non-owner sources. SFAS
No. 130 requires that an enterprise report all components of comprehensive
income in the period in which they are recognized. These components are net
income and other comprehensive income. Net income includes such items as
income from continuing operations, discontinued operations, extraordinary
items, and cumulative effects of changes in accounting principle. Other
comprehensive income includes foreign currency translations, adjustments of
minimum pension liability, and unrealized gains and losses on certain
investments in debt and equity securities.
For the years ended December 31, 1998, 1997, and 1996, the Company's
sole items of other comprehensive income were foreign currency translation
adjustments of $7,363,000, $2,181,000, and $18,000, respectively, to retained
earnings. There are no current income tax effects resulting from the
adjustments. The 1998 adjustment included both the change in the valuation of
the assets of the Company's Canadian operations and a change in the rate used
to adjust certain Canadian assets. Until November 1, 1997, the plant of the
Company's natural gas utility operations, owned by a wholly owned subsidiary,
was included in the natural gas utility rate base. As such, the Company
</PAGE>
<PAGE>
earned a rate of return on these assets stated at their historical costs,
converted to U.S. dollars using historical foreign currency exchange rates.
When the assets were transferred from the Company's regulated operations to
the Nonutility operations, and removed from utility rate base, they were
converted to U.S. dollars using current foreign currency exchange rates which
resulted in a decrease of approximately $5,100,000 in retained earnings in
1998.
Derivative financial instruments:
The Company has formal policies regarding the execution, recording, and
reporting of derivative instruments related to the marketing and trading of
electricity, oil, natural gas, and natural gas liquids. The purpose of the
policies is to manage a portion of the price risk associated with its
Nonutility producing assets, firm-supply commitments, and natural gas
transportation agreements. The Company uses derivatives as hedging
instruments to achieve earnings targets, reduce earnings volatility, and
provide more stabilized cash flows. When fluctuations in natural gas and
crude oil market prices result in the Company realizing gains on the
derivative instruments into which it has entered, the Company is exposed to
credit risk relating to the nonperformance by counterparties of their
obligations to make payments under the agreements. Such risk to the Company
is mitigated by the fact that the counterparties, or the parent companies of
such counterparties, are investment grade financial institutions. The Company
does not anticipate any material impact to its financial position, results of
operations, or cash flow as a result of nonperformance by counterparties.
To manage a portion of Nonutility price risk, the Company uses a variety
of derivative instruments including crude oil and natural gas swap and option
agreements to hedge revenue from anticipated production of crude oil and
natural gas reserves, supply costs, and transportation commitments to its firm
markets. Under swap agreements, the Company receives or makes payments based
on the differential between a specified price and a variable price of oil or
natural gas when the hedged transaction is settled. The variable price is
either a crude oil or natural gas price quoted on the New York Mercantile
Exchange or a quoted natural gas price in Inside FERC's Gas Market Report or
other recognized industry index. These variable prices are highly correlated
with the market prices received by the Company for its natural gas and crude
oil production or paid by the Company for commodity purchases. Under option
agreements, the Company makes or receives monthly payments at the settlement
date based on the differential between the actual price of oil or natural gas
and the price established in the agreement depending on whether the Company
sells or buys the option. At December 31, 1998, the Company had no hedge
agreements on crude oil. The Company had swap and option agreements on
approximately 1.3 Bcf of Nonutility natural gas, or 7 percent of its expected
production from proved, developed, and producing Nonutility natural gas
reserves through October 1999. The Company had swap and option agreements to
hedge approximately 4.1 Bcf of Nonutility natural gas, or 20 percent of its
expected delivery obligations under long-term natural gas sales contracts
through December 1999. In addition, the Company had swap and option
agreements to hedge approximately 2.3 Bcf, or 4 percent, of its Nonutility
natural gas pipeline transportation obligations under contracts through
October 2000.
The Company accounts for derivative transactions through hedge
accounting. The Company designates all of its derivatives as fair value
hedges. A fair value hedge is based on the following criteria:
? The hedged item is specifically identified as a recognized asset or a firm
commitment.
? The hedged item is a single asset or a portfolio of similar assets.
</PAGE>
<PAGE>
? The hedged item presents an exposure to changes in fair value for the hedged
risk that could affect earnings.
? The hedged item is not an asset or liability that is measured at fair value
with changes in fair value attributable to the hedged risk reported
currently in earnings.
Gains or losses from these derivative instruments are reflected in
operating revenues on the Consolidated Statement of Income at the same time as
the recognition of the revenue or expense associated with the underlying
hedged item. If the Company determines that any portion of the underlying
hedged item will not be produced or purchased, the unmatched portion of the
instrument is marked-to-market and any gain or loss is recognized in the
Consolidated Statement of Income. If the Company terminates a hedging
instrument prior to the date of the anticipated natural gas or crude oil
production, commodity purchase or transportation commitment, the gain or loss
from the agreement is deferred in the Consolidated Balance Sheet at the
termination date. At December 31, 1998, the Company had no material deferred
gains or losses related to these transactions.
The Company also 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 natural gas price
fluctuations. At December 31, 1998, the Company believes it would not
experience any materially adverse impacts from the risks inherent in these
instruments.
SFAS No. 133, issued by the FASB in 1998, requires that all derivative
instruments be recorded on an entity's balance sheet at fair value. The
statement also expands the definition of a derivative and requires that
changes in the fair value of the derivatives is recognized each period in
current earnings or comprehensive income. The gains or losses on the
derivative instruments that are reported in comprehensive income will be
reclassified into current earnings in the periods in which the earnings are
impacted by the variability of the cash flows of the hedged item. The
ineffective portion of all hedges will be recognized in current earnings. The
new statement is effective for all fiscal quarters of all fiscal years
beginning after June 15, 1999. The Company has not yet determined the impact
that the adoption of the new standard will have on its earnings or financial
position.
Fair value of financial instruments:
1998 1997
Carrying Fair Carrying Fair
Amount Value Amount Value
Thousands of Dollars
Assets:
Investments in independent
power projects (cost basis
only) $ 394 $ 1,543 $ 5,584 $ 9,063
Reclamation fund 41,542 41,542 47,312 47,312
Other significant investments 83,102 83,102 34,704 34,704
Liabilities:
Mandatorily redeemable preferred
securities $ 65,000 $ 69,160 $ 65,000 $ 70,850
Long-term debt(including due
within one year) 794,621 829,870 734,827 743,713
The following methods and assumptions were used to estimate fair value:
</PAGE>
<PAGE>
Investments in independent power projects - 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.
Reclamation fund and 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. Fair value
for the remainder of the investments 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.
Mandatorily redeemable preferred securities and long-term debt - The fair
value was estimated using quoted market rates for the same or similar
instruments. Where quotes were not available, fair value was estimated by
discounting expected future cash flows using year-end incremental borrowing
rates.
</PAGE>
<PAGE>
NOTE 2 - Contingencies:
The Company is required by an order of the Federal Energy Regulatory
Commission (FERC) to implement a plan to mitigate the impact of Kerr Project
operations on fish, wildlife, and habitat. Implementation will require
payments of approximately $135,000,000 between 1985 and 2020, the license
term. The net present value of the total payments, assuming a 9.5 percent
discount rate, is approximately $57,000,000, an amount the Company recognized
as license costs in plant and long-term debt in the Consolidated Balance Sheet
in 1997. Included in the $135,000,000 is a payment of approximately
$15,600,000 to fund the Fish and Wildlife Implementation Strategy for the 1985
to 1997 period.
FERC's order is subject to judicial review by the United States Court of
Appeals for the District of Columbia Circuit. Pursuant to a related FERC
order, the Company is not obligated to pay approximately $15,600,000 to fund
the Fish and Wildlife Implementation Strategy for the 1985 to 1997 while the
order is subject to judicial review.
In November 1992, the Company applied to FERC to relicense nine Madison
and Missouri River hydroelectric projects, a generating capacity of 292 MWs
(Project 2188). The Company estimates that the cost of environmental
mitigation proposed by FERC's staff in the license proceeding is approximately
$162,000,000, net present value. A license order is expected in late 1999 or
early 2000.
The Kerr Project and Project 2188 are assets to be sold under the terms
of the Agreement for the Company's sale of its generation assets. For further
information on the sale of the Company's interest in the generating facilities
see Note 4 - "Deregulation and Asset Divestiture". At closing of the sale,
PP&L Global will assume the obligation to make payments required to comply
with the license conditions. The Company, however, retained the obligation to
make (i) the $15,600,000 payment for the Fish and Wildlife Implementation
Strategy referred to above and (ii) to the extent not reimbursed by PP&L
Global through the capital and maintenance budget to be agreed upon by the
Company and PP&L Global, other payments regarding "pre-closing" license
compliance expenditures.
Houston Lighting & Power (Reliant Energy), the purchaser of lignite
produced by Northwestern Resources Co. (Northwestern), a Company subsidiary,
settled litigation regarding the terms of the Lignite Supply Agreement (LSA)
between it and Northwestern. The LSA governs the delivery of approximately
9,000,000 tons of lignite per year and is effective until July 29, 2015.
Northwestern realizes revenues of approximately $25,000,000 per year from
management and dedication fees under LSA terms. Under the terms of the
settlement, lignite prices will continue to be set under the pre-settlement
LSA pricing terms until June 30, 2002. Reliant Energy will pay from July 1,
2002 through July 30, 2015, the lesser of a re-determined price set to be
competitive with Powder River Basin Coal supplies, or the price that would
have otherwise been paid under the pre-settlement LSA pricing terms. Reliant
Energy and Northwestern are negotiating terms to amend the LSA and implement
the settlement.
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 financial position or its
consolidated results of operations.
</PAGE>
<PAGE>
NOTE 3 - Commitments:
Purchase commitments:
In 1994, the Company entered a contract to purchase 98 MWs of seasonal
capacity from Basin Electric Power Cooperative (Basin). The rate for the
contract year beginning in November 1997 was approximately 3.2 cents per kWh
and will increase each subsequent year to approximately 7.4 cents per kWh in
the final contract year, which begins in November 2009. This contract is
included in the asset sale agreement with PP&L Global for the sale of the
Company's interest in the generating facilities. Although not specifically
named in the restructuring legislation, costs associated with disposal and
reassignment of this contract are also expected to be collectable through the
Competitive Transition Charges (CTC).
The Company also has long-term purchase contracts with certain qualifying
facilities (QF's) 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 Company currently has 15
QF contracts, with expiration terms ranging from 2003 through 2031. Three
contracts account for 96 percent of the 101 MWs of capacity provided by these
facilities. These QF contracts were intended to be sold or reassigned in
conjunction with the Company's sale of electric generating facilities,
however, they were excluded from the asset sale agreement with PP&L Global.
Management is evaluating options for dealing with these contracts. In
accordance with the restructuring legislation, costs associated with disposal
and reassignment of these contracts are also expected to be collected through
the CTC.
The Nonutility operations have one natural gas take-or-pay contract that
expires in 2006, natural gas transportation contracts that begin expiring in
2000 and two electric firm capacity contracts that expire in mid-2001.
A Nonutility lignite 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, 1998, the remaining payments under this agreement were
$7,152,000. Under current mine plans, these payments should be recovered
through lignite sales.
Total payments under all of these contracts for the prior three years
were as follows:
Thousands of Dollars
Utility Nonutility Total
Electric Natural Gas
1996 $ 30,751 $ 8,100 $ 3,245 $ 42,096
1997 44,153 7,554 3,289 54,996
1998 50,611 2,998 19,809 73,418
The present value of future minimum payments, at an assumed discount rate
of 8 percent, under the above agreements is estimated as follows:
Thousands of Dollars
Utility Nonutility Total
Electric Natural Gas
1999 $ 15,979 $ 3,554 $ 27,317 $ 46,850
2000 15,113 3,225 25,608 43,946
2001 14,787 2,767 10,235 27,789
2002 14,587 2,433 1,820 18,840
2003 14,346 746 1,685 16,777
Remainder 151,801 1,291 16,338 169,430
$ 226,613 $ 14,016 $ 83,003 $ 323,632
</PAGE>
<PAGE>
In 1997, Touch America entered a joint construction effort with Williams
Companies and Enron called FTV Communications LLC (FTV) for the purpose of
constructing a fiber-optic route from Portland, Oregon to Los Angeles,
California. From October 1997 to December 1998, Touch America has loaned FTV
$28,500,000 in separate notes of various amounts at fixed rates of interest of
approximately 6 percent per annum. These notes are payable on demand, except
that any payments depend on the unanimous vote of the members of FTV.
Construction of the route will cost in excess of $100,000,000. At December
31, 1998, the Company estimated that remaining construction costs will be less
than $10,000,000. Payment of all the notes outstanding is expected upon the
completion of construction, which is scheduled to be completed in the second
quarter of 1999.
In October 1998, the Company contracted with Northern Telecom, Inc. to
upgrade equipment on certain fiber-optic cable networks and install such
equipment on recently constructed networks. These projects are expected to be
completed in the fourth quarter of 2000 at a cost of $33,900,000, of which
$12,000,000 was paid in 1998, and $16,500,000 and $5,400,000 are expected to
be paid in 1999 and 2000, respectively.
In December 1998, the Company entered into a contract to implement an
enterprise resource planning system (ERP) to better manage its information
resources. The system is scheduled for completion in September 2000 at a cost
of approximately $40,000,000.
Sales commitments:
The Nonutility oil and natural gas operations have agreed to supply
approximately 92 Bcf of natural gas to four co-generation facilities. These
contracts begin expiring in 2005. The Company has sufficient proven,
developed, and undeveloped reserves, and controls related sales of production
sufficient to supply all of the remaining natural gas required by these
contracts.
The Company has several commitments to sell electricity under contracts,
which have terms expiring over the next six years. One such contract includes
a fixed-price for a portion of the deliveries. When the sale of the Company's
generation assets is finalized, and to the extent that this contract is not
addressed in the electric restructuring transition process, the Company will
be subject to the commodity price risks associated with supplying that portion
of the contract. However, due to the uncertainties relating to the supply
requirements of the contract, the timing of the sale of the generation assets,
and the eventual outcome of the electric restructuring process, the Company
cannot determine at this time the potential effects of this contract on the
Company's future results of operations.
Lease commitments:
On December 30, 1985, the Company sold its 30 percent 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 annual lease payments of
approximately $32,000,000 over the remaining term of the 25-year lease. The
unregulated leasehold interest and its related assets and liabilities and
contract obligations will be sold as part of the generation sale to PP&L Global
and accordingly the lease would be assumed by the buyer. There are no other
material minimum operating lease payments. Capitalized leases are not material
and are included in other long-term debt.
Rental expense for the prior three years, including Colstrip Unit 4, was
$58,800,000, $56,600,000, and $55,500,000 for 1998, 1997, and 1996
respectively.
</PAGE>
<PAGE>
Note 4 - Deregulation and asset divestiture:
Natural Gas
Since 1991, the Company's natural gas utility business has been in
transition to a competitive environment to provide commodity and related
services to wholesale and retail customers. In Montana, the "Natural Gas
Restructuring and Customer Choice Act" was signed into law in May 1997
allowing natural gas utilities to open their systems to full customer choice
for gas supply.
In response to the Company's restructuring filing, in October 1997, the
PSC approved an order (Order) giving additional natural gas customers of the
Company the right to choose their own suppliers. The decision allowed
approximately 230 smaller industrial and larger commercial customers using
5,000 dekatherms or more of natural gas annually, to have choice beginning in
November 1997. The 24 former natural gas supply customers using 60,000 or
more dekatherms of natural gas annually, who represented approximately 49
percent of the pre-choice load, have had choice since 1991. The Company's
remaining 140,000 customers will have choice no later than July 1, 2002. Pilot
programs for natural gas customers began on November 2, 1998. Through
December 1998, approximately 232 customers, representing approximately 54
percent of the Utility's pre-choice natural gas supply load have chosen
alternate suppliers.
Natural gas transmission, distribution, and storage will remain
regulated by the PSC and the Company retains the right to seek rate
adjustments related to these services after a two year rate freeze. The
Company will also continue to offer regulated supply service at rates set by
the PSC for the transition period or such shorter period as determined by the
PSC. Following this period, the Company will offer natural gas supply to
retail and wholesale customers through its unregulated business segments.
In accordance with the Order, in November 1997, significantly all of the
Utility natural gas production assets were transferred to an unregulated
affiliate at an agreed-to amount, which was $33,600,000 below the existing
book value. This difference between transfer value and the book value and the
existing $25,400,000 of regulatory assets related to the natural gas
production assets were approved as a Competitive Transition Charge (CTC) to be
recovered from transmission and distribution customers in rates over a 15-year
period. The transition plan also includes a fixed-price supply contract
through 2002 between the unregulated gas supply division and the regulated
distribution division to serve the remaining customers who have not chosen
other suppliers.
The Order also froze base rates for two years and accepted the
continuation of the gas cost tracker and the Gas Transportation Clause (GTAC)
procedures.
Electric
Montana's "Electric Industry Restructuring and Customer Choice Act" was
also signed into law in May 1997. The legislation provided for choice of
electricity supplier for the Company's large customers by July 1, 1998, for
pilot programs for residential and small commercial customers by July 1, 1998
and choice for all customers no later than July 1, 2002. Through December
1998, approximately 50 customers, representing approximately 10 percent of the
Utility's pre-choice load have chosen alternate suppliers. As with the
Utility natural gas business, transmission and distribution services will
remain fully regulated by FERC and the PSC and the Company retained the right
to seek rate adjustments related to these services.
</PAGE>
<PAGE>
The legislation provides the collection of CTC's by the Company in order
to recover its non-mitigatable transition costs, specifically recovery of
above-market qualifying facility power-purchase contract costs and regulatory
assets associated with the generation business, and recovery for utility-owned
above-market generation costs over the transition period of up to four years.
The legislation also established a rate moratorium on electric rates for all
customers for two years beginning July 1, 1998, and an electric-energy supply
component rate moratorium for an additional two years for smaller customers.
The legislation provides that rates cannot be increased under the rate
moratorium except under limited circumstances.
As required by the electric legislation, the Company filed a
comprehensive transition plan with the PSC in July 1997. The filing contained
the Company's transition plan, including the proposed handling and resolution
of transition costs, and addressed other issues required by the legislation.
Initial hearings on the filing began in April 1998 and the issues involved in
the restructuring filing were separated into groups. The PSC rendered a
decision in June 1998 on the issues relating to customer choice for the large
industrial group and the pilot programs. Pilot programs for electric
customers began concurrently with the natural gas pilot program on November 2,
1998. The Company expects a decision on the remaining issues, including the
amount of transition costs, the effect of the sale of the generation assets
discussed below, and the Uniform Systems Benefits Charge once the details of
the sale are final.
On November 2, 1998, the Company announced that it had entered into a
definitive Asset Purchase Agreement (the Agreement) with PP&L Global, Inc
(PP&L Global), a subsidiary of PP&L Resources, Inc. Under the Agreement, PP&L
Global agreed to purchase the Company's interest in 12 of its 13 hydroelectric
facilities, all four coal-fired thermal generating plants, and a leasehold
interest in Colstrip Unit 4 for a total gross capacity of 1,557 MWs. PP&L
Global will also acquire the power purchase contract with Basin and two power
exchange agreements. The sale does not include the power purchase contracts
with QF's or the 3-MW Milltown Dam near Missoula, Montana.
The sale is subject to the satisfaction of various conditions and the
receipt of required regulatory approvals. The transfer of the Company's
licenses to operate the hydroelectric facilities is subject to approval by the
FERC. Final determination of proceeds and the related transmission facilities
to be included in the sale are subject to the sales of two other owners'
interests in the Colstrip plants, which must be approved by those owners'
state regulatory commissions. The sale of the Company's unregulated leasehold
interest in Colstrip Unit 4 is subject to approval by the purchasers of power
under two long-term sales agreements related to that unit. Although the
Agreement is not contingent upon inclusion of Colstrip Unit 4, such inclusion,
or the potential exclusion, will impact the amount of proceeds received as
well as the amount of transmission facilities included in the sale. The
Company anticipates this transaction will be completed by the end of 1999.
Although the Company has remained in the electric trading business to
take full advantage of the opportunities to sell excess and buy needed
electricity, and fulfill contractual commitments, the Company will exit the
electric commodity trading and marketing business following the sale.
The costs of completion of these potential transactions include legal,
accounting, and consulting fees, employee-related costs, asset relocation
costs, and other expenses. Total transaction costs may reach $50,000,000 and
will reduce the proceeds realized from the sale. There may also be income
taxes associated with the transactions.
The Company's Mortgage and Deed of Trust imposes a lien on all physical
properties including the generation assets and pollution control equipment on
</PAGE>
<PAGE>
some of the thermal generating facilities, therefore, restrictions may exist
on the use of proceeds.
This divestiture is expected to be a complex process involving many
factors. The Company may have little or no direct control over some of these
factors; therefore, it can give no assurance as to the successful
implementation. If the Company is unsuccessful in implementing the sale of
the generation assets or any other elements of the deregulation process, the
potential exists for writeoff of regulatory assets and the recording of
effects of adverse purchase power contracts. The restructuring legislation
does, however, provide for, and management is expecting, full recovery of all
regulatory assets and other transition costs.
On March 30, 1998, the Company submitted a filing with the FERC
requesting increased rates for bundled wholesale electric service to two rural
electric cooperatives. Resolution of this filing is expected before the end
of 1999.
As in the natural gas legislation, the issuance of transition bonds was
approved to lower transition costs. During the electric transition period,
savings related to these financings are available to the Company to offset cost
increases that would not be reflected in rates due to the rate moratorium. In
addition, under the legislation, if, during the transition period, the earnings
of the electric utility fall below a predetermined return on equity, the
utility's obligation to flow investment tax credit (ITC) benefits to ratepayers
in future years is reduced. Any such ITC reduction in the utility's regulatory
obligation provides an economic benefit to the Company and increases income in
that year. No such benefit was recognized in the results of operations for
1998.
</PAGE>
<PAGE>
<TABLE>
<CAPTION>
NOTE 5 - Income tax expense:
Income before income taxes was as follows:
1998 1997 1996
Thousands of Dollars
<S> <C> <C> <C>
United States $ 246,242 $ 177,114 $ 181,393
Canada (2,927) 12,780 7,706
Other countries 479 608 2,262
$ 243,794 $ 190,502 $ 191,361
The provision for income taxes differs from the amount of income tax that
would be expected by applying the applicable U.S. statutory federal income tax
rate to pretax income as a result of the following differences:
1998 1997 1996
Thousands of Dollars
Computed "expected" income tax expense $ 85,328 $ 66,675 $ 66,976
Adjustments for tax effects of:
Statutory depletion (4,156) (2,891) (2,317)
Tax credits (4,722) (11,645) (5,286)
State income tax, net 7,393 7,147 5,772
Reversal of utility book/tax
depreciation 2,784 5,636 4,054
Other (8,453) (3,052) 2,776
Actual income tax expense $ 78,174 $ 61,870 $ 71,975
Income tax expense as shown in the Consolidated Statement of Income
consists of the following components:
1998 1997 1996
Thousands of Dollars
Current:
United States $ 88,233 $ 36,680 $ 44,304
Canada 1,212 994 3,309
Other countries 3,684 445
State 13,462 9,835 8,487
102,907 51,193 56,545
Deferred:
United States (20,331) 6,491 15,590
Canada (1,851) 2,802 135
State (2,551) 1,384 (295)
(24,733) 10,677 15,430
$ 78,174 $ 61,870 $ 71,975
</TABLE>
</PAGE>
<PAGE>
<TABLE>
<CAPTION>
Deferred tax liabilities (assets) are comprised of the following:
December 31
1998 1997
Thousands of Dollars
<S> <C> <C>
Plant related $ 403,832 $ 390,776
Investment in Nonutility generation projects 7,132 25,530
Other 35,344 41,499
Gross deferred tax liabilities 446,308 457,805
Coal reclamation (47,487) (46,820)
Amortization of gain on sale/leaseback (12,755) (13,860)
Investment tax credit amortization (21,833) (22,862)
Other (59,082) (44,551)
Gross deferred tax assets (141,157) (128,093)
Net deferred tax liabilities 305,151 329,712
Less current deferred tax assets-net (18,755) (10,539)
Total noncurrent deferred tax liabilities $ 323,906 $ 340,251
</TABLE>
The change in net deferred tax liabilities differs from current year
deferred tax expense as a result of the following:
Thousands of
Dollars
Change in noncurrent deferred tax $(16,345)
Regulatory assets related to income taxes 1,168
Current deferred tax assets-net (8,216)
Amortization of investment tax credits (1,363)
Other 23
Deferred tax expense $(24,733)
</PAGE>
<PAGE>
NOTE 6 - Common stock:
The Company has a Shareholder Protection Rights Plan that 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, 2009, unless redeemed earlier or exchanged by the Company.
The Company's Board of Directors has authorized a share repurchase
program over the next five years to repurchase up to 10,000,000 shares, or 18
percent, of the Company's outstanding common stock.
As of yearend 1998, the Company had 55,060,520 common shares
outstanding. The repurchase of common stock may be made, from time to time,
on the open market or in privately negotiated transactions. The number of
shares to be purchased and the timing of the purchases will be based on the
level of cash balances, general business conditions, and other factors,
including alternative investment opportunities.
The Company's Dividend Reinvestment and Stock Purchase Plan permits
participants to: (a) acquire additional shares of common stock through the
reinvestment of dividends on all or any specified number of common and/or
preferred shares registered in their own names, or through optional cash
payments of up to $60,000 per year; (b) deposit common and preferred stock
certificates into their Plan accounts for safekeeping; and allows for other
interested investors (residents of certain states) to make initial purchases
of common shares with a minimum of $100 and a maximum of $60,000 per year.
The Company has a Retirement Savings Plan (Plan) that covers all regular
eligible employees. The Company, on behalf of the employee, contributes a
matching 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 percent 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 loan are made, long-term debt and the offset in
common shareholders' equity are both reduced. At December 31, 1998,
1,122,347 shares had been allocated to the participants' accounts. Expense for
the Plan is recognized using the Shares Allocated Method, and the pre-tax
expense was $4,923,000, $5,194,000 and $6,046,000 for 1998, 1997, and 1996,
respectively.
Under the Long-Term Incentive Plan, options have been issued to Company
employees. Options issued to 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
Nonutility employees under the Key Employee Incentive Stock Option Plan 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. Options were granted at
the average of the high and low prices as reported on the New York Stock
Exchange composite tape on the date granted, and expire ten years from that
date.
</PAGE>
<PAGE>
Previously, restricted stock awards of 66,335 shares were issued to
certain Nonutility employees under the Long-Term Incentive Plan. Upon the
achievement of performance goals 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.
At December 31, 1998, there were 9,285 shares of restricted stock remaining.
<TABLE>
<CAPTION>
Option activity is summarized below:
1998 1997 1996
Wtd Avg Wtd Avg Wtd Avg
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
<S> <C> <C> <C> <C> <C> <C>
Outstanding, beginning
of year 540,665 $22.01 694,804 $21.91 569,982 $21.95
Granted 1,117,329 49.00 - - 164,400 21.63
Exercised 351,281 22.51 125,753 21.45 11,578 19.04
Cancelled 32,666 26.94 28,386 22.02 28,000 22.31
Outstanding, end of year 1,274,047 $45.42 540,665 $22.01 694,804 $21.91
</TABLE>
Shares under option at December 31, 1998 are summarized below:
<TABLE>
<CAPTION>
Options Outstanding Options Exercisable
Wtd Avg Wtd Avg Wtd Avg
Exercise Exercise Exercise
Exercise Price Range Shares Price Life (yrs) Shares Price
<S> <C> <C> <C> <C> <C>
$20.06 to $22.63 180,718 $22.01 6 143,750 $22.10
$36.00 to $38.34 258,000 37.06 9 - -
$53.06 835,329 53.06 10 - -
1,274,047 143,750
</TABLE>
As permitted by SFAS No. 123, "Accounting for Stock-Based Compensation",
the Company has elected to follow Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees" (APB 25) and related
interpretations in accounting for its employee stock options. Under APB 25,
because the exercise price of the Company's employee stock options equals the
market price of the underlying stock on the date of grant, no compensation
expense is recognized. Disclosure of pro-forma information regarding net
income and earnings per share is required by SFAS No. 123. This information
has been determined as if the Company had accounted for its employee stock
options under the fair value method of that statement. The weighted-average
fair value of options granted in 1998 and 1996 was $7.12 and $1.73 per share,
respectively. The fair value of each option grant was estimated on the date
of grant using the binomial option-pricing model with the following weighted-
average assumptions used for grants in 1998 and 1996, respectively: risk-free
interest rate of 5.08 percent and 6.87 percent; expected life of 10 and 8.4
years; expected volatility of 19.34 percent and 10.46 percent and a dividend
yield of 6.51 percent and 6.83 percent. Had the Company used SFAS No. 123,
compensation expense would have increased $795,000, $195,000, and $108,000 for
1998, 1997, and 1996 respectively.
</PAGE>
<PAGE>
NOTE 7 - 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 is in three series as detailed in the following table:
Stated and Shares Issued Thousands
Liquidation and Outstanding of Dollars
Series Price* 1998 1997 1998 1997
$6.875 $100 360,800 360,800 $ 36,080 $ 36,080
6.00 100 159,589 159,589 15,959 15,959
4.20 100 60,000 60,000 6,025 6,025
Discount (410) (410)
580,389 580,389 $ 57,654 $ 57,654
*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 and
$103 per share for the $4.20 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
October 2013, after which the redemption price is $100 per share.
</PAGE>
<PAGE>
NOTE 8 - Company obligated mandatorily redeemable preferred securities of
subsidiary trust:
Montana Power Capital I (Trust) was established as a wholly owned
business trust of the Company for the purpose of issuing common and preferred
securities (Trust Securities) and holding Junior Subordinated Deferrable
Interest Debentures (Subordinated Debentures) issued by the Company. At
December 31, 1998 and 1997, the Trust held 2,600,000 units of 8.45 percent
Cumulative Quarterly Income Preferred Securities, Series A (QUIPS). Holders
of the QUIPS are entitled to receive quarterly distributions at an annual rate
of 8.45 percent of the liquidation preference value of $25 per security. The
sole asset of the Trust is $67,000,000 of Subordinated Debentures, 8.45
percent Series due 2036, issued by the Company. The Trust will use interest
payments received on the Subordinated Debentures it holds to make the
quarterly cash distributions on the QUIPS.
The Trust Securities are subject to mandatory redemption upon repayment
of the Subordinated Debentures at maturity or redemption. The Company has the
option at any time on or after November 6, 2001, to redeem the Subordinated
Debentures, in whole or in part. The Company also has the option, upon the
occurrence of certain events, to redeem the Subordinated Debentures, in whole
but not in part, which would result in the redemption of all the Trust
Securities. The Company has the right to terminate the Trust at any time and
cause the pro rata distribution of the Subordinated Debentures to the holders
of the Trust Securities.
In addition to the Company's obligations under the Subordinated
Debentures, the Company has guaranteed, on a subordinated basis, payment of
distributions on the Trust Securities, to the extent the Trust has funds
available to pay such distributions and has agreed to pay all of the expenses
of the Trust (such additional obligations collectively, the Back-up
Undertakings). Considered together with the Subordinated Debentures, the
Back-up Undertakings constitute a full and unconditional guarantee by the
Company of the Trust's obligations under the QUIPS. The Company is the owner
of all the common securities of the Trust, which constitute 3 percent of the
aggregate liquidation amount of all the Trust Securities.
</PAGE>
<PAGE>
NOTE 9 - Long-term debt:
The Company's Mortgage and Deed of Trust (the Mortgage) 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
designated as Secured Medium-Term Notes and those securing Pollution Control
Revenue Bonds. The Mortgage may impose some restrictions on the use of
proceeds realized from the sale of the electric generating assets and power
purchase contracts.
Long-term debt consists of the following:
December 31
1998 1997
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 -
maturing 1999-2025 7.20%-8.11% 88,000 108,000
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 15,500
Natural Gas Transition Bonds -6.20%, due 2012 62,700
ESOP Notes Payable - 9.2%, due 2004 22,392 25,104
Unsecured Medium-Term Notes:
Series A - maturing 1998-2022 8.68%-8.9% 19,500 22,000
Series B - maturing 2006-2026 7.07%-7.96% 115,000 55,000
Revolving Credit Agreements 14,241 45,715
Other 71,779 62,269
Unamortized Discount and Premium (4,196) (3,966)
794,621 734,827
Less: Portion due within one year 96,292 81,659
$ 698,329 $ 653,168
Both the electric and natural gas legislation authorized the issuance of
transition bonds, often referred to as securitization which involves the
issuance of a non-recourse debt instrument which is repaid through, and
secured by, the recovery of the regulatory assets through a specified
component of future revenues, thereby reducing the credit risk of the
securities. This specific component of revenues is referred to as a
competitive transition charge (CTC). Following the April 1998 natural gas
related PSC Financing Order approving issuance of up to $65,000,000 of such
bonds, in December 1998, $62,700,000 of bonds, carrying a 6.2 percent interest
rate and maturing in March 2013, were issued by a special purpose entity (SPE)
which is a wholly owned subsidiary of the Company. At December 31, 1998,
approximately $1,700,000 is classified as due within one year in the
Consolidated Balance Sheet.
Although the bonds were issued by an SPE and are without recourse to the
general credit of the Company, the bonds are shown as debt on the Consolidated
Balance Sheet of the Company. Similarly, the right to receive the revenues
pledged to secure the bonds is a specific right of the SPE and not the
Company. However, as a wholly owned subsidiary of the Company, revenues and
expenses of the SPE are shown as revenues and expenses on the Consolidated
Statement of Income of the Company. However, due to the regulatory mechanism
</PAGE>
<PAGE>
for recognizing the operations of the SPE, including the amortization of the
regulatory assets, it is not expected to have a material impact on the results
of operations of the Company.
In order to ensure that the collections by the SPE are neither more nor
less than the amount necessary to pay interest and principal, and the other
related issuance costs, the Company is required to file for, and the PSC is
required to approve periodic adjustments, or true-ups, to the annual amounts to
be collected by the SPE.
In December 1997, Altana Exploration Ltd. (Altana), a wholly owned
Canadian subsidiary purchased the stock of a Canadian company, for
approximately $26,500,000 in U.S. dollars. Financing for the purchase was
provided through an Extendible Revolving Term Credit Agreement between Altana
and the Royal Bank of Canada. The maximum amount of credit available under
this Agreement is $28,000,000 in Canadian dollars. At December 31, 1998 and
1997, the U.S. dollar amounts outstanding under the agreement were $14,241,000
($21,796,000 Canadian dollars) and $15,715,000 ($22,459,000 Canadian dollars),
respectively. These amounts are included in "Revolving Credit Agreements" in
the table above.
In April 1997, the Company entered into a $160,000,000 Revolving Credit
Agreement for certain of its Nonutility operations. Under terms of the new
Agreement, the amount of the facility decreased on March 31, 1998, reducing
the borrowing ability to $100,000,000. This Agreement terms on April 4, 2000,
and all outstanding borrowings must be repaid on this date. Fixed or variable
interest rate options are available under the facility with facility fees or
commitment fees on the unused portions.
In June 1997, in response to FERC's decision regarding the Kerr
mitigation plan discussed in Item 8, "Financial Statements and Supplementary
Data - Note 2 to the Consolidated Financial Statements", the Company
recognized long-term debt of approximately $57,000,000 which is included in
"Other" in the table above. Approximately $31,000,000 is classified as due
within one year in the Consolidated Balance Sheet at December 31, 1998.
Debt repayments for the five years ending December 31, 2003, on the long-
term debt outstanding at December 31, 1998, amount to: $96,000,000 in 1999;
$38,000,000 in 2000; $46,000,000 in 2001; $9,000,000 in 2002; and $25,000,000
in 2003.
</PAGE>
<PAGE>
NOTE 10 - Short-term borrowing:
The Company has 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, 1998, the Company had lines of credit consisting of
$110,000,000 committed and $105,000,000 uncommitted. There are facility fees
or commitment fees on the committed lines of credit which are not significant.
The Company has the ability to issue up to $145,000,000 of commercial paper
based on the total of unused committed lines of credit and revolving credit
agreements.
Short-term borrowings and average interest rates were as follows:
December 31
1998 1997
Amount Rate Amount Rate
Thousands of Dollars
Notes payable to banks $ 40,000 5.87% $ 89,100 6.82%
Commercial paper 29,820 6.04% 44,858 6.46%
$ 69,820 $133,958
</PAGE>
<PAGE>
NOTE 11 - 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.
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. In December 1998, the Company curtailed
the plan and in accordance with SFAS No. 88, "Employers' Accounting for
Settlements and Curtailments of Defined Benefit Pension Plans" accrued
approximately $4,000,000 of expense.
In addition to providing pension benefits, the Company and its
subsidiaries provide certain health care and life insurance benefits for
eligible retired employees. In 1994, the Company established a pre-funding
plan for postretirement benefits for Utility employees retiring after
January 1, 1993. The assets of the plan consist primarily of domestic and
foreign corporate stocks, domestic corporate bonds, and U.S. Government
securities. The PSC allows the Company to include in rates all Utility OPEB
cost on the accrual basis provided by SFAS No. 106.
The following tables provide a reconciliation of the changes in the
plans' benefit obligations and fair value of assets over the two-year period
ending December 31, 1998, and a statement of the funded status as of
December 31 of both years:
Pension Benefits Other Benefits
1998 1997 1998 1997
Thousands of Dollars
Benefit obligation at January 1 $247,903 $221,459 $ 25,153 $ 25,294
Service cost on benefits earned 8,170 6,595 1,019 803
Interest cost on projected benefit
obligation 18,289 16,285 1,864 1,677
Plan amendments 8,387 325
Actuarial (gain)/loss 5,878 12,891 1,909 (1,833)
Curtailments (4,303) 137
Gross benefits paid (10,923) (9,789) (2,269) (788)
Benefit obligation at December 31 $273,401 $247,903 $ 27,676 $ 25,153
Fair value of plan assets at
January 1 $259,059 $222,866 $ 8,168 $ 5,740
Actual return on plan assets 39,765 40,375 1,036 993
Employer contributions 4,000 1,847 1,908
Gross benefits paid (8,943) (8,182) (2,269) (473)
Fair value of plan assets
at December 31 $289,881 $259,059 $ 8,782 $ 8,168
</PAGE>
<PAGE>
Pension Benefits Other Benefits
1998 1997 1998 1997
Thousands of Dollars
Funded status at January 1 $ 16,463 $ 11,156 $(18,894) $(16,984)
Unrecognized net:
Actuarial gain (54,169) (40,473) (6,582) (8,583)
Prior service cost 12,980 8,691 826
Transition obligation (337) 1,905 16,988 18,194
Net amount recognized
at December 31 $ (25,063) $(18,721) $ (7,662) $ (7,373)
The following table provides the amounts recognized in the statement of
financial position as of December 31 of both years:
Pension Benefits Other Benefits
1998 1997 1998 1997
Thousands of Dollars
Prepaid benefit cost $ 4,028 $ 2,403
Accrued benefit cost (29,091) (21,124) $ (7,662) $ (7,373)
Additional minimum liability (net) (4,618)
Intangible asset 4,618
Net amount recognized
at December 31 $(25,063) $(18,721) $ (7,662) $ (7,373)
The following tables provide the components of net periodic benefit cost
for the pension and other postretirement benefit plans, portions of which have
been deferred or capitalized, for fiscal years 1998, 1997, and 1996:
Pension Benefits
1998 1997 1996
Thousands of Dollars
Service cost on benefits earned $ 8,079 $ 6,625 $ 7,956
Interest cost on projected benefit
obligation 18,238 16,316 15,810
Expected return on plan assets (22,870) (19,900) (16,541)
Amortization of:
Transition obligation (asset) 358 383 375
Prior service cost (credit) 1,468 965 902
Actuarial (gain) loss (1,062) (1,474) 250
Immediate recognition of DC conversion (142)
Net periodic benefit cost 4,069 2,915 8,752
Curtailment (gain) loss 3,964 960
Net periodic benefit cost after
curtailments $ 8,033 $ 3,875 $ 8,752
</PAGE>
<PAGE>
Other Benefits
1998 1997 1996
Thousands of Dollars
Service cost on benefits earned $ 1,020 $ 803 $ 1,074
Interest cost on projected benefit
obligation 1,864 1,677 1,768
Expected return on plan assets (671) (459) (349)
Amortization of:
Transition obligation (asset) 1,206 1,185 1,224
Prior service cost (credit) 69
Actuarial (gain) loss (346) (448) (172)
Net periodic benefit cost $ 3,142 $ 2,758 $ 3,545
In 1998, funding for pension costs exceeded SFAS No. 87 pension expense
by $1,780,000. In 1997, pension costs exceeded SFAS No. 87 pension expense by
$5,441,000, and in 1996, pension costs funded were less than SFAS No. 87
pension expense by $188,000. The differences were deferred for recognition in
future periods as funding is reflected in rates. At December 31, 1998, the
regulatory liability was $4,125,000.
The following assumptions were used in the determination of actuarial
present values of the projected benefit obligations:
Pension Benefits Other Benefits
1998 1997 1998 1997
Weighted average assumptions as
of December 31
Discount rate 6.75% 7.00% 6.75% 7.00%
Expected return on plan assets 9.00% 9.00% 9.00% 9.00%
Rate of compensation increase 3.97% 4.89% 3.75% 4.50%
Assumed health care costs trend rates have a significant effect on the
amounts reported for the health care plans. A 1 percent change in assumed
health care cost trend rates would have the following effects:
1% Increase 1% Decrease
Thousands of Dollars
Effect on total of service and interest
cost component of net periodic post-
retirement health care benefit cost $ 194 $ (182)
Effect on the health care component of
the accumulated postretirement benefit
obligation 1,483 (1,368)
The assumed 1999 health care cost trend rates used to measure the
expected cost of benefits covered by the plans is 7.50 percent. The trend rate
decreases through 2004 to 5 percent.
In 1995, the Company accrued the estimated expected postretirement
benefit obligation for the plan curtailment at its Colorado mining operations
as part of the writedown of long-lived assets. As such, these operations are
no longer included in the above numbers.
</PAGE>
<PAGE>
NOTE 12 - Information on industry segments:
The Company operates a regulated Utility involving the generation,
purchase, transmission, and distribution of electricity and the purchase,
transportation, and distribution of natural gas. The Company's Nonutility
operations principally involve telecommunication operations which sells long
distance, Internet, and dedicated line services and equipment and designs,
develops, constructs, operates, maintains, and manages a fiber-optic network
and digital microwave facilities. Other Nonutility operations include the
mining and sale of coal and lignite, exploration for, and the development,
production, processing, and sale of oil and natural gas. It also conducts the
trading of electricity and trading and marketing of natural gas. In addition,
the Company manages long-term power sales, and develops and invests in
independent power projects and other energy-related businesses.
The Company's open-access and reorganization plan for its regulated
Natural Gas Utility was approved for implementation by the PSC, effective
November 1, 1997. Under the approved plan, significantly all of the regulated
Utility's natural gas production assets, including those of its Canadian
subsidiary, were transferred to its unregulated oil and natural gas operations
as of that date.
Financial information relating to the segment information for foreign
operations is not considered material.
</PAGE>
<PAGE>
<TABLE>
<CAPTION>
Operations Information:
Year Ended
December 31, 1998
Thousands of Dollars
UTILITY Electric Natural Gas
<S> <C> <C>
Sales to unaffiliated customers $ 450,719 $ 107,052
Intersegment sales 7,576 727
Interest revenue 2,460 311
Interest expense 50,016 11,834
Pre-tax operating income (loss) 124,841 15,019
Earnings (loss) from unconsolidated investments
Income tax expense 26,388 171
Depreciation, depletion and amortization 56,524 8,705
Capital expenditures 61,334 21,989
Identifiable assets 1,577,583 405,670
<CAPTION>
NONUTILITY
Oil and Independent
Coal* Natural Gas Power**
<S> <C> <C> <C>
Sales to unaffiliated customers $ 177,961 $ 208,116 $ 73,707
Intersegment sales 38,796 24,597 2,014
Interest revenue 2,630 379 4,979
Interest expense 443 1,203 58
Pre-tax operating income 32,560 7,640 (4,806)
Earnings (loss) from unconsolidated investments 89,525
Income tax expense 8,107 (1,007) 32,315
Depreciation, depletion and amortization 6,596 22,259 9,005
Capital expenditures 7,746 53,319 11,329
Identifiable assets 235,438 289,453 120,675
<CAPTION>
NONUTILITY (continued)
Tele-
Communications** Other
<S> <C> <C>
Sales to unaffiliated customers $ 87,748 $ 47,987
Intersegment sales 1,298 1,913
Interest revenue 969 1,466
Interest expense 1 9,716
Pre-tax operating income (loss) 39,051 (9,464)
Earnings from unconsolidated investments 10,909
Income tax expense 19,772 (7,572)
Depreciation, depletion and amortization 7,090 4,088
Capital expenditures 56,181 1,314
Identifiable assets 187,556 69,053
CORPORATE
Interest expense $ (803)
Capital expenditures 189
Identifiable assets 42,667
<CAPTION>
RECONCILIATION TO CONSOLIDATED
Segment Consolidated
Total Adjustments*** Total
<S> <C> <C> <C>
Sales to unaffiliated customers $1,153,290 $1,153,290
Intersegment sales 76,921 $ (76,921)
Interest revenue 13,194 (5,869) 7,325
Interest expense 72,468 (6,125) 66,343
Pre-tax operating income 204,841 204,841
Earnings (loss) from unconsolidated investments 100,434 100,434
Income tax expense 78,174 78,174
Depreciation, depletion and amortization 114,267 114,267
Capital expenditures 213,401 213,401
Identifiable assets 2,928,095 2,928,095
<FN>
* Sales under one coal contract with Reliant Energy amounted to $110,172,000.
** The Telecommunications and Independent Power segments are dependent on a single customer and two customers,
respectively, the losses of which would have a material adverse effect on the segments.
*** Identifiable assets excludes intersegment receivables which are eliminated for consolidation. The
adjustments include certain eliminations between the business segments.
</FN>
</TABLE>
</PAGE>
<PAGE>
<TABLE>
<CAPTION>
Operations Information:
Year Ended
December 31, 1997
Thousands of Dollars
UTILITY Electric Natural Gas
<S> <C> <C>
Sales to unaffiliated customers $ 435,986 $ 122,355
Intersegment sales 4,685 588
Interest revenue 6,450 1,615
Interest expense 46,257 11,426
Pre-tax operating income (loss) 111,002 37,994
Earnings (loss) from unconsolidated investments
Income tax expense 24,297 11,347
Depreciation, depletion and amortization 51,674 11,939
Capital expenditures 122,639 15,679
Identifiable assets 1,560,055 390,463
<CAPTION>
NONUTILITY
Oil and Independent
Coal* Natural Gas Power**
<S> <C> <C> <C>
Sales to unaffiliated customers $ 169,825 $ 163,656 $ 70,932
Intersegment sales 34,164 3,120 1,820
Interest revenue 2,095 2,065 3,972
Interest expense 424 106 32
Pre-tax operating income 31,051 16,310 (17)
Earnings (loss) from unconsolidated investments (2,202) 14,980
Income tax expense (700) 10,776 6,762
Depreciation, depletion and amortization 9,043 16,922 2,774
Capital expenditures 4,588 140,437 294
Identifiable assets 247,981 290,110 156,282
<CAPTION>
NONUTILITY (continued)
Tele-
Communications Other
<S> <C> <C>
Sales to unaffiliated customers $ 46,691 $ 939
Intersegment sales 799 5,719
Interest revenue 143 5,955
Interest expense 6,043
Pre-tax operating income (loss) 11,492 (4,543)
Earnings from unconsolidated investments 435
Income tax expense 4,824 4,564
Depreciation, depletion and amortization 2,494 494
Capital expenditures 27,902 53
Identifiable assets 101,581 7,987
CORPORATE
Interest expense
Capital expenditures $ 94
Identifiable assets 51,437
<CAPTION>
RECONCILIATION TO CONSOLIDATED
Segment Consolidated
Total Adjustments*** Total
<S> <C> <C> <C>
Sales to unaffiliated customers $1,010,384 $1,010,384
Intersegment sales 50,895 $ (50,895)
Interest revenue 22,295 (4,271) 18,024
Interest expense 64,288 (4,129) 60,159
Pre-tax operating income 203,289 203,289
Earnings (loss) from unconsolidated investments 13,213 13,213
Income tax expense 61,870 61,870
Depreciation, depletion and amortization 95,340 95,340
Capital expenditures 311,686 311,686
Identifiable assets 2,805,896 2,805,896
<FN>
* Sales under one coal contract with Reliant Energy amounted to $104,668,000.
** The Telecommunications and Independent Power segments are dependent on a single customer and two customers,
respectively, the losses of which would have a material adverse effect on the segments.
*** Identifiable assets excludes intersegment receivables which are eliminated for consolidation. The
adjustments include certain eliminations between the business segments.
</FN>
</TABLE>
</PAGE>
<PAGE>
<TABLE>
<CAPTION>
Operations Information:
Year Ended
December 31, 1996
Thousands of Dollars
UTILITY Electric Natural Gas
<S> <C> <C>
Sales to unaffiliated customers $ 430,171 $ 128,528
Intersegment sales 5,793 649
Interest revenue 2,253 73
Interest expense 46,652 11
Pre-tax operating income (loss) 122,123 40,830
Earnings (loss) from unconsolidated investments
Income tax expense 33,729 12,958
Depreciation, depletion and amortization 46,648 11,638
Capital expenditures 74,930 31,060
Identifiable assets 1,526,197 421,955
<CAPTION>
NONUTILITY
Oil and Independent
Coal* Natural Gas Power**
<S> <C> <C> <C>
Sales to unaffiliated customers $ 166,678 $ 124,532 $ 75,322
Intersegment sales 31,448 293 1,426
Interest revenue 1,690 530 3,095
Interest expense 404 28 35
Pre-tax operating income 34,358 17,687 1,675
Earnings (loss) from unconsolidated investments (2,777) 21,174
Income tax expense 7,907 6,936 11,286
Depreciation, depletion and amortization 5,653 17,080 3,793
Capital expenditures 8,386 25,021 3,198
Identifiable assets 268,297 184,512 156,044
<CAPTION>
NONUTILITY (continued)
Tele-
Communications Other
<S> <C> <C>
Sales to unaffiliated customers $ 27,641 $ 1,939
Intersegment sales 133 44
Interest revenue 112 1,017
Interest expense 40 4,322
Pre-tax operating income (loss) 2,657 (2,041)
Earnings (loss) from unconsolidated investments
Income tax expense 960 (1,801)
Depreciation, depletion and amortization 911 680
Capital expenditures 27,902 6
Identifiable assets 52,139 17,954
CORPORATE
Interest expense
Capital expenditures $ 1,178
Identifiable assets 71,117
<CAPTION>
RECONCILIATION TO CONSOLIDATED
Segment Consolidated
Total Adjustments*** Total
<S> <C> <C> <C>
Sales to unaffiliated customers $ 954,811 $ 954,811
Intersegment sales 39,786 $ (39,786)
Interest revenue 8,770 (2,771) 5,999
Interest expense 51,492 (2,722) 48,770
Pre-tax operating income 217,289 217,289
Earnings (loss) from unconsolidated investments 18,397 18,397
Income tax expense 71,975 71,975
Depreciation, depletion and amortization 86,403 86,403
Capital expenditures 171,681 171,681
Identifiable assets 2,698,215 2,698,215
<FN>
* Sales under one coal contract with Reliant Energy amounted to $102,181,000.
** The Telecommunications and Independent Power segments are dependent on a single customer and two customers,
respectively, the losses of which would have a material adverse effect on the segments.
*** Identifiable assets excludes intersegment receivables which are eliminated for consolidation. The
adjustments include certain eliminations between the business segments.
</FN>
</TABLE>
</PAGE>
<PAGE>
SUPPLEMENTARY DATA
OIL AND NATURAL GAS PRODUCING ACTIVITIES
For the years ended December 31, 1998, 1997, and 1996, net recoverable oil and
natural gas reserves, excluding royalty volumes and volumes controlled under
purchase contract, of the Utility and Nonutility operations were estimated
as follows:
<TABLE>
<CAPTION>
1998
U.S. CANADA STORAGE
PROVED DEVELOPED AND UNDEVELOPED RESERVES:
<S> <C> <C> <C>
UTILITY OPERATIONS:
Natural Gas (Mmcf):
Beginning Balance 2,097 0 56,840
Production (235)
Additions
(Sales) and Purchases of Reserves in Place
Transfers Out
Revisions - Other
Revisions - Price 1,469
Ending Balance 1,862 0 58,309
NONUTILITY OPERATIONS:
Natural Gas (Mmcf):
Beginning Balance 191,250 125,135
Production (14,099) (11,216)
Additions 39,774 41,456
(Sales) and Purchases of Reserves in Place 1,400 (2,808)
Transfers In
Revisions - Other (4,635) (16,001)
Revisions - Price (17,640) 1,573
Ending Balance 196,050 138,139
Natural Gas
Liquids (Bbls):
Beginning Balance 8,246,554 2,542,585
Production (218,000) (325,000)
Additions 1,321,300 431,000
(Sales) and Purchases of Reserves in Place (57,000)
Revisions - Other 438,943 (667,585)
Revisions - Price (1,302,000) (2,000)
Ending Balance 8,486,800 1,922,000
Oil (Bbls):
Beginning Balance 5,025,390 2,700,071
Production (242,800) (258,000)
Additions 543,300 22,000
(Sales) and Purchases of Reserves in Place (540,000)
Revisions - Other (874,071)
Revisions - Price (2,050,390) (109,000)
Ending Balance 3,275,500 941,000
1998
U.S. CANADA
PROVED DEVELOPED RESERVES:
UTILITY OPERATIONS:
Natural Gas (Mmcf):
Ending Balance 1,862 0
NONUTILITY OPERATIONS:
Natural Gas (Mmcf):
Ending Balance 133,578 118,452
Natural Gas Liquids (Bbls):
Ending Balance 8,484,116 1,921,728
Oil (Bbls):
Ending Balance 3,275,003 941,000
</TABLE>
</PAGE>
<PAGE>
<TABLE>
<CAPTION>
1997
U.S. CANADA STORAGE
PROVED DEVELOPED AND UNDEVELOPED RESERVES:
<S> <C> <C> <C>
UTILITY OPERATIONS:
Natural Gas (Mmcf):
Beginning Balance 71,952 94,445 55,624
Production (3,764) (3,401)
Additions 1,216
(Sales) and Purchases of Reserves in Place (13,082)
Transfers Out (53,711) (91,044)
Revisions - Other 702
Revisions - Price
Ending Balance 2,097 0 56,840
NONUTILITY OPERATIONS:
Natural Gas (Mmcf):
Beginning Balance 160,174 53,011
Production (11,427) (6,529)
Additions 14,920 8,569
(Sales) and Purchases of Reserves in Place 6,039 5,914
Transfers In 53,711 91,044
Revisions - Other (31,918) (26,501)
Revisions - Price (249) (373)
Ending Balance 191,250 125,135
Natural Gas
Liquids (Bbls):
Beginning Balance 3,491,100 3,089,300
Production (473,139) (225,715)
Additions 118,500 184,000
(Sales) and Purchases of Reserves in Place 2,717,377 582,000
Revisions - Other 2,392,716 (1,082,000)
Revisions - Price (5,000)
Ending Balance 8,246,554 2,542,585
Oil (Bbls):
Beginning Balance 6,458,000 3,204,235
Production (746,380) (322,164)
Additions 339,110 2,445,000
(Sales) and Purchases of Reserves in Place (1,145,648) (2,851,000)
Revisions - Other (28,792) 228,000
Revisions - Price 149,100 (4,000)
Ending Balance 5,025,390 2,700,071
1997
U.S. CANADA
PROVED DEVELOPED RESERVES:
UTILITY OPERATIONS:
Natural Gas (Mmcf):
Ending Balance 2,097 0
NONUTILITY OPERATIONS:
Natural Gas (Mmcf):
Ending Balance 139,802 104,799
Natural Gas Liquids (Bbls):
Ending Balance 8,246,554 2,298,585
Oil (Bbls):
Ending Balance 3,474,602 2,079,071
</TABLE>
</PAGE>
<PAGE>
<TABLE>
<CAPTION>
1996
U.S. CANADA STORAGE
PROVED DEVELOPED AND UNDEVELOPED RESERVES:
<S> <C> <C> <C>
UTILITY OPERATIONS:
Natural Gas (Mmcf):
Beginning Balance 75,461 103,475 56,745
Production (5,055) (4,694)
Additions (1,121)
(Sales) and Purchases of Reserves in Place
Revisions - Other 1,546 (4,336)
Revisions - Price
Ending Balance 71,952 94,445 55,624
NONUTILITY OPERATIONS:
Natural Gas (Mmcf):
Beginning Balance 136,660 62,474
Production (8,915) (6,924)
Additions 813 1,702
(Sales) and Purchases of Reserves in Place 19,240 12
Revisions - Other (1,098) (14,847)
Revisions - Price 13,474 10,594
Ending Balance 160,174 53,011
Natural Gas
Liquids (Bbls):
Beginning Balance 3,615,400 3,680,132
Production (232,600) (271,241)
Additions 17,700
(Sales) and Purchases of Reserves in Place (200)
Revisions - Other (43,414) (440,607)
Revisions - Price 151,914 103,316
Ending Balance 3,491,100 3,089,300
Oil (Bbls):
Beginning Balance 5,999,400 4,429,496
Production (539,288) (676,640)
Additions 19,600 118,814
(Sales) and Purchases of Reserves in Place 702,347 58,800
Revisions - Other (130,360) (1,027,636)
Revisions - Price 406,301 301,401
Ending Balance 6,458,000 3,204,235
1996
U.S. CANADA
PROVED DEVELOPED RESERVES:
UTILITY OPERATIONS:
Natural Gas (Mmcf):
Ending Balance 71,121 94,445
NONUTILITY OPERATIONS:
Natural Gas (Mmcf):
Ending Balance 100,067 53,011
Natural Gas Liquids (Bbls):
Ending Balance 3,486,700 3,089,300
Oil (Bbls):
Ending Balance 6,369,000 3,204,235
</TABLE>
</PAGE>
<PAGE>
SUPPLEMENTARY DATA
Oil and Natural Gas Producing Activities (Cont.)
As determined by engineers, Utility natural gas reserves were revised
during 1997 and 1996 due to changes in projected performance or changes in the
Company's ownership interest in specific fields. On November 1, 1997, the PSC
approved the deregulation of the Utility's natural gas production properties,
the result of which was the transfer of all of the Canadian and significantly
all of the U.S. natural gas reserves to the Nonutility operations. Since that
date, Utility natural gas reserves have been produced to maintain Utility
natural gas storage leases and to supply fuel for electric generation.
Nonutility U.S. natural gas and natural gas liquid reserves increased in
1998 with the addition of undeveloped reserves in Colorado and successful
drilling in Wyoming and Oklahoma. However, the additions were partially offset
by downward price revisions of petroleum products. That downward price
revision also caused a significant decrease in U.S. oil reserves. The Canadian
natural gas reserves increased because of successful exploratory drilling in
Southeast Alberta. Oil reserves in Canada decreased due to the sale of an
Alberta producing property and downward price revisions. Canadian oil and
natural gas reserves were also revised downward to reflect poorer than expected
performance in two fields.
Nonutility U.S. natural gas and natural gas liquid reserves increased in
1997 because of the acquisition of reserves in place, successful drilling in
Oklahoma and Wyoming, and the transfer of previously regulated Montana
properties. Oil reserves decreased because of the sale of reserves in Kansas.
The Canadian natural gas reserves increase is due to the purchase of reserves
in place, and transfer of previously regulated Canadian properties to the
Nonutility Supply Division. Oil reserves in Canada also decreased because of
the sale of some Alberta properties.
When the Utility owned the reserves that were transferred to the
Nonutility on November 1, 1997, petroleum engineers estimated reserves on the
basis of Utility business guidelines; that is, mechanical recoverability at
reasonable and prudent costs. With deregulation and transfer, petroleum
engineers began to estimate reserves on the basis of mechanical recoverability
under market price conditions. Estimating reserves on that basis has resulted
in downward revisions of Nonutility U.S. and Canadian natural gas reserves in
1997.
In 1996, the Nonutility U.S. natural gas and oil reserves increased as a
result of higher market prices and the acquisition of reserves in place.
Natural gas reserves were added through the purchase of interests in 250 wells
in northeastern Montana. Oil reserves were added with the purchase of
additional interest in an existing Montana field. The Canadian natural gas and
oil reserves decreased primarily as a result of downward revisions of
engineering estimates for undeveloped reserves.
The following table presents information for 1998, 1997, and 1996 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 net cost of natural gas in underground storage is 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,
</PAGE>
<PAGE>
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.
</PAGE>
<PAGE>
<TABLE>
<CAPTION>
1998 1997 1996
U.S. Canada U.S. Canada U.S. Canada
UTILITY OPERATIONS Thousands of Dollars
At December 31:
<S> <C> <C> <C> <C> <C> <C>
Capitalized costs relating
to natural gas producing
activities $ 2,026 $ 0 $ 2,023 $ 0 $ 87,363 $ 38,551
Accumulated depreciation,
depletion and valuation
allowances 1,853 0 1,833 0 46,881 20,102
Net capitalized costs $ 173 $ 0 $ 190 $ 0 $ 40,482 $ 18,449
For the year ended
December 31:
Costs incurred in natural
gas property acquisition,
exploration and
development activities:
Acquisition of
properties $ 474 $ 49
Exploration $ 35 $ 168 54 191
Development $ (5) $ 0 1 66 501 1,230
Costs reflected in results
of operations:
Production costs $ 98 $ 0 $ 3,361 $ 1,359 $ 4,773 $ 1,510
Exploration expenses (3) 0 35 168 54 191
Development expenses 0 66 22 113
Depreciation, depletion
and valuation
provisions 19 2,072 686 2,667 711
</TABLE>
</PAGE>
<PAGE>
The following table presents information for 1998, 1997, and 1996 on the
capitalized costs relating to Nonutility oil and natural gas producing
activities, costs incurred in Nonutility oil and natural gas property
acquisition, exploration and development activities and results of
Nonutility operations for oil and natural gas producing activities:
<TABLE>
<CAPTION>
1998 1997 1996
U.S. Canada U.S. Canada U.S. Canada
NONUTILITY OPERATIONS Thousands of Dollars
At December 31:
<S> <C> <C> <C> <C> <C> <C>
Capitalized costs relating
to oil and natural gas
producing activities* $271,047 $109,742 $240,436 $113,165 $182,339 $ 87,529
Accumulated depreciation,
depletion and valuation
allowances* 60,186 43,026 49,167 46,131 65,401 44,770
Net capitalized costs $210,861 $ 66,716 $191,269 $ 67,034 $116,938 $ 42,759
For the year ended
December 31:
Costs incurred in oil and
natural gas property
acquisition, exploration
and development
activities:
Acquisition of
properties $ 1,470 $ 1,408 $ 85,606 $ 22,762 $ 4,667 $ 3,722
Exploration 2,197 1,502 4,589 6,036 1,780 2,157
Development 32,747 15,287 21,050 8,535 10,651 3,345
Results of operations for
oil and natural gas
producing activities:
Revenues $ 28,366 $ 18,739 $ 34,182 $ 14,821 $ 26,872 $ 19,789
Production costs 17,029 7,222 10,232 5,041 8,901 6,547
Exploration expenses 2,158 1,439 3,233 2,905 1,670 1,747
Depreciation, depletion
and valuation
provisions 14,675 6,779 12,037 3,781 10,019 6,133
(5,496) 3,299 8,680 3,094 6,282 5,362
Income tax expenses (3,651) 1,472 416 1,380 946 2,393
Results of operations from
producing activities
(excluding corporate
overhead and interest
cost) $ (1,845) $ 1,827 $ 8,264 $ 1,714 $ 5,336 $ 2,969
<FN>
*U.S. capitalized costs relating to these activities include the costs
of support equipment and facilities. Also, U.S. accumulated depreciation,
depletion, and valuation includes the depreciation associated with such
equipment and facilities. The capitalized costs of support equipment and
facilities were $60,681,000 and $54,295,000, and the associated depreciation
was $8,676,000 and $5,288,000 for 1998 and 1997, respectively.
</FN>
</TABLE>
</PAGE>
<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 pre-tax
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>
<PAGE>
<TABLE>
<CAPTION>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS AND CHANGES THEREIN RELATING TO
PROVED OIL AND NATURAL GAS RESERVES
December 31
1998 1997
U.S. Canada U.S. Canada
Thousands of Dollars
<S> <C> <C> <C> <C>
Future cash inflows $ 650,446 $ 273,644 $ 876,733 $ 303,780
Future production and
development costs 327,784 108,436 467,270 151,201
Future income tax expenses 56,167 51,102 94,162 36,253
Future net cash flows 266,495 114,106 315,301 116,326
10% annual discount for
estimated timing
of cash flows 96,136 47,155 122,469 35,008
Standardized measure of
discounted future net
cash flows $ 170,359 $ 66,951 $ 192,832 $ 81,318
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 $ (16,236) $ (11,518) $ (23,620) $ (9,780)
Net changes in prices,
development and production
costs (57,866) (13,339) (30,047) (12,687)
Extensions, discoveries, and
improved recovery, less
related costs 25,625 15,424 60,863 42,699
Revisions of previous quantity
estimates (17,259) (8,916) (20,953) (11,929)
Accretion of discount 21,338 8,937 20,503 7,480
Net change in income taxes 22,793 (5,061) 25,584 968
Other (868) 106 1,601 (1,217)
</TABLE>
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 1998 and 1997, the amount described as other is primarily the result
of changes in the timing of production.
</PAGE>
<PAGE>
QUARTERLY FINANCIAL DATA
Operating revenues, operating income, and net income in thousands of
dollars and net income per common share for the four quarters of 1998 and 1997
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.
<TABLE>
<CAPTION>
Quarter Ended
Dec. 31, Sept. 30, June 30, Mar. 31,
1998 1998 1998 1998
<S> <C> <C> <C> <C>
Utility Operating Revenues $158,908 $124,805 $123,393 $158,968
Utility Operating Income 37,852 34,002 24,979 43,027
Utility Net Income 16,587 10,930 5,022 18,946
Nonutility Operating Revenues 256,091 197,901 157,779 152,801
Nonutility Operating Income 80,737 38,845 24,996 20,836
Nonutility Net Income 52,891 24,950 16,606 15,998
Consolidated Net Income
Available for Common Stock 69,478 35,880 21,628 34,944
Basic Earnings Per Share of
Common Stock $ 1.26 $ 0.65 $ 0.40 $ 0.64
Diluted Earnings Per Share of
Common Stock $ 1.26 $ 0.65 $ 0.39 $ 0.64
<CAPTION>
Quarter Ended
Dec. 31, Sept. 30, June 30, Mar. 31,
1997 1997 1997 1997
<S> <C> <C> <C> <C>
Utility Operating Revenues $152,498 $120,914 $119,862 $170,340
Utility Operating Income 44,140 22,047 20,925 61,884
Utility Net Income 25,557 3,012 2,543 27,996
Nonutility Operating Revenues 155,610 125,253 105,567 121,589
Nonutility Operating Income 21,095 14,744 10,183 21,484
Nonutility Net Income 24,955 12,306 11,287 17,286
Consolidated Net Income
Available for Common Stock 50,512 15,318 13,830 45,282
Basic Earnings Per Share of
Common Stock $ 0.93 $ 0.28 $ 0.25 $ 0.83
Diluted Earnings Per Share of
Common Stock $ 0.92 $ 0.28 $ 0.25 $ 0.83
</TABLE>
</PAGE>
<PAGE>
ITEM 9. DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
See Part 1, "Executive Officers of the Registrant."
Information on The Montana Power Company Directors is incorporated by
reference from the Company's Notice of 1999 Annual Meeting of Shareholders and
Proxy Statement, pages 5-6.
ITEM 11. EXECUTIVE COMPENSATION
Incorporated by reference from Notice of 1999 Annual Meeting of
Shareholders and Proxy Statement, pages 9-18.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Incorporated by reference from Notice of 1999 Annual Meeting of
Shareholders and Proxy Statement, pages 7-8.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
</PAGE>
<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
October 27, 1998 Item 5. Other Events. Discussion of Third
Quarter Net Income.
Item 7 Exhibits. Consolidated Statements of
Income for the Quarters Ended September 30,
1998 and 1997, Nine Months Ended September 30,
1998 and 1997, and for the Twelve Months Ended
September 30, 1998 and 1997. Utility
Operations Schedule of Revenues and Expenses
for the Quarters Ended September 30, 1998 and
1997, Nine Months Ended September 30, 1998 and
1997, and for the Twelve Months Ended
September 30, 1998 and 1997. Nonutility
Operations Schedule of Revenues and Expenses
for the Quarters Ended September 30, 1998 and
1997, Nine Months Ended September 30, 1998 and
1997, and for the Twelve Months Ended
September 30, 1998 and 1997.
November 6, 1998 Item 5. Other Events. Sale of Generation
Assets and Stock Repurchase Program.
December 18, 1998 Item 5. Other Events. Montana Power and
Houston Industries settle Coal Dispute.
</PAGE>
<PAGE>
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
3. Exhibits Incorporation by Reference
Previous
Previous Exhibit
Filing Designation
2 Asset Purchase Agreement 1-4566 2(a)
Form 8-K
Dated
November 2,
1998
3(a) Restated Articles of Incorporation,
as amended 33-56739 3(a)
3(a)(1) Articles of Amendment to the Restated
Articles of Incorporation 1-4566 3(a)(1)
3(a)(2) Articles of Amendment to the Restated
Articles of Incorporation
3(b) By-laws, as adopted dated August 22,
1995 1-4566 3(b)
3(b)(1) Amendment to By-laws dated August 27,
1996 1-4566 3(b)
3(b)(2) Amendment to By-laws dated May 12,
1997 1-4566 3(b)
3(b)(3) Amendment to By-laws dated December 9,
1997
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
4(u) Amendment to Rights Agreement 1-4566 99(a)
dated March 2, 1999 1999
Form 8-K
Dated
March 2, 1999
</PAGE>
<PAGE>
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
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 1996
Management Executives Form 10-K
10(a)(vi) Colstrip Unit #3 Wholesale 1-4566 10(a)
Transmission Service Agreement Form 8-K
(Exhibit F-1 to the Asset Dated
Purchase Agreement November 2, 1998
10(a)(vii) Non-Colstrip Unit #3 Wholesale 1-4566 10(b)
Transmission Service Agreement Form 8-K
(Exhibit F-2 to the Asset Dated
Purchase Agreement) November 2,
1998
10(a)(viii) Generation Interconnection 1-4566 10(c)
Agreement (Exhibit G to the Form 8-K
Asset Purchase Agreement) Dated
November 2,
1998
10(a)(ix) Equity Contribution Agreement 1-4566 10(d)
Form 8-K
Dated
November 2,
1998
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
23 Consent of Independent Accountants
27 Financial Data Schedule
</PAGE>
<PAGE>
<TABLE>
<CAPTION>
THE MONTANA POWER COMPANY AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Thousands of Dollars
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, 1998
Reserves deducted
in balance sheet
from assets to
which they apply:
Doubtful accounts
Utility $ 984 $ 1,749 $ 1,689 $ 1,044
Nonutility 827 182 $ (11) 136 862
Total $ 1,811 $ 1,931 $ (11) $ 1,825 $ 1,906
December 31, 1997
Reserves deducted
in balance sheet
from assets to
which they apply:
Doubtful accounts
Utility $ 924 $ 2,349 $ 2,289 $ 984
Nonutility 636 229 $ 6 44 827
Total $ 1,560 $ 2,578 $ 6 $ 2,333 $ 1,811
December 31, 1996
Reserves deducted
in balance sheet
from assets to
which they apply:
Doubtful accounts
Utility $ 868 $ 1,767 $ 1,711 $ 924
Nonutility 601 236 $ (37) 164 636
Total $ 1,469 $ 2,003 $ (37) $ 1,875 $ 1,560
<FN>
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.
</FN>
</TABLE>
</PAGE>
<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/ Robert P. Gannon
Robert P. Gannon
(Chairman of the Board)
Date: March 23, 1999
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/ Robert P. Gannon Principal Executive
Robert P. Gannon Officer and Director March 23, 1999
(Chief Executive Officer)
/s/ J. P. Pederson Principal Financial
J. P. Pederson and Accounting Officer
(Vice President and Chief and Director March 23, 1999
Financial and Information
Officer)
/s/ Tucker Hart Adams Director March 23, 1999
Tucker Hart Adams
/s/ Alan F. Cain Director March 23, 1999
Alan F. Cain
</PAGE>
<PAGE>
/s/ John G. Connors Director March 23, 1999
John G. Connors
/s/ R. D. Corette Director March 23, 1999
R. D. Corette
/s/ Kay Foster Director March 23, 1999
Kay Foster
/s/ Beverly D. Harris Director March 23, 1999
Beverly D. Harris
/s/ John R. Jester Director March 23, 1999
John R. Jester
/s/ Carl Lehrkind, III Director March 23, 1999
Carl Lehrkind, III
/s/ N. E. Vosburg Director March 23, 1999
N. E. Vosburg
</PAGE>
<PAGE>
EXHIBIT INDEX
Exhibit 12
Statement Re Computation of Ratio Earnings to Fixed Charges
Exhibit 21
Subsidiaries of the Registrant
Exhibit 23
Consent of Independent Accountants
Exhibit 27
Financial Data Schedule
</PAGE>
SIGNATURES (Continued)
Exhibit 12
THE MONTANA POWER COMPANY
Computation of Ratio of Earnings to Fixed Charges
(Dollars in Thousands)
Twelve Months Ended
December 31,
1998 1997 1996
Net Income $ 162,761 $ 127,985 $ 119,147
Income Taxes 78,174 61,870 72,813
$ 240,935 $ 189,855 $ 191,960
Fixed Charges:
Interest $ 66,275 61,720 50,937
Amortization of Debt Discount,
Expense and Premium 1,556 1,538 1,610
Rentals 34,999 34,671 34,470
$ 102,830 $ 97,929 $ 87,017
Earnings Before Income Taxes
and Fixed Charges $ 343,765 $ 287,784 $ 278,977
Ratio of Earning to Fixed Charges 3.34 x 2.94 x 3.21 x
Exhibit 12
THE MONTANA POWER COMPANY
Computation of Ratio of Earnings to Fixed Charges
(Dollars in Thousands)
Twelve Months Ended
December 31,
1995 1994 1993
Net Income $ 59,053 $ 115,963 $ 107,196
Income Taxes 21,573 53,152 54,120
$ 80,626 $ 169,115 $ 161,316
Fixed Charges:
Interest $ 47,330 $ 44,096 $ 48,142
Amortization of Debt Discount,
Expense and Premium 1,567 1,666 1,768
Rentals 35,300 36,586 36,631
$ 84,197 $ 82,348 $ 86,541
Earnings Before Income Taxes
and Fixed Charges $ 164,823 $ 251,463 $ 247,857
Ratio of Earning to Fixed Charges 1.96 x 3.05 x 2.86 x
- -116-
Canadian-Montana Pipe Line Company
An Alberta Corporation 100
Glacier Gas Company
A Montana Corporation 100
Colstrip Community Services Company
A Montana Corporation 100
Montana Power Services Company
A Montana Corporation 100
Montana Power Capital 1
A Montana Corporation 100
MPC Natural Gas Funding Trust
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 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
EMPECO VII - TX3, Inc.
A Montana Corporation
(A wholly-owned subsidiary of Continental
Energy Services, Inc.) 100
Montana Energy Inc.
A Montana Corporation
(A wholly-owned subsidiary of Continental
Energy Services, Inc.) 100
CES International, Inc.
A Cayman Islands Corporation
(A wholly-owned subsidiary of Continental
Energy Services, Inc.) 100
Barge Energy, LLC
A Cayman Islands Limited Life Corporation
(A wholly-owned subsidiary of CES International,
Inc., except 1% held by EMPECO VI - TE, Inc.) 100
PAK Energy, LLC
A Cayman Islands Limited Life Corporation
(A wholly-owned subsidiary of CES International,
Inc., except 1% held by Montana Energy, Inc.) 100
ECI Energy, Ltd.
A Delaware Corporation
Investment in English Partnership in a
Gas-fired Cogeneration Project
(A 47.5% owned subsidiary of Continental
Energy Services, Inc.) 50
Enserch Development Corporation One, Inc.
A Delaware Corporation
(A wholly owned subsidiary of Continental
Energy Services, Inc.) 100
Montana Grimes County, Inc.
A Montana Corporation
(A wholly owned subsidiary of Continental
Energy Services, Inc.) 100
Montana Grimes Frontier, Inc.
A Montana Corporation
(A wholly owned subsidiary of Continental
Energy Services, Inc.) 100
Entech, Inc.
A Montana Corporation 100
Canadian-Montana Gas Company Limited
An Alberta 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 Energy Development Participacoes, Ltd.
A Brazilian Corporation
(99.99% owned by Entech, Inc., .01% owned by Western
Energy Company) 100
Financiera Ulken Sociedad Anonima (SA)
A Uruguayan Corporation
(A wholly-owned subsidiary of Montana
Energy Development Participacoes, Ltd.) 100
Northwestern Resources Co.
A Montana Corporation 100
Altana Exploration Company
A Montana Corporation 100
Montana Power Ventures, Inc.
A Montana Corporation 100
Altana Exploration Ltd.
An Alberta Corporation 100
North American Resources Company
A Montana Corporation 100
Tetragenics Company
A Montana Corporation 100
Touch America, Inc.
A Montana Corporation 100
The Montana Power Trading & Marketing Company
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
Entech Gas Ventures, Inc.
A Montana Corporation 100
The Montana Power Gas Company
A Montana Corporation 100
Syncoal, Inc.
A Montana Corporation 100
Note: The above listed companies are included in the Consolidated Financial
Statements of the registrant.
SUBSIDIARIES OF REGISTRANT Exhibit 21
Percentage of Voting
Securities Owned
by Registrant
- -119-
Exhibit 23
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. 33-43655), to
the incorporation by reference in the Prospectus constituting part of the
Registration Statement on Form S-3 (No. 333-28877), to the incorporation by
reference in the Prospectus constituting part of the Registration Statement on
Form S-3 (No. 33-59573), to the incorporation by reference in the Registration
Statement on Form S-8 (No. 33-24952), to the incorporation by reference in 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), to the incorporation by reference in the Prospectus
constituting part of the Registration Statement on Form S-3 (No. 33-55816), 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. 333-14369), to the incorporation by reference in the Prospectus
constituting part of the Registration Statement on Form S-3 (No. 333-14369-
01), to the incorporation by reference in the Prospectus constituting part of
the Registration Statement on Form S-3 (No. 333-17181), of our report dated
February 4, 1999, appearing on page 57 of The Montana Power Company's Annual
Report on Form 10-K for the year ended December 31, 1998.
/s/ PricewaterhouseCoopers LLP
PRICEWATERHOUSECOOPERS LLP
Portland, Oregon
March 30, 1999
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the
Consolidated Balance Sheet at 12/31/98, the Consolidated Income Statement and
the Consolidated Statement of Cash Flows for the twelve months ended 12/31/98
and is qualified in its entirety by reference to such finanical statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> DEC-31-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,514,462
<OTHER-PROPERTY-AND-INVEST> 717,114
<TOTAL-CURRENT-ASSETS> 328,235
<TOTAL-DEFERRED-CHARGES> 368,284
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,928,095
<COMMON> 702,511
<CAPITAL-SURPLUS-PAID-IN> 2,167
<RETAINED-EARNINGS> 384,127
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,088,805
65,000
57,654
<LONG-TERM-DEBT-NET> 697,803
<SHORT-TERM-NOTES> 69,820
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 95,910
0
<CAPITAL-LEASE-OBLIGATIONS> 526
<LEASES-CURRENT> 382
<OTHER-ITEMS-CAPITAL-AND-LIAB> 852,195
<TOT-CAPITALIZATION-AND-LIAB> 2,928,095
<GROSS-OPERATING-REVENUE> 1,253,724
<INCOME-TAX-EXPENSE> 78,174
<OTHER-OPERATING-EXPENSES> 948,449
<TOTAL-OPERATING-EXPENSES> 1,026,623
<OPERATING-INCOME-LOSS> 227,101
<OTHER-INCOME-NET> 4,862
<INCOME-BEFORE-INTEREST-EXPEN> 231,963
<TOTAL-INTEREST-EXPENSE> 66,343
<NET-INCOME> 165,620
3,690
<EARNINGS-AVAILABLE-FOR-COMM> 161,930
<COMMON-STOCK-DIVIDENDS> 88,008
<TOTAL-INTEREST-ON-BONDS> 45,335
<CASH-FLOW-OPERATIONS> 255,677
<EPS-PRIMARY> 2.95
<EPS-DILUTED> 2.94
</TABLE>
