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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, 1999 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 (406) 497-3000
(Address of principal executive (Zip code) (Registrant's telephone
offices) number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
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Common Stock New York Stock Exchange
Pacific Exchange, Inc.
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:
TITLE OF CLASS
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Preferred Stock
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
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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 $4,602,632,651 at March 3, 2000.
On March 3, 2000, the Company had 105,555,466 shares of common stock
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
(1) Notice of 2000 Annual Meeting of Shareholders and Proxy Statement,
pages 1 - 30, is incorporated into Part III of this report.
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PART I
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When we use the terms "Montana Power," "we," "us," or "our" in this Form
10-K, we mean The Montana Power Company, a Montana corporation, together with
its subsidiaries.
WARNINGS ABOUT FORWARD-LOOKING STATEMENTS
We are 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 us, or
on our behalf, in this 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 statements other than
those of historical fact. Forward-looking statements may be identified, without
limitation, by the use of the words "anticipates," "estimates," "expects,"
"intends," "believes," and similar expressions. We disclaim any obligation to
update any forward-looking statements to reflect events or circumstances after
the date that we file this Form 10-K.
Forward-looking statements that we make 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 our
revenue and cost trends, cost recovery, cost-reduction strategies and
anticipated outcomes, pricing strategies, planned capital expenditures,
financing needs and availability, and changes in the utility and
telecommunication industries and other industries in which we operate. Investors
or other readers of the forward-looking statements are cautioned that these
statements are not a guarantee of future performance and that the
forward-looking statements are subject to risks and uncertainties that could
cause actual results to differ materially from those expressed in, or implied
by, the statements. Some, but not all, of the risks and uncertainties include:
. General economic and weather conditions in the areas in which we
have operations;
. Competitive factors and the effects of restructuring in the
electric, natural gas, and telecommunications industries;
. Sanctity and enforceability of contracts;
. Market prices;
. Environmental laws and policies and 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 and interest rates; and
. Changes in accounting principles or the application of such
principles.
STOCK SPLIT
On June 22, 1999, the Board of Directors approved a two-for-one stock
split of our outstanding common stock. As a result of the split, which was
effective August 6, 1999, for all shareholders of record on July 16, 1999,
55,099,015 outstanding shares of common stock were converted to 110,198,030
shares of outstanding common stock. Unless otherwise noted, we have adjusted all
share and per-share information in this Form 10-K to reflect the split.
ITEM 1. BUSINESS
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GENERAL
The Montana Power Company was incorporated in 1961 under the laws of the
state of Montana as the successor to a corporation formed in 1912. We engage in
a number of diversified energy and communications businesses.
We regularly assess our business units and evaluate opportunities to
create, develop, and maximize the value of our diverse businesses. The Board of
Directors is considering various options to optimize the value of Touch America,
Inc., our telecommunications subsidiary, and maximize shareholder value. On
January 25, 2000, we announced that Goldman, Sachs & Co. will assist us in
evaluating options with respect to implementing a strategy to separate Touch
America from Montana Power. In pursuing this strategy, we will continue to
investigate different approaches, including asset purchases and sales, the
issuance of securities, and other transactions that may materially affect our
results of operations, liquidity, dividends, capital structure, and capital
resources. For additional information on how pursuing our strategies may affect
our liquidity and capital resources, see Management's Discussion and Analysis of
Financial Condition and Results of Operations (MD&A), "Liquidity and Capital
Resources."
Our business is organized as follows:
. UTILITY
We operate regulated electric and natural gas utilities. Our electric and
natural gas service territory covers approximately 107,600 square miles, or
approximately 73 percent of Montana, making us one of the country's largest
utilities in terms of service territory. Dominant industries operating within
our service territory are mining, agriculture, selected manufacturing,
railroads, tourism and recreation, and the forest-products industry. We serve
approximately 439,000 customers, or approximately 80 percent of the population
within our service territory. For information about how weather affects our
utility operations, see MD&A, "Utility Operations."
Regulated Electric Utility
Our regulated electric utility purchases, transmits (movement of bulk
quantities of energy), and distributes (movement of
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energy from transmission system to consumer) electric energy. We provide
electric energy to 191 communities and their surrounding rural areas throughout
Montana. We also provide electric energy to Yellowstone National Park and to
cooperatives that serve approximately 76,000 residents.
On December 17, 1999, we sold substantially all of our electric generating
assets to PPL Montana, LLC, a subsidiary of PP&L Global, Inc., for approximately
$758,600,000. We have used some of the sales proceeds to repurchase shares of
our common stock, and we have begun to use some of the proceeds to retire
long-term debt. We also intend to use some of the proceeds to expand Touch
America.
Pursuant to the terms of our Asset Purchase Agreement with PPL Montana, we
would receive another $152,000,000 from PPL Montana if it were to acquire
additional gross capacity in the Colstrip Units 1, 2, and 3 generating units
located in Colstrip, Montana from Portland General Electric Company (Portland
General) and Puget Sound Energy, Inc. (Puget). On February 29, 2000, the Oregon
Public Utility Commission denied the application of Portland General for
approval to sell Portland General's interest in the Colstrip Units 3 and 4
plants. We cannot predict the ultimate outcome of this proceeding.
For additional information on the sale, its accounting and regulatory
implications, and our use of sale proceeds, see Note 5, "Sale of Electric
Generating Assets," and MD&A, "Liquidity and Capital Resources."
Regulated Gas Utility
Our regulated natural gas utility purchases, transports, distributes, and
stores natural gas. We provide natural gas to 109 communities throughout
Montana.
. NONUTILITY
Our nonutility businesses include telecommunications, coal, independent
power, and oil and natural gas operations. We operate these businesses as
subsidiary companies of our wholly owned subsidiary, Entech, Inc.
Telecommunications
Through Touch America, our telecommunications operation designs, develops,
constructs, operates, maintains, and manages a fiber-optic network and wireless
facilities. Touch America's fiber-optic network, which spans 14 states, is
described in Item 2, "Properties," under the "Telecommunications Properties"
section. Touch America provides wireless services mainly through Personal
Communication Services (PCS) and Local Multi-Point Distribution Services (LMDS).
Touch America also sells long-distance, Internet, and private-line services and
telecommunications equipment.
Coal
Through Western Energy Company, we mine and sell coal at the Rosebud Mine
in Colstrip, Montana, primarily to mine-mouth customers. Through Northwestern
Resources Co., we mine and sell lignite at the Jewett Mine in central Texas,
with all sales to one customer.
Independent Power
Through Continental Energy Services, Inc. (CES), our independent power
operation develops, invests in, and operates independent power projects and
other energy-related businesses. Through the Colstrip Unit 4 Lease Management
Division, it also sells electricity from our leased interest in Colstrip Unit 4.
Oil and Gas
Our oil and natural gas operation explores for, develops, produces,
processes, and sells oil and natural gas in the United States and Canada.
Through our affiliate, The Montana Power Trading & Marketing Company (MPT&M), it
also trades and markets crude oil, natural gas, and natural gas liquids.
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Table The following table shows, for the last three years, revenues
contributed by any class of similar products or services that
accounted for 10 percent or more of consolidated revenues, which
includes Earnings from Unconsolidated Investments.
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Percentage Of Revenues
Contributed By Any Class Of
Similar Products Or Services
That Accounted For
10 Percent Or More Of
Business Unit Consolidated Revenues
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1999 1998 1997
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Electric Utility 34% 36% 43%
Natural Gas Utility -- -- 12%
Telecommunications -- -- --
Coal 15% 14% 16%
Independent Power -- 13% --
Oil and Natural Gas 25% 17% 16%
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FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS
For additional information on the financial results of our segments,
including a discussion of revenues earned by Northwestern Resources from sales
to a single customer and revenues earned by our independent power operations
from sales to two customers, see Note 13, "Information on Industry Segments."
ELECTRIC UTILITY OPERATIONS
. ELECTRIC TRANSMISSION SYSTEM
Our electric transmission system forms an integral part of
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the Northwest Power Pool. This pool consists of the major electric suppliers in
the Pacific Northwest region of the United States; British Columbia, Canada; and
parts of Alberta, Canada.
In April 1996, the Federal Energy Regulatory Commission (FERC) issued
Order No. 888 and Order No. 889 requiring utilities to allow open use of their
transmission systems by other utilities and power marketers. Since then, a
number of companies (including MPT&M when it traded and marketed electricity)
have used our transmission system to transmit power across our system under
terms, conditions, and rates defined in our FERC open access transmission tariff
(OATT), which became effective in July 1996.
In May 1999, FERC began a rulemaking process to establish its authority
regarding Regional Transmission Organizations (RTOs). An RTO is an organization
that attempts to capture synergies and efficiencies created by combining
individually operated transmission systems into a single operation, focusing on
operational and strategic transmission issues. On December 20, 1999, FERC issued
Order No. 2000, its most recent order regarding RTOs. The goal of Order No. 2000
is the voluntary and timely formation of RTOs by all public utilities that own,
operate, or control interstate transmission facilities. In accordance with the
FERC Order, we must file a proposal with FERC by October 15, 2000, describing
our efforts to participate in an RTO that will be operational by December 15,
2001. If efforts to participate in an RTO are unsuccessful, then we must
describe our plans to overcome particular obstacles as we continue to work
toward RTO participation.
We are a member of the Western Systems Coordinating Council (WSCC),
organized by 84 member systems and 21 affiliates in the 14 western states of the
United States; British Columbia, Canada; Alberta, Canada; and Mexico. The WSCC
seeks to ensure reliability of the interconnected transmission system.
We participate in an interconnection agreement with Avista Corporation,
IdaCorp, Inc., and PacifiCorp (which was acquired by Scottish Power). This
agreement provides for the sharing of transmission capacity of certain lines on
the interconnected systems. We also operate, in coordination with our own
transmission lines and facilities, the Colstrip transmission lines and
facilities, which connect to the four Colstrip generating units.
Together with Western Area Power Administration (WAPA), effective July 1,
1999, we terminated a long-standing bilateral transmission arrangement, and
replaced it with service agreements under our respective OATTs. While certain
details remain to be completed, service has commenced pursuant to those OATT
service agreements.
We have been a party to the Pacific Northwest Coordination Agreement
(PNCA), which coordinates the hydroelectric operations of the 18 parties'
hydroelectric generating facilities in the Columbia River Basin. Pursuant to the
Asset Purchase Agreement with PPL Montana and the sale of the Kerr and Thompson
Falls hydroelectric facilities (our former facilities that were coordinated
under the PNCA), we agreed to assign our interest in the PNCA to PPL Montana. We
did not assign this interest at the December 17, 1999, closing of our
transaction with PPL Montana because we had not obtained all necessary consents
and regulatory approvals by that date. We have now obtained the consent of the
other parties to the PNCA for this assignment, which remains subject to FERC
approval. On February 25, 2000, we submitted a joint filing with PPL Montana to
seek FERC approval of the assignment. We expect FERC to take action on the
filings by May 2000.
. ELECTRIC SUPPLY OBLIGATIONS
Montana's Electric Industry Restructuring and Customer Choice Act
(Electric Act) provided our large industrial customers with choice of commodity
supply beginning July 1, 1998; pilot supply programs for our residential and
small commercial customers beginning November 2, 1998; and choice of supply for
all of our customers no later than July 1, 2002. The Electric Act also defined
the role of the Montana Public Service Commission (PSC) in licensing suppliers
in the state, regulating distribution services, and promulgating rules to
prohibit anti-competitive and abusive practices. For additional information on
Montana's Electric Act and the regulatory environment in which our electric
utility operates, see Note 4, "Deregulation and Regulatory Matters."
Under the Electric Act, we are obligated to continue to supply electric
energy to customers in our service territory who have not chosen, or have not
had an opportunity to choose, other power suppliers during the transition
period. This obligation requires us to have a sufficient power supply to meet
these customers` electric needs. Our sales agreement with PPL Montana includes
buyback contracts pursuant to which we expect to purchase electric energy from
PPL Montana to supply our remaining customers. The buyback contracts are
effective through December 31, 2001, and June 30, 2002, after which we may be
required to act as a "default supplier" and supply our remaining customers. At
that time, we will purchase energy as necessary in the secondary market. We
expect to recover any costs related to this electric supply through rates
charged to these customers. For additional information on the effects of
deregulation, see Note 4, "Deregulation and Regulatory Matters."
. COMPETITIVE ENVIRONMENT
Our regulated electric utility is now primarily a transmission and
distribution services utility, and the PSC continues to regulate our
transmission and distribution services and approve the rates that we charge for
these services. By selling substantially all of our electric generating assets
to PPL Montana, we eliminated a high-risk activity. The buyback contracts
entered into with PPL Montana - together with the sale of our assets - eliminate
our operational risk. While we
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may be required to serve as the "default supplier" after the transition period
ends on July 1, 2002, we expect to recover costs incurred to serve these
customers. For information regarding commodity price risk that we face as a
result of the sale of our generating assets, see Note 3, "Commitments," in the
"Sales Commitments" section. For additional information on Montana's Electric
Act and the regulatory environment in which our electric utility operates, see
Note 4, "Deregulation and Regulatory Matters." For information on the sale of
substantially all of our electric generating assets, see Note 5, "Sale of
Electric Generating Assets."
NATURAL GAS UTILITY OPERATIONS
. NATURAL GAS REQUIREMENTS
Natural gas supply requirements in 1999 totaled 18,828 thousands of
dekatherms (MDkt), of which 6,973 MDkt were purchased from third-party contracts
with Montana suppliers and 1,160 MDkt were purchased from third-party contracts
with Canadian suppliers. We purchased a total of 10,695 MDkt, or approximately
56.8 percent of the natural gas supply requirements for the year, from our
unregulated affiliates. We estimate that our natural gas requirements for 2000
will be approximately 20,230 MDkt.
. NATURAL GAS RESOURCES
We fulfill our natural gas requirements through our unregulated
affiliates, which have access to natural gas in the United States and in Canada,
third-party contracts with Montana suppliers, and third-party contracts with
Canadian suppliers. We take delivery of all natural gas within the Montana
border. Approximately two-thirds of our nonaffiliated gas purchases have
contract terms of one year, from November through October. We anticipate that
our unregulated businesses and third-party contracts will supply our natural gas
requirements for 2000.
. GAS TRANSPORTATION
We transported natural gas volumes of 24,426 MDkt in 1999, 27,516 MDkt in
1998, and 26,478 MDkt in 1997. We expect to transport approximately 24,000 MDkt
in 2000. The reduction in transportation volumes is due primarily to anticipated
weaker off-system markets and the loss of a large industrial, on-system
transportation customer.
. COMPETITIVE ENVIRONMENT
Montana's Natural Gas Utility Restructuring and Customer Choice Act
(Natural Gas Act) provided that natural gas utilities, such as Montana Power,
could offer customers choice of natural gas suppliers and provide open access.
Because restructuring is voluntary, no deadline for choice exists. Montana's
Natural Gas Act also defined the PSC's role in licensing suppliers in the state,
regulating transportation and distribution services, and promulgating rules to
prohibit anti-competitive and abusive practices. For additional information on
Montana's Natural Gas Act and the regulatory environment in which our natural
gas utility operates, see Note 4, "Deregulation and Regulatory Matters."
TELECOMMUNICATIONS OPERATIONS
. BUSINESS
Touch America is expanding its nationwide fiber-optic network. We expect
Touch America's fiber network to extend approximately 23,000 miles by the end of
2001. For information on Touch America's fiber-optic network, see Item 2,
"Properties," in the "Telecommunications Properties" section.
Touch America is constructing a fiber network, in conjunction with AT&T,
that will span more than 4,300 miles. The network includes new fiber routes from
Minneapolis to Chicago; from St. Louis, Missouri to Plano, Illinois; from
Sacramento to Salt Lake City; from Salt Lake City to Denver; and from Denver
through Nebraska and Iowa to Chicago. We expect various third parties, including
AT&T, to cover approximately one-half of our estimated $500,000,000 total
project cost.
In January 2000, Touch America announced an exchange of fiber and conduits
with PF.Net, a telecommunications company based in New Jersey. Touch America
will receive approximately 5,900 route miles from PF.Net, with all segments
expected to be complete by the end of 2001.
Touch America is focused on increasing network traffic principally through
a combination of relationships with anchor customers (large-volume commercial or
wholesale customers), alliances with third parties, and acquisitions. Touch
America continues to provide wholesale services through leasing lit (fully
operational) or dim (regeneration equipment but no optical equipment) fiber
capacity, and selling dark (no optical or regeneration equipment) fiber to other
telecommunications companies.
Touch America and New Century Energies entered into a joint venture in
1999, Northern Colorado Telecommunications LLC, to provide a full range of
telecommunications services, including private-line services, to enterprises in
the Denver metropolitan area. Primarily through its PCS and LMDS technologies,
Touch America is creating "last-mile" connections, which connect a fiber network
via wireless applications. In 1999, Touch America and US WEST Wireless entered
into a joint venture, TW Wireless (TWW), to provide "one number" telephone
service in an eight-state region of the Pacific Northwest and Upper Midwest.
That service provides a customer with one directory number for cell phone and
home or business telephones.
On March 13, 2000, Touch America signed an agreement with Qwest
Communications International Inc. to acquire wholesale, private-line, and
long-distance telecommunications services, which currently serve approximately
250,000 customers in the Pacific Northwest, Rocky Mountain, and Upper Midwest
regions. Touch America also would acquire
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approximately 1,800 route miles of fiber within these regions.
For additional information on Touch America's alliances and acquisitions,
see Note 3, "Commitments," in the "Telecommunications" section.
. COMPETITIVE ENVIRONMENT
Our low-cost fiber network helps us to compete in national and regional
telecommunications markets. We attempt to mitigate the risks inherent in the
telecommunications industry by expanding our fiber-optic network and increasing
traffic on that network. We also believe that our presence in the
telecommunications industry for more than 16 years has provided us with
experience that will help reduce our risks.
The trend in telecommunications toward business combinations and alliances
is creating new competitors with resources greater than ours. To succeed, we
must continually change and improve our products in response to rapid
technological developments and changes in operating systems, Internet access and
communications, application and networking software, and computer and
communications hardware. The development of new, technologically advanced
products and services is a complex and uncertain process requiring constant
innovation and the ability to anticipate technological and market trends.
We mitigate this risk through our joint-venture alliances with other
telecommunications companies. Some of these joint ventures, because they are
highly leveraged, expose us to interest rate and financing risk.
In providing interstate telecommunications services, we comply with
federal telecommunications laws and regulations prescribed by the Federal
Communications Commission. At the state level, we are subject to regulations by
the various state public service commissions. We do not expect actions by these
regulatory agencies to adversely affect our operations.
COAL OPERATIONS
. BUSINESS
At our Rosebud Mine in Colstrip, Montana, in the northern Powder River
Basin, Western Energy surface-mines coal and, after crushing, sells it without
further preparation. Rosebud Mine's primary customers are the owners of the four
mine-mouth units in Colstrip, making up approximately 90 percent of Western
Energy's 1999 coal sales volumes. During 1999, Western Energy mined and sold
10,601,000 tons, of which 3,295,000 tons were affiliated sales. We estimate
production to be 11,415,000 tons in 2000, and 11,413,000 tons in 2001.
Northwestern Resources' Jewett Mine, located in central Texas, supplies
surface-mined lignite under a long-term lignite supply agreement (LSA) to the
two electric generating units located adjacent to the mine. Reliant Energy
(Reliant) owns these electric generating units. Northwestern Resources sold
8,934,702 tons in 1999. We estimate that Northwestern Resources' production for
2000 will be 7,800,000 tons, and approximately 8,000,000 tons annually
thereafter.
. COMPETITIVE ENVIRONMENT
We sell our current production from the Rosebud and Jewett mines under
long-term contracts to mine-mouth customers. Western Energy's Rosebud Mine
supplies all of the coal requirements of the Colstrip Units under separate
contracts for Units 1 and 2 versus Units 3 and 4. The coal supply agreement
between Western Energy and the owners of Colstrip Units 1 and 2 provides for a
final price re-opener in 2001. An Amended and Restated Coal Supply Agreement
dated August 28, 1998, settled coal contract disputes and future coal price
re-openers with the owners of Colstrip Units 3 and 4. Prior to mid-2000, Western
Energy expects to see a modest profit reduction as a result of the settlement.
In mid-2000, the new pricing provisions of the Amended and Restated Coal Supply
Agreement take effect. When the new pricing provisions of the Amended and
Restated Coal Supply Agreement are fully implemented in 2002, we expect pretax
income to decrease from current levels by $12,000,000 per year. We expect this
decrease to be partially offset by efficiency and cost-savings measures of
$2,000,000. The December 17, 1999, sale of our interests in Colstrip Units 1, 2,
and 3 did not affect the terms of the coal supply agreements with Colstrip Units
1 and 2 or Units 3 and 4.
The Rosebud Mine also sells coal to other parties because it has
production capacity exceeding the fuel requirements for the Colstrip Units.
Competition for these sales comes from Montana and Wyoming Powder River Basin
producers located south of the mine. These producers generally experience lower
operating costs and lower sulfur content than the coal from the Rosebud Mine.
Therefore, we anticipate only modest contract sales and no significant spot
market sales for the foreseeable future.
Reliant is the purchaser of lignite produced by Northwestern Resources.
The LSA requires Northwestern Resources to produce enough lignite to meet
Reliant's demand through July 30, 2015. The LSA provides for cost reimbursement
plus approximately $25,000,000 per year from the payment of management and
dedication fees charged under the LSA pricing terms.
In late 1998, Reliant and Northwestern Resources settled litigation
regarding the pricing terms of the LSA and signed a letter of intent regarding
amendments to the LSA. This 1998 letter of intent was superseded by a Settlement
Agreement and Amendment of Existing Contracts in 1999. The Settlement Agreement
allows Reliant to blend petroleum coke with the lignite at a 20/80 ratio. As of
December 31, 1999, Reliant had not obtained certain required permits to
implement this change. Recently enacted electric power deregulation in Texas
calls for emission reductions for generating units in the state. The effect of
these environmental changes on Reliant's ability to use petroleum coke will be
assessed in 2000.
Under the terms of the settlement, lignite prices will continue
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to be set under pre-settlement pricing terms through June 30, 2002. From July
1, 2002, through July 30, 2015, lignite prices will be the lesser of (1) a
redetermined price set to be competitive with Powder River Basin coal supplies
(subject to an established minimum), or (2) the price that would have otherwise
been paid under the pre-settlement pricing terms. Northwestern Resources expects
that, if the market value of Powder River Basin coal stays flat until the
agreement is fully implemented, the competitive-pricing structure could result
in a reduction of annual pretax income of approximately $7,000,000 beginning
July 1, 2002, through July 30, 2015. Northwestern Resources plans to mitigate
this effect through efficiency and cost-savings measures.
INDEPENDENT POWER OPERATIONS
. BUSINESS
CES develops and invests in independent power projects. CES' Colstrip 4
Lease Management Division sells the leased share of Colstrip Unit 4 generation
principally to the Los Angeles Department of Water and Power (LADWP) and to
Puget under contracts with terms coexistent with the lease associated with the
1985 sale-leaseback of our interest in Colstrip Unit 4 (expiring December 29,
2010). In December 1999, an agreement with the LADWP terminated the existing
agreement (11 years remaining) and established a new agreement. We received
approximately $106,000,000 from the LADWP as a result of the termination of the
existing agreement and the establishment of the new agreement and were not
adversely affected by the transaction. The LADWP has assigned all of its rights
and obligations under the new agreement to a third party.
CES, through a wholly owned subsidiary, holds a managing general partner
interest in the 255 MW Encogen One Project located in Sweetwater, Texas. For
more information on CES' projects, see Item 2, "Properties," under the
"Independent Power Properties" section.
In 1998, CES sold its share of the Lockport Project in the state of New
York. CES also participated in the settlement of a power-purchase agreement with
respect to a different project in New York. As a result of this settlement, the
project owners dismantled the plant and CES exited the partnership in 1999.
. COMPETITIVE ENVIRONMENT
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 negotiate pricing. CES works with
its partners and customers to attempt to mitigate effects of contracts that may
reflect pricing higher than current market prices. CES also seeks to target
specific industrial customers for future expansion and establish itself as the
provider of choice for onsite generation projects.
OIL AND NATURAL GAS OPERATIONS
. BUSINESS
We conduct our oil and natural gas operations primarily through our United
States subsidiaries, which include North American Resources Company, MP Gas
Company, and Altana Exploration Co., and our Canadian subsidiaries, which
include Altana Exploration Ltd. and Canadian-Montana Gas Company Limited.
Effective January 1, 2000, we combined all of the assets, liabilities, and
shareholders' equity of Canadian-Montana Gas Company into Altana Exploration
Ltd.
MPT&M principally trades crude oil, natural gas, and natural gas liquids
commodities and derivatives.
. COMPETITIVE ENVIRONMENT
Our nonutility oil and natural gas businesses compete with major oil and
natural gas companies and other independent and individual producers and
operators. For our natural gas operations in the United States, we intend to
emphasize development of midstream, fee-based gas gathering and gas processing
services in a strategic transition away from the natural gas commodity
exploration and production business. We intend to focus our efforts in Canada on
natural gas production and developing markets, primarily in southeast Alberta.
We currently sell natural gas production in both the United States and
Canada under short-term, spot-market, and long-term contracts. Approximately 9.0
Mmcf, or 4 percent of our United States natural gas reserves, are dedicated to a
long-term contract expiring in 2007. Approximately 105,831 Mmcf, or 84 percent
of our Canadian natural gas reserves, are dedicated to long-term contracts
expiring 2003 through 2005.
Additionally, our affiliate, MPT&M, competes for our former natural gas
utility customers who have exercised consumer choice.
ENVIRONMENTAL ISSUES
. GENERAL
Our diversified businesses subject us to numerous federal, state, and
local environmental laws and regulations relating to pollution control and
prevention and environmental remediation, including laws and regulations
regarding clean air and water and the cleanup of contamination related to past
business operations. We accrue an appropriate amount of estimated costs
associated with reasonably foreseeable potential environmental cleanup costs. We
do not expect these costs to materially affect our consolidated financial
position, results of operations, or cash flows.
The Comprehensive Environmental Response, Compensation, and Liability Act
(CERCLA), and some of its state counterparts, may require us to remove or
mitigate adverse environmental effects resulting from the disposal or release of
certain substances at sites that we owned or presently own, or at sites
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where these substances were disposed. We do not know the amount of costs
associated with current site remediation efforts or future remediation because
of uncertainties relating to, among other matters, the following:
. We do not know all sites for which we may be alleged or found to be
responsible.
. We cannot estimate with any degree of reasonable certainty the total
costs for sites that we have identified.
We do not expect the unknown costs to have a materially adverse effect on
our consolidated financial position, results of operations, or cash flows.
. SILVER BOW CREEK/BUTTE AREA SUPERFUND SITE
We are a Potentially Responsible Party (PRP) at the Silver Bow Creek/Butte
Area Superfund Site. A Consent Decree recognizing our "de minimis" contributor
status is pending approval of the United States District Court for the District
of Montana. Upon approval of the Consent Decree, and payment of $100,000, we
would receive a release from further liability for cleanup costs. Further, the
Consent Decree would provide contribution protection in the event other PRPs
claim contribution for cleanup costs they expend. Given the expected approval of
the Consent Decree, the substantial financial capability of other PRPs named by
the Environmental Protection Agency (EPA), and the limited connection between
our property ownership along with the "mining-related" character of the alleged
contamination of this site, we do not believe we are exposed to material
liability regarding this site.
We will, however, continue to address alleged soils contamination of the
30 acres of this site that we own. We do not expect cleanup costs to be
material.
. MILLTOWN DAM SITE
Toxic heavy metals in the silts resting behind the dam caused the EPA to
include Milltown Dam on its list of priority CERCLA sites. The EPA is continuing
its study of this situation, and its Record of Decision that will identify
remedial actions and the party or parties responsible for them is expected in
2001. We believe that we have no responsibility for any remediation of any
alleged releases at the Milltown Dam because of a specific statutory exemption
in the CERCLA legislation.
. THOMPSON FALLS
The Montana Department of Environmental Quality (MDEQ) has listed the
reservoir at the Thompson Falls Dam as a Comprehensive Environmental Cleanup and
Responsibility Act (CECRA) site - Montana's equivalent of a CERCLA National
Priority List site. In 1985 and 1986, researchers found elevated levels of heavy
metals in sediments in the reservoir. The EPA declared the site a "No Further
Action" site pursuant to CERCLA. The MDEQ identified the site as a "Low Priority
Site" because of the low probability of direct human contact and the lack of
evidence of migration to groundwater supplies. Given the low priority
designation for this site, the risk of material remediation is very low. As
discussed in Note 5, "Sale of Electric Generating Assets," we retained
pre-closing environmental liability relating to this CECRA listing when we sold
the dam to PPL Montana.
. SALE OF ELECTRIC GENERATING ASSETS
For further information concerning our environmental liabilities
associated with the generating assets sold to PPL Montana, see Note 5, "Sale of
Electric Generating Assets."
. SITES OF MANUFACTURED GAS PLANTS
We have voluntarily cleaned up two sites where we operated manufactured
gas plants, spending approximately $675,000. We have inspected and assessed a
third site. We are required to periodically monitor groundwater at the first two
sites and report our results to the MDEQ. We have not completed discussions with
the MDEQ and local regulatory agencies regarding the third site. Although we do
not expect that we will be required to remediate the third site, we are likely
to be required to monitor the groundwater at this site for an indefinite period.
We do not expect the costs of monitoring to be material.
. OIL AND NATURAL GAS
Our Canadian subsidiaries are involved with abandonment and remediation of
depleted wells and surface facilities in Alberta, Canada. This work addresses
cleanup under the direction of Alberta Environmental and reflects normal
activity within the oil and gas industry. Approximately 35 sites are under
active reclamation. We have completed cleanup of 70 sites through 1999, of which
31 sites are either awaiting final inspection by Alberta Environmental or are in
the final stages of monitoring vegetation growth, which must occur before we can
apply for cleanup certification. Since 1995, we have spent approximately
$800,000 (United States dollars) for cleanup of the identified sites. We
estimate that we will spend an additional $500,000 (United States dollars) for
cleanup of affected sites through the year 2004. This estimate may change
depending on acquisitions or divestitures of Canadian properties that may occur
over the five-year period.
EMPLOYEES
At December 31, 1999, we had 2,416 employees. Of these, 754 are members of
collective bargaining units involving 11 unions. Current union contracts will
expire at various times during the next three years. The December 17, 1999, sale
of our electric generating assets resulted in the transfer of 474 persons to PPL
Montana, which we have reflected in the above figures.
FOREIGN AND DOMESTIC OPERATIONS
We believe that financial information relating to the segment information
for foreign and domestic operations and export sales, other than the information
previously disclosed regarding our Canadian subsidiaries, is immaterial.
<PAGE>
ITEM 2. PROPERTIES
- ------------------
ELECTRIC UTILITY PROPERTIES
Our electric transmission system extends through the western two-thirds
area of Montana. At December 31, 1999, we owned and operated 6,833 miles of
transmission lines and 16,017 miles of distribution lines.
Our electric resource capacity is provided by two power-purchase
agreements with PPL Montana, 15 Qualifying Facility (QF) contracts that total
101 MWs of firm winter peak capacity, and Milltown Dam (3 MWs gross capacity).
For additional information on our power-purchase agreements, see Note 3,
"Commitments," in the "Purchase Commitments" section.
NATURAL GAS UTILITY PROPERTIES
We serve all of our natural gas customers from our transportation system,
which extends through the western two-thirds area of Montana. At December 31,
1999, we owned and operated 2,120 miles of natural gas transportation lines and
3,598 miles of distribution mains. We also have four natural gas storage fields,
which are an important part of our transportation system. These fields enable us
to store natural gas in excess of system load requirements during the summer for
delivery during winter periods of peak demand, enhancing system reliability.
While our unregulated businesses now operate the natural gas producing
properties, our natural gas utility still produces a small amount of natural gas
from fields in southern Montana and Wyoming to maintain our natural gas storage
leases. See Item 8, "Financial Statements and Supplementary Data - Oil and
Natural Gas Producing Activities," for additional information relating to our
net recoverable utility natural gas reserves.
- --------------------------------------------------------------------------------
Table Total produced, royalty, and purchased natural gas volumes during
the last three years follow, with all volumes in MDkt:
- --------------------------------------------------------------------------------
United States Canada
Produced Royalty Purchased Produced Royalty Purchased
------------------------------------------------------------------
1999 ....... -- -- 17,668 -- -- 1,160
1998 ....... -- -- 10,798 -- -- 9,440
1997 ....... 3,784 294 8,334 3,420 683 7,170
- --------------------------------------------------------------------------------
<PAGE>
TELECOMMUNICATIONS PROPERTIES
Touch America has staffed offices in Minneapolis, Minnesota; Fargo, North
Dakota; Billings, Bozeman, Helena, Butte, Great Falls, Kalispell, and Missoula,
Montana; Boise, Idaho; Spokane and Seattle, Washington; Eugene, Oregon; Casper,
Wyoming; and Denver, Colorado. Touch America owns 25 LMDS licenses in various
marketing areas within nine states in the Pacific Northwest, Rocky Mountain, and
Upper Midwest regions of the United States.
. JOINT VENTURES
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------
Table Primarily through Touch America, we hold interests in joint ventures as listed below:
- ----------------------------------------------------------------------------------------------------------------
Partnership Project Location Partnership Owners Ownership Interest
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
FTV Communications LLC (FTV) -- Touch America 33.3%
Enron Broadband Services 33.3%
Williams Communications 33.3%
Iowa Telecommunications Services, Inc. (ITS) Iowa Touch America 30.7%
Iowa Network Services 69.3%
Northern Colorado Telecommunications LLC Denver, CO Touch America 50.0%
NCE Communications 50.0%
TW Wireless, LLC (TWW) -- Touch America 50.0% (Approx.)
U S West Wireless 50.0% (Approx.)
America Fiber Touch, LLC (AFT) -- Touch America 50.0%
AEP Communications 50.0%
Minnesota PCS, LP Minnesota Touch America 25.0%
Others 75.0%
New Horizon Technology Energy Services, LLC Butte, MT Tetragenics (a) 50.5%
NCAT (NHT) 37.0%
Williams 12.5%
- ----------------------------------------------------------------------------------------------------------------
</TABLE>
(a) Tetragenics is a wholly owned subsidiary of Entech.
<PAGE>
. FIBER-OPTIC NETWORK
Through Touch America, we own or hold interests in the fiber-optic routes
listed below:
OPERATIONAL
- --------------------------------------------------------------------------------
Route
Route Miles
- ----------------------------------------------------------------------------
Within Montana ...................................................... 1,615
Seattle-Minneapolis ................................................. 2,033
Denver-Montana-Canadian Border ...................................... 1,070
Minneapolis-Green Bay-Chicago ....................................... 544
Denver Metropolitan Area ............................................ 230
Denver-Colorado Springs-Dallas ...................................... 1,302
Spokane-Boise ....................................................... 487
Portland-Boise-Salt Lake City-
Las Vegas-Los Angeles ............................................ 1,715
Portland-Seattle .................................................... 200
Portland-Sacramento-Los Angeles (b) ................................. 1,500
------
Total Operational Route Miles .................................... 10,696
======
- --------------------------------------------------------------------------------
(b) The Portland-to-Sacramento section of this route has been delayed
due to permitting issues.
Touch America either holds title to, or has contractual rights in, the
above operational route miles. Those route miles not owned by Touch America are
held principally through Indefeasible Rights-of-Use (IRUs).
UNDER CONSTRUCTION
- --------------------------------------------------------------------------------
Anticipated
Route Operational
Route Miles Date
- --------------------------------------------------------------------------------
Minneapolis-Des Moines-
Topeka-Denver (c) ................................... 1,050 2000
Rexburg-American Falls, ID ............................. 280 2000
Salt Lake City-Denver .................................. 632 2000
Seattle-Yakima-Spokane ................................. 400 2000
Spokane-Billings ....................................... 625 2000
Minneapolis-Madison-Chicago ............................ 500 2000
St. Louis-Plano, IL .................................... 330 2000
Houston-New Orleans-Jacksonville ....................... 1,050 2000
Chicago-Detroit ........................................ 400 2000
Sacramento-Salt Lake City .............................. 770 2001
Denver-Omaha-Des Moines-Chicago ........................ 1,100 2001
Los Angeles-San Diego-Phoenix-
Dallas-Houston ...................................... 2,330 2001
Jacksonville-Orlando-Atlanta ........................... 560 2001
Atlanta-Washington, DC-New York City ................... 1,140 2001
St. Louis-Kansas City .................................. 285 2001
Kansas City-Tulsa ...................................... 265 2001
Tulsa-Dallas ........................................... 330 2001
------
Total Route Miles Under Construction ................ 12,047
======
- --------------------------------------------------------------------------------
(c) This route will become operational in 2000, pending signing of the
contract.
The above tables do not include the 1,800 miles that Touch America expects
to acquire as a result of the agreement with Qwest signed on March 13, 2000.
<PAGE>
COAL PROPERTIES
Western Energy leases and produces coal from Montana properties, and
Northwestern Resources leases and produces lignite from Texas properties.
Western Energy's subsidiary, Western SynCoal LLC (Western SynCoal), owns a
patented coal-enhancement process and a coal-enhancement process demonstration
plant at the Rosebud Mine that Western Energy operates.
Western Energy has coal leases covering approximately 497,686,000 proved,
probable, and recoverable tons of surface-mineable coal reserves at Colstrip.
These tons average less than 1.6 pounds of sulfur dioxide per MMBTU.
Approximately 211,809,000 tons of these reserves are committed to present
contracts, relating principally to the Colstrip Units.
Northwestern Resources has lignite leases in central Texas at the Jewett
Mine covering approximately 144,500,000 proved, probable, and recoverable tons
of surface-mineable lignite reserves. Northwestern Resources has dedicated all
of these reserves to Reliant.
INDEPENDENT POWER PROPERTIES
- --------------------------------------------------------------------------------
Table Through CES, we partially own or have contract rights in nonutility
power generation projects as listed below:
- --------------------------------------------------------------------------------
. PROJECTS IN OPERATION
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------
Location Rated CES Customer
(Commercial Ownership Capacity Share ----------------------------------
Project Operation) 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 (c) United Kingdom 3.2% 1,725 56 Various U.K. customers --
(1993)
Tenaska-Ferndale Ferndale, WA 25.1% 245 61 Puget Sound Energy Tosco Corp.
(1994)
Doctor Bird Old Harbour, Jamaica 17.6% 74 13 Jamaica Public Service None
(1995)
Tenaska-Cleburne Cleburne, TX 13.4% 258 35 Brazos REA City of Cleburne
(1997) ---
Total CES Share of Rated Capacity MW 315
===
- ------------------------------------------------------------------------------------------------------------------
</TABLE>
(a) CES holds a managing partner interest in this project (through its
wholly owned subsidiary, Enserch Development Corporation One, Inc).
(b) This co-generation facility has a long-term contract with North
American Resources Company (Entech's 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.
<PAGE>
<TABLE>
<CAPTION>
. PROJECTS UNDER CONSTRUCTION
- -------------------------------------------------------------------------------------------------------------
Location Rated CES Customer
(Commercial Ownership Capacity Share ----------------------------------
Project Operation) Interest MW MW Electricity Thermal
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Tenaska-Frontier Grimes County, TX 25.0% 830 208 Power Team, a division None
(Grimes County) (2000) of PECO Energy Company
Uch Power Limited Uch, Pakistan 3.2% 586 19 Pakistan Water & None
(2000) --- Power Department
Total Anticipated CES Share of Rated Capacity MW 227
===
- -------------------------------------------------------------------------------------------------------------
</TABLE>
OIL AND NATURAL GAS PROPERTIES
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
Table Listed below is information on our nonutility natural gas and oil wells
as of December 31, 1999, including the owned or leased properties in
which the wells are located.
- --------------------------------------------------------------------------------
United States Canada
------------------------------------------
Leased Owned Leased
------------------------------------------
<S> <C> <C> <C>
Gross productive natural gas wells .. 1,515 164 527
Net productive natural gas wells .... 1,010.08 76.14 55.45
Gross productive oil wells .......... 92 -- 68
Net productive oil wells ............ 86.22 -- 48.73
Gross producing acres ............... 501,361 41,525 262,353
Net producing acres ................. 338,443 35,197 221,354
Gross undeveloped acres ............. 514,109 14,373 333,577
Net undeveloped acres ............... 322,833 12,797 258,592
- --------------------------------------------------------------------------------
</TABLE>
Our producing oil and natural gas properties in the United States are
principally located in Wyoming, Colorado, Oklahoma, and Montana. Our Canadian
properties are principally located in Alberta. One of our subsidiaries has
agreements to supply 81 Bcf of natural gas to four co-generation facilities over
a period of 5 to 11 years, for which there are sufficient proved, developed, and
undeveloped reserves, and controls related sales of production, sufficient to
supply all of the remaining natural gas required by those agreements.
Approximately 9.0 Bcf are dedicated to supply one of these contracts.
The United States wells listed above include multiple completions of 269
gross productive natural gas wells, or 214 net productive natural gas wells.
They also include 3 gross productive oil wells, or 3 net productive oil wells.
The wells located in Canada include multiple completions of one gross productive
natural gas well, or a 0.5 net productive natural gas well.
<PAGE>
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
Table The following table presents information on our nonutility oil and natural gas exploratory and development wells drilled
during the past three years.
- ------------------------------------------------------------------------------------------------------------------------------------
United States Canada
----------------------------------------------------------------------
1999 1998 1997 1999 1998 1997
----------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Net productive natural gas exploratory wells ......... -- 0.96 1.86 -- 3.34 4.30
Net productive oil exploratory wells ................. -- -- 1.00 -- -- --
Net productive natural gas development wells ......... 52.11 53.84 41.50 122.38 73.50 1.30
Net productive oil development wells ................. -- -- 2.87 -- 0.98 15.11
Net dry exploratory wells ............................ 2.31 1.13 0.34 -- 0.50 1.13
Net dry development wells ............................ 10.04 0.45 0.25 7.00 7.00 --
- ------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
For information on properties acquired, see Item 8, "Supplementary Data - Oil
and Natural Gas Producing Activities."
No significant change has occurred and no event has taken place since
December 31, 1999, that would materially affect the estimated quantities of
proved reserves. For information pertaining to the net recoverable oil and
natural gas reserves, see Item 8, "Supplementary Data - Oil and Natural Gas
Producing Activities."
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
Table The following table presents information on produced oil and natural gas average sales prices and production costs in
United States dollars for the past three years.
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31
1999 1998 1997
------------------------------------------------------------------------
United United United
States Canada States Canada States Canada
------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Average sales price:
Per Mcf of natural gas ........................... $ 1.74 $ 1.69 $ 1.45 $ 1.39 $ 1.94 $ 1.38
Per barrel of oil ................................ 16.16 15.40 12.96 11.36 20.42 18.77
Per barrel of natural gas liquids ................ 11.81 10.97 9.10 10.12 10.12 15.64
Average production cost:
Per barrel of oil equivalent ..................... $ 3.79 $ 2.84 $ 3.95 $ 2.95 $ 4.13 $ 3.02
- ------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
NOTE: We converted natural gas production to barrel-of-oil equivalents
based on a ratio of 6 Mcf to 1 barrel of oil.
We sold nonutility oil, natural gas, and natural gas liquids production
pursuant to short-term and long-term contracts at posted prices or pursuant to
forward-market arrangements. From 1997 to 1999, average sales prices changed due
to market fluctuations. Natural gas sales include the sale under a contract with
our utility operations to supply customers who have not chosen other natural gas
suppliers. This contract expires November 1, 2002. Average production costs in
the United States decreased as a result of the prior year inclusion of
non-recurring environmental and compliance work required on the processing
facilities and operating efficiencies in both the United States and Canada.
MORTGAGE AND DEED OF TRUST
A Mortgage and Deed of Trust (Mortgage) subjects all of our physical
properties, except subsidiary company assets and certain specified properties
and assets now owned or hereafter acquired, to a first mortgage lien.
<PAGE>
ITEM 3. LEGAL PROCEEDINGS
- -------------------------
PALADIN ASSOCIATES, INC.
We and North American Resources Company (NARCO), Entech's subsidiary, are
defendants in litigation initiated in October 1995 by Paladin Associates, Inc.
in the United States District Court for the District of Montana. Paladin, a
natural gas broker that transported natural gas on our pipeline system, alleges
that Northridge Petroleum Marketing, a Canadian corporation, NARCO and Montana
Power violated antitrust law, breached contractual obligations, and committed
torts for which Paladin is entitled to collect monetary damages. Paladin is
seeking actual damages that it estimates to be approximately $10,000,000, which,
if trebled, would amount to $30,000,000. In addition, it seeks unspecified
punitive damages regarding its tort claims.
We and NARCO deny Paladin's allegations. Because the alleged wrongful and
illegal antitrust actions were subject to state and federal regulation, we and
NARCO are asserting a state action defense. Summary judgment motions and motions
to limit issues at the trial are pending the court's determination. The
previously scheduled January 2000 trial of this matter has been postponed and
has not been rescheduled.
TCA BUILDING COMPANY
Entech and Northwestern Resources, its subsidiary, are defendants in
litigation initiated by TCA Building Company in 1995 in the 261st Judicial
District Court in Travis County, Texas. TCA alleged that Entech and Northwestern
Resources breached obligations to assist it in mining its property, that alleged
promises underlying these obligations were tainted by fraud, and that our
subsidiaries wrongfully interfered with a contract and a business opportunity
for TCA to sell lignite. TCA alleges that its damages, in addition to
unspecified exemplary damages, are between $8,000,000 and $13,500,000. Entech
and Northwestern Resources have asserted counterclaims that would substantially
reduce these alleged amounts.
The Texas district court granted motions filed by Entech and Northwestern
Resources for summary judgment on all of TCA's claims. We cannot predict whether
TCA will appeal or the ultimate resolution of TCA's claims.
For additional information on legal proceedings, see the "Environmental
Issues" section of Item 1, "Business," and Note 2, "Contingencies."
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
- -----------------------------------------------------------
None.
PART II
- -------
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
- -------------------------------------------------------------------------
MATTERS
-------
COMMON STOCK INFORMATION
Our common stock is listed on the New York Stock Exchange and the Pacific
Exchange, Inc. The following table presents the high and low sale prices of our
common stock, as well as dividends declared, for the years 1999 and 1998. The
number of common shareholders of record on December 31, 1999, was 31,976, and
the number of common shareholders of record on March 3, 2000, was 31,778. As
discussed in Part I, the Board of Directors approved a two-for-one stock split
of our outstanding common stock, effective August 6, 1999, for all shareholders
of record on July 16, 1999, and we have adjusted all share and per-share
information to reflect the split.
- --------------------------------------------------------------------------------
Table Common stock information:
- --------------------------------------------------------------------------------
Dividends
Declared
Per
1999 High Low Share
--------------------------------------------------------------------
1st quarter $ 41.000 $ 24.563 $ 0.20
2nd quarter 42.625 31.563 0.20
3rd quarter 36.313 27.500 0.20
4th quarter 37.375 26.813 0.20
- --------------------------------------------------------------------------------
Dividends
Declared
Per
1998 High Low Share
--------------------------------------------------------------------
1st quarter $ 18.407 $ 14.532 $ 0.20
2nd quarter 19.250 16.907 0.20
3rd quarter 22.625 16.625 0.20
4th quarter 28.563 20.563 0.20
- --------------------------------------------------------------------------------
<PAGE>
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------------
Table Balance Sheet Items
- ----------------------------------------------------------------------------------------------------------------------
1999 1998 1997 1996 1995
------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Assets:
Utility plant ......................... $ 1,466,727 $ 2,246,847 $ 2,216,198 $ 2,236,309 $ 2,156,959
Less accumulated depreciation
and depletion ..................... 464,653 732,385 684,960 705,119 663,216
------------------------------------------------------------------------
Net utility plant ............ 1,002,074 1,514,462 1,531,238 1,531,190 1,493,743
------------------------------------------------------------------------
Nonutility property ................... 1,051,997 864,981 781,406 666,679 633,079
Less accumulated depreciation
and depletion ..................... 349,045 297,933 260,567 256,489 252,612
------------------------------------------------------------------------
Net nonutility property ...... 702,952 567,048 520,839 410,190 380,467
------------------------------------------------------------------------
Total net plant and property . 1,705,026 2,081,510 2,052,077 1,941,380 1,874,210
Other assets .......................... 1,343,717 846,585 753,819 756,835 711,881
------------------------------------------------------------------------
Total Assets ...................... $ 3,048,743 $ 2,928,095 $ 2,805,896 $ 2,698,215 $ 2,586,091
========================================================================
Liabilities and Shareholders' Equity:
Common shareholders' equity ........... $ 1,029,217 $ 1,112,103 $ 1,037,534 $ 999,657 $ 976,043
Unallocated stock held by trustee
for retirement savings plan ....... (20,401) (23,298) (25,945) (28,360) (30,565)
Preferred stock ....................... 57,654 57,654 57,654 57,654 101,416
Company obligated mandatorily
redeemable preferred securities
of subsidiary trust ............... 65,000 65,000 65,000 65,000 --
Long-term debt ........................ 618,512 698,329 653,168 633,339 616,574
Other liabilities ..................... 1,298,761 1,018,307 1,018,485 970,925 922,623
------------------------------------------------------------------------
Total Liabilities and Shareholders'
Equity ....................... $ 3,048,743 $ 2,928,095 $ 2,805,896 $ 2,698,215 $ 2,586,091
========================================================================
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------------
Table Income Statement Items
- --------------------------------------------------------------------------------------------------------------------------
1999 1998 1997 1996 1995
------------------------------------------------------------------------
(Thousands of Dollars except per-share amounts)
<S> <C> <C> <C> <C> <C>
Income Statement Items:
Revenues .................................. $ 1,342,309 $ 1,267,271 $ 1,023,597 $ 973,208 $ 953,224
Expenses:
Operations ............................ 668,521 541,743 420,032 386,775 426,425
Maintenance ........................... 81,553 81,064 82,702 75,409 74,593
Selling, general, and administrative .. 138,248 128,741 116,054 104,535 95,212
Taxes other than income taxes ......... 103,881 96,181 92,967 84,400 86,599
Depreciation, depletion, and
amortization ..................... 111,145 114,267 95,340 86,403 84,635
Write-downs of long-lived assets ...... 7,083 -- -- -- 74,297
------------------------------------------------------------------------
1,110,431 961,996 807,095 737,522 841,761
------------------------------------------------------------------------
Income from operations ........... 231,878 305,275 216,502 235,686 111,463
Interest expense and other income:
Interest .............................. 43,006 60,851 54,667 48,770 43,656
Distributions on company obligated
mandatorily redeemable preferred
securities of subsidiary trust ... 5,492 5,492 5,492 -- --
Other income - net .................... (11,029) (4,862) (34,159) (4,445) (10,704)
------------------------------------------------------------------------
37,469 61,481 26,000 44,325 32,952
Income taxes .............................. 44,063 78,174 61,870 71,975 21,574
------------------------------------------------------------------------
Net income ................................ 150,346 165,620 128,632 119,386 56,937
Dividends on preferred stock .............. 3,690 3,690 3,690 8,358 7,227
------------------------------------------------------------------------
Net income available for common stock ..... $ 146,656 $ 161,930 $ 124,942 $ 111,028 $ 49,710
========================================================================
Basic earnings per share of common stock:
Utility operations .................... $ 0.56 $ 0.47 $ 0.54 $ 0.56 $ 0.61
Nonutility operations ................. 0.78 1.00 0.60 0.45 (0.15)
------------------------------------------------------------------------
$ 1.34 $ 1.47 $ 1.14 $ 1.01 $ 0.46
========================================================================
Diluted earnings per share of
common stock .......................... $ 1.33 $ 1.47 $ 1.14 $ 1.01 $ 0.46
========================================================================
Dividends declared per share of
common stock .......................... $ 0.80 $ 0.80 $ 0.80 $ 0.80 $ 0.80
Average shares outstanding-Basic (000) .... 109,795 109,962 109,298 109,268 108,242
Earnings coverage of fixed charges,
SEC Method ............................ 3.25x 3.34x 2.94x 3.21x 1.96x
</TABLE>
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
- -------------------------------------------------------------------------------
OF OPERATIONS
- -------------
RESULTS OF OPERATIONS
Consolidated net income available for common stock was $146,656,000 in
1999, compared with $161,930,000 in 1998 and $124,942,000 in 1997.
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------
Table The following table shows the sources of consolidated net income on a per-share (basic) basis
for 1999, 1998, and 1997 and each source's percentage contribution to consolidated earnings
per share.
Year Ended December 31
- ------------------------------------------------------------------------------------------------------
Percent Percent Percent
1999 Contribution 1998 Contribution 1997 Contribution
---------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Utility operations...... $ 0.56 42% $ 0.47 32% $ 0.54 47%
Nonutility operations... 0.78 58% 1.00 68% 0.60 53%
---------------------------------------------------------------------------
Consolidated............ $ 1.34 100% $ 1.47 100% $ 1.14 100%
===========================================================================
- ------------------------------------------------------------------------------------------------------
</TABLE>
1999 Compared With 1998
- -----------------------
UTILITY
The utility's net income increased primarily because we recognized as
income approximately $18,300,000 in unamortized investment tax credits (ITCs) in
the fourth quarter 1999.
. Approximately $10,000,000 of these previously deferred ITCs were
associated with the sale of our electric generating assets.
. Approximately $8,300,000 of these previously deferred ITCs were
recognized as income in accordance with provisions of the Electric
Act, which authorizes accelerated amortizations if the electric
utility's return on equity drops below 9.5 percent.
As a result of the sale, we also reversed accrued interest expense related
to the Kerr Project. The after-tax effect of this adjustment to interest expense
positively affected the utility's 1999 earnings by approximately $3,000,000.
The electric utility's operating income decreased compared with 1998 for
the following reasons:
. Revenues increased primarily due to increased volumes of surplus
power sold in the secondary markets at higher prices, coupled with
revenues earned from transmitting energy for customers who chose
other suppliers.
. Higher expenses - especially selling, general, and administrative
(SG&A) expenses and electric transmission and distribution expenses
- more than offset the increased revenues. Approximately $5,800,000
of the increase in SG&A expenses was attributable to costs
associated with implementing new information systems.
The natural gas utility's operating income increased compared with 1998
mainly because of customer growth and a 1998 decrease in revenues to reflect a
rate refund under a PSC ruling.
NONUTILITY
The nonutility's net income for 1999 decreased, compared with 1998,
primarily because of the effects of one-time favorable events involving our
independent power business, Continental Energy Services, Inc. (CES), during
1998. The nonutility businesses had operating results for 1999 as follows:
. Income from telecommunications operations decreased compared with
1998. On January 16, 1999, a customer of Touch America exercised its
option to prepay, with a discount, all amounts due for the remaining
twelve-year initial term of a capacity agreement. As a result, Touch
America received $257,000,000 and Touch America's income from
operations for 1999 was approximately $23,200,000 lower than it
would have been without the discounted prepayment. Increased
private-line and long-distance revenues reduced the operating-income
effects of the prepayment.
. Income from coal operations increased due to higher revenues
resulting from increased tons sold and the effects in the third
quarter 1998 of a one-time refund issued by Western Energy to
Colstrip Units 3 and 4 customers, which decreased 1998 revenues.
. Income from independent power operations decreased because of the
following events, which had materially positive effects on CES' 1998
income: (1) a contract settlement between the Bonneville Power
Administration and an independent power partnership in which CES was
a partner; (2) the sale of CES' interest in the Lockport project in
New York; and (3) the effects of the buyout of CES' interest in the
Encogen Four project in New York.
<PAGE>
. Increased income from oil and natural gas operations resulted from
higher oil and natural gas prices and increased natural gas volumes
sold, which more than offset decreases in oil volumes sold and
write-downs of natural gas properties.
1998 Compared With 1997
- -----------------------
Consolidated earnings for the year ended December 31, 1998, were $1.47 per
share, an increase of $0.33 per share, or approximately 29 percent, over 1997
earnings of $1.14 per share.
Our 1998 financial performance reflects nonutility business successes,
which significantly offset the effects of utility deregulation and weak oil and
gas prices. Our telecommunications and independent power businesses provided
significant increases in annual earnings. Our utility operations suffered not
only from the effects of deregulation, but also from weather - which was 6
percent warmer than normal.
Approximately $0.39 per share of the increased earnings resulted from the
following events in our independent power business: (1) an arbitration award
against the Bonneville Power Administration for breach of a power purchase
agreement, resulting in a gain to CES of approximately $42,200,000; (2) a gain
of approximately $14,200,000 on the sale of CES' interest in the Lockport, New
York project; and (3) a gain of approximately $14,200,000 (including partial
sale of plant) as a result of a third-quarter settlement with a power purchaser
and the owners of a project, including CES.
Increased rates and increased secondary sales resulted in an increase of
approximately $17,600,000 in electric revenues. Natural gas general business
revenues decreased by approximately $14,400,000 mainly because of customer
choice and warmer weather. Although lower maintenance expenses reduced
power-supply costs, our utility also was affected by charges associated with
curtailment of a benefit plan and higher depreciation associated with property
that we had held for future construction of a generating plant.
Touch America recorded approximately $10,900,000 in earnings from
unconsolidated investments as a result of its share of dark-fiber sales through
its interest in the FTV joint venture. Revenues from telecommunications
operations increased approximately $51,000,000. The increase was primarily
attributable to the effects of (1) a full year's operation of Touch America's
expanded fiber-optic network linking Seattle to Minneapolis-St. Paul and Denver
to Canada, resulting in dark-fiber sales, and (2) increased long-distance
revenues.
Oil and natural gas earnings declined when compared with 1997. Production
constraints and comparatively low prices caused the decline.
- --------------------------------------------------------------------------------
Table Utility Operations
Year Ended December 31
- --------------------------------------------------------------------------------
1999 1998 1997
------------------------------------
(Thousands of Dollars)
ELECTRIC UTILITY:
- -----------------
REVENUES:
Revenues ........................... $ 456,933 $ 450,719 $ 435,986
Intersegment revenues .............. 13,616 7,576 4,685
------------------------------------
470,549 458,295 440,671
EXPENSES:
Power supply ....................... 138,705 137,415 143,224
Transmission and distribution ...... 49,355 40,182 38,359
Selling, general, and administrative 67,392 53,017 50,872
Taxes other than income taxes ...... 50,857 46,316 45,540
Depreciation and amortization ...... 53,574 56,524 51,674
------------------------------------
359,883 333,454 329,669
------------------------------------
INCOME FROM ELECTRIC OPERATIONS .... 110,666 124,841 111,002
NATURAL GAS UTILITY:
- --------------------
REVENUES:
Revenues (other than gas supply
cost revenues) ................. 78,359 75,112 105,220
Gas supply cost revenues ........... 32,759 31,940 17,135
Intersegment revenues .............. 629 727 588
------------------------------------
111,747 107,779 122,943
EXPENSES:
Gas supply costs ................... 32,759 31,940 17,135
Other production, gathering,
and exploration ................ 2,338 2,284 8,572
Transmission and distribution ...... 14,635 15,556 14,163
Selling, general, and administrative 21,944 20,191 17,889
Taxes other than income taxes ...... 14,333 14,084 15,251
Depreciation, depletion,
and amortization ............... 9,279 8,705 11,939
------------------------------------
95,288 92,760 84,949
------------------------------------
INCOME FROM GAS OPERATIONS ......... 16,459 15,019 37,994
INTEREST EXPENSE AND OTHER INCOME:
- ----------------------------------
Interest ........................... 48,204 56,357 52,191
Distributions on company obligated
mandatorily redeemable preferred
securities of subsidiary trust . 5,492 5,492 5,492
Other income - net ................. (3,565) (3,723) (7,128)
------------------------------------
50,131 58,126 50,555
INCOME TAXES ............................ 11,940 26,559 35,643
------------------------------------
NET INCOME .............................. 65,054 55,175 62,798
DIVIDENDS ON PREFERRED STOCK ............ 3,690 3,690 3,690
------------------------------------
UTILITY NET INCOME AVAILABLE
FOR COMMON STOCK ................... $ 61,364 $ 51,485 $ 59,108
====================================
UTILITY OPERATIONS
Weather affects the demand for electricity and natural gas, especially
among residential and commercial customers. Very cold winters increase demand,
while mild winters reduce demand. The weather's effect is measured using
degree-days, which 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,
<PAGE>
the 1999 temperatures for our service territory were 3 percent warmer than 1998
and 9 percent warmer than the historic average. Temperatures in 1998 were 6
percent warmer than 1997 and the historic average.
Weather, streamflow conditions, and the wholesale power markets in the
Northwest and California influenced our electric wholesale revenues,
purchased-power expenses, and output of thermal generation. Regional
purchased-power prices were higher in 1999 than 1998 and, consequently, we did
not displace thermal generation as in prior years.
Utility earnings are based on capital invested in utility plant. We expect
our electric utility income to decrease as a result of the sale of our
generating assets.
. ACCOUNTING FOR THE EFFECTS OF REGULATION
For our regulated operations, we follow Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation." Pursuant to this pronouncement, we recognize certain expenses and
credits as they are reflected in revenues collected through rates established by
cost-based regulation. Changes in regulation or changes in the competitive
environment could result in our not meeting the criteria of SFAS No. 71. If we
were to discontinue application of SFAS No. 71 for some or all of our regulated
operations, we would have to eliminate the related regulatory assets and
liabilities from the balance sheet and include the associated expenses and
credits in income in the period when the discontinuation occurred, unless
recovery of those costs was provided through rates charged to those customers in
portions of the business that were to remain regulated.
With the sale of our generating assets, we received proceeds in excess of
the book value of the regulated assets. Until the PSC reaches a decision in our
Tier II filing, we are carrying these excess proceeds as a liability on the
Consolidated Balance Sheet and have not recorded a gain on the sale.
For additional information on our Tier II filing, see Note 4,
"Deregulation and Regulatory Matters." The Electric Act identifies regulatory
assets and deferred charges that exist because of regulatory practices, as well
as above-market costs associated with QF contracts, as recoverable transition
costs. Based upon this anticipated recovery of these costs, we believe that
discontinuing regulatory-accounting treatment would not have a material adverse
effect on our future consolidated financial position, results of operations, or
cash flows. We expect our regulated transmission and distribution businesses
will continue to have cost-based rates and, therefore, meet the criteria of SFAS
No. 71.
<PAGE>
. ELECTRIC UTILITY
1999 Compared With 1998
- -----------------------
- --------------------------------------------------------------------------------
Table The following table categorizes revenues and volumes into General
Business Revenues, Sales to Other Utilities, Other, and Intersegment.
It also shows Bundled Revenues and Distribution Only Revenues
separately for General Business Revenues. While we no longer supply the
electricity for customers who have chosen other commodity suppliers, we
continue to earn transmission and distribution revenues for moving
their electricity across our transmission and distribution lines. We
reflect transmission revenues as Other Revenues and distribution
revenues as Distribution Only Revenues. We expect these revenues to
continue to increase as additional customers move to choice. For
customers who have not chosen other suppliers, Bundled Revenues reflect
fully bundled rates for supplying, transmitting, and distributing
electricity. We expect these revenues to continue to decrease as
additional customers move to choice.
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------
Revenues and
Power Supply Expenses Volumes
-----------------------------------------------------------
(Thousands of Dollars) (Thousands of MWh)
1999 1998 1999 1998
-----------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
REVENUES:
General Business Bundled Revenues:
Residential ....................... $127,591 $125,523 2% 1,810 1,927 (6%)
Small Commercial, Small Industrial,
and Government and Municipal .... 160,107 164,178 (2%) 2,484 2,793 (11%)
Large Commercial, Large Industrial 36,294 82,667 (56%) 1,124 2,158 (48%)
Irrigation and Street Lighting .... 15,249 14,683 4% 144 139 4%
-----------------------------------------------------------
Total ........................... 339,241 387,051 (12%) 5,562 7,017 (21%)
General Business Distribution Only
Revenues:
Small Commercial, Small Industrial,
and Government and Municipal .... 2,837 179 1485% 128 9 1322%
Large Commercial, Large Industrial 13,437 2,034 561% 1,519 252 503%
-----------------------------------------------------------
Total ........................... 16,274 2,213 635% 1,647 261 531%
Total General Business
Revenues .................... 355,515 389,264 (9%) 7,209 7,278 (1%)
Sales to Other Utilities ............. 78,975 48,111 64% 3,375 1,906 77%
Other ................................ 22,443 13,344 68% -- -- --
Intersegment ......................... 13,616 7,576 80% 66 125 (47%)
-----------------------------------------------------------
Total ............................. $470,549 $458,295 3% 10,650 9,309 14%
===========================================================
POWER SUPPLY EXPENSES:
Hydroelectric ........................ 21,576 22,266 (3%) 3,692 3,742 (1%)
Steam ................................ 54,969 50,952 8% 4,685 4,516 4%
Purchased Power and Other ............ 62,160 64,197 (3%) 2,992 2,058 45%
-----------------------------------------------------------
Total ............................. $138,705 $137,415 1% 11,369 10,316 10%
===========================================================
Dollars per MWh ...................... $ 12.20 $ 13.32
===================
</TABLE>
- --------------------------------------------------------------------------------
General Business Revenues
Revenues from electric utility operations increased in 1999, while General
Business Revenues decreased primarily because of a decrease in revenues from the
Large Industrial Customer classification as these customers continued to choose
other commodity suppliers. An increase in prices to recover the cost of
public-purpose programs in accordance with the Electric Act lessened the effects
of decreased revenues from Large Industrial Customers.
Sales to Other Utilities
Revenues from Sales to Other Utilities increased because of increased
volumes sold in the secondary markets at higher average prices. We had more
energy available to sell in the secondary markets because of increased plant
availability as a result of less downtime for repairs and maintenance and lower
consumption attributable to customers continuing to choose other suppliers. With
the sale of substantially all of our generating assets, we no longer sell energy
in the secondary markets.
<PAGE>
Other
Other revenues increased mainly because of revenues earned for
transmitting energy for customers who chose other suppliers. Prior to the
Electric Act, we classified transmission revenues as General Business Revenues.
We now reflect transmission revenues from customers who chose other suppliers as
Other revenues, while we still report transmission revenues from customers who
have not chosen other suppliers as General Business Revenues.
Intersegment
Intersegment revenues increased because of the revenues associated with
MPT&M using our lines to transmit energy that it sold in the secondary markets.
While we reflect sales in the secondary markets as Sales to Other Utilities, as
of July 1, 1998, we began reflecting revenues earned from the transmission of
the energy sold to other utilities in the Intersegment line of the segmented
schedule of revenues and expenses. The corresponding transmission volumes are
the same volumes associated with the sale of energy in the secondary markets.
Therefore, we report these volumes in the Sales to Other Utilities line in the
table above.
Expenses
Power-supply expenses increased primarily due to increased plant
availability. Transmission and distribution expenses increased because of costs
associated with using others' lines outside our service territory to transmit
the energy sold in the secondary markets. Property taxes increased because of
additional plant and higher assessed property values. Depreciation and
amortization expense decreased because of expenses incurred in 1998 associated
with software costs and property held for future use.
SG&A expenses increased approximately $14,400,000 mainly because of the
following items:
. An increase of approximately $7,900,000 for energy efficiency and
public-purpose programs to comply with the Universal System Benefits
Charge (USBC) requirements of the Electric Act. In accordance with
the Electric Act, we collect these costs through a separate
component of rates.
. Costs of approximately $2,000,000 incurred to train staff and to
reengineer business processes to implement a new Enterprise Resource
Planning (ERP) information system and similar costs of approximately
$3,800,000 for a new Enterprise Customer Care (E-CIS) information
system.
. Increases in other administrative costs of approximately $2,700,000,
which were mostly offset by decreased benefit expenses of
approximately $2,000,000 relating to the curtailment of a benefit
plan in the prior year.
<PAGE>
. ELECTRIC UTILITY
1998 Compared With 1997
- -----------------------
- --------------------------------------------------------------------------------
Table The following table categorizes revenues and volumes into General
Business Revenues, Sales to Other Utilities, Other, and Intersegment.
It also shows Bundled Revenues and Distribution Only Revenues
separately for General Business Revenues.
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Revenues and
Power Supply Expenses Volumes
---------------------------------------------------------
(Thousands of Dollars) (Thousands of MWh)
1998 1997 1998 1997
---------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
REVENUES:
General Business Bundled Revenues:
Residential ....................... $125,523 $122,446 3% 1,927 1,920 --
Small Commercial, Small Industrial,
and Government and Municipal .... 164,178 156,428 5% 2,793 2,699 3%
Large Commercial, Large Industrial 82,667 85,602 (3%) 2,158 2,196 (2%)
Irrigation and Street Lighting .... 14,683 13,271 11% 139 118 18%
---------------------------------------------------------
Total ........................... 387,051 377,747 2% 7,017 6,933 1%
General Business Distribution Only
Revenues:
Small Commercial, Small Industrial,
and Government and Municipal .... 179 -- -- 9 -- --
Large Commercial, Large Industrial 2,034 -- -- 252 -- --
---------------------------------------------------------
Total ........................... 2,213 -- -- 261 -- --
Total General Business
Revenues .................... 389,264 377,747 3% 7,278 6,933 5%
Sales to Other Utilities ............. 48,111 47,178 2% 1,906 2,663 (28%)
Other ................................ 13,344 11,061 21% -- -- --
Intersegment ......................... 7,576 4,685 62% 125 149 (16%)
---------------------------------------------------------
Total ............................. $458,295 $440,671 4% 9,309 9,745 (4%)
=========================================================
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%
Purchased Power and Other ............ 64,197 63,280 1% 2,058 2,538 (19%)
---------------------------------------------------------
Total ............................. $137,415 $143,224 (4%) 10,316 10,954 (6%)
=========================================================
Dollars per MWh ...................... $ 13.32 $ 13.08
===================
</TABLE>
- --------------------------------------------------------------------------------
Revenues
Revenues increased during the period primarily due to higher rates. While
volumes sold decreased due to the transfer of electric-trading activities to
nonutility operations in the third quarter of 1998, revenues from Sales to Other
Utilities increased from higher average prices and steam generation, resulting
in more energy available to sell in the secondary market. Other revenues
increased as a result of an actuarial pension plan adjustment, along with
transmission revenues from customers who chose other suppliers.
Expenses
Power-supply expenses decreased primarily due to lower steam maintenance,
which was partially offset by increased purchased-power costs. Although we
purchased less power through electric-trading activities as a result of the
transfer of these activities to nonutility operations, purchased-power costs
increased due to higher prices.
Increased SG&A expenses resulted primarily from increased outsourcing
costs and higher benefit charges associated with curtailment of a benefit plan.
The absence of severance costs in the current year partially offset this
increase. Depreciation and amortization expense increased because of expenses
associated with software costs and property held for future use.
<PAGE>
. NATURAL GAS UTILITY
1999 Compared With 1998
- -----------------------
- --------------------------------------------------------------------------------
Table The following table categorizes revenues and volumes into General
Business Revenues, Sales to Other Utilities, Transportation, and Other.
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Revenues Volumes*
(Thousands of Dollars) (Thousands of Dkt)
-----------------------------------------------------------
1999 1998 1999 1998
-----------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
REVENUES:
Residential ....................... $ 63,921 $ 61,666 4% 12,657 11,505 10%
Small Commercial, Small Industrial,
and Government and Municipal .. 30,329 31,842 (5%) 5,874 6,006 (2%)
-----------------------------------------------------------
General Business Revenues ......... 94,250 93,508 1% 18,531 17,511 6%
Less: Gas Supply Cost
Revenues (GSC) ................. 32,759 31,940 3% -- -- --
-----------------------------------------------------------
General Business
Revenues without GSC ......... 61,491 61,568 -- 18,531 17,511 6%
Sales to Other Utilities .......... 687 606 13% 229 200 15%
Transportation .................... 15,197 14,844 2% 24,426 27,320 (11%)
Other ............................. 984 (1,906) (152%) -- -- --
-----------------------------------------------------------
Total .......................... $ 78,359 $ 75,112 4% 43,186 45,031 (4%)
===========================================================
</TABLE>
* With the implementation of our E-CIS, we now report natural gas
revenues in dekatherms (Dkt). A Dkt measures the heat used and is
the basis of how we bill our customers.
- --------------------------------------------------------------------------------
Revenues
All of our former Large Industrial and Large Commercial customers have now
chosen other commodity suppliers. While we no longer supply the natural gas for
those customers, we still earn transportation revenues from moving their natural
gas through our pipelines. We reflect these revenues as Transportation revenues
in the table.
General Business Revenues remained relatively flat. Increased revenues
from customer growth and increased rates to recover higher gas-supply costs were
offset by a decrease in revenues from industrial customers continuing to choose
other commodity suppliers. For additional information on deregulation, see Note
4, "Deregulation and Regulatory Matters." Other revenues increased because of a
1998 decrease in revenues to reflect a rate refund in compliance with a PSC
ruling.
Expenses
SG&A expenses increased chiefly because of expensed costs for implementing
the ERP system and the E-CIS system. An increase relating to energy efficiency
and public-purpose programs mostly offset a decrease in other administrative
costs.
<PAGE>
1998 Compared With 1997
- -----------------------
- --------------------------------------------------------------------------------
Table The following table categorizes revenues and volumes into General
Business Revenues, Sales to Other Utilities, Transportation, and Other.
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Revenues Volumes
(Thousands of Dollars) (Thousands of Dkt)
-----------------------------------------------------------
1998 1997 1998 1997
-----------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
REVENUES:
Residential ....................... $ 61,666 $ 66,292 (7%) 11,505 12,493 (8%)
Small Commercial, Small Industrial,
and Government and Municipal ... 31,842 41,613 (23%) 6,006 8,188 (27%)
-----------------------------------------------------------
General Business Revenues ......... 93,508 107,905 (13%) 17,511 20,681 (15%)
Less: Gas Supply Cost
Revenues (GSC) ................. 31,940 17,135 86% -- -- --
-----------------------------------------------------------
General Business
Revenues without GSC ......... 61,568 90,770 (32%) 17,511 20,681 (15%)
Sales to Other Utilities .......... 606 786 (23%) 200 237 (16%)
Transportation .................... 14,844 9,919 50% 27,320 26,160 4%
Other ............................. (1,906) 3,745 (151%) -- -- --
-----------------------------------------------------------
Total .......................... $ 75,112 $105,220 (29%) 45,031 47,078 (4%)
===========================================================
</TABLE>
- --------------------------------------------------------------------------------
Revenues
Natural gas revenues, excluding gas-supply cost revenues, decreased in
1998 primarily due to weather-related reductions in volumes sold. Slightly
higher tariff rates and customer growth partially offset the revenue decrease. A
decrease in Other revenues, due to the November 1997 restructuring of our
natural gas utility and an increase in gas-supply cost refunds to our customers,
was partially offset by an increase in Transportation revenues. For additional
information on deregulation, see Note 4, "Deregulation and Regulatory Matters."
Expenses
In November 1997, we transferred substantially all of our regulated
natural gas production assets to an unregulated affiliate. Since that time, we
have included operating expenses related to the transferred assets in the
nonutility oil and natural gas operations. The absence of these expenses in the
utility operations resulted in net reductions in other production, gathering,
and exploration costs.
As a result of the restructuring, we have contracted to purchase most of
our natural gas from our 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 expenses for the period resulted primarily from increased
amortizations of regulatory assets, which are collected in rates, as well as
higher outsourcing charges.
Depreciation, depletion, and amortization expense decreased due to the
transfer of the natural gas production properties as discussed above.
. INTEREST EXPENSE AND INCOME TAXES
1999 Compared With 1998
- -----------------------
Interest Expense
With the sale of our generating assets, we will no longer be responsible
for mitigating costs associated with Kerr Project operations after the date of
the sale. We had previously recorded the present value of mitigation
expenditures over the life of the license. From the date of the initial entry
through the date of the sale, interest expense had been recorded to adjust the
mitigation liability to current dollars. With the sale, our obligation to make
payments for future periods ended. The mitigation liability has now been
adjusted, and accrued interest expense was reversed. This adjustment to interest
expense accounts for the majority of the decrease in interest expense of
approximately $8,200,000. For additional information on the Kerr Project, see
Note 2, "Contingencies."
Income Taxes
In accordance with the Electric Act, we are allowed to recognize as income
accelerated amortizations of ITCs during the transition period if our return on
equity drops below 9.5 percent. As a result, we recognized approximately
$8,300,000 of ITCs associated with our electric utility's business.
<PAGE>
In addition, we recognized as income approximately $10,000,000 in
unamortized ITCs associated with the sale of our electric generating assets to
PPL Montana.
1998 Compared With 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 associated with a federal income tax settlement. Partially offsetting
this increase was a decrease in short-term borrowing and the absence of interest
paid in 1997 in conjunction with a contract settlement.
- --------------------------------------------------------------------------------
Table Nonutility Operations
Year Ended December 31
- --------------------------------------------------------------------------------
1999 1998 1997
------------------------------------
(Thousands of Dollars)
TELECOMMUNICATIONS:
REVENUES:
Revenues ........................... $ 84,350 $ 87,748 $ 46,691
Earnings from unconsolidated
investments .................... 10,392 10,909 435
Intersegment revenues .............. 1,012 1,298 799
------------------------------------
95,754 99,955 47,925
EXPENSES:
Operations and maintenance ......... 34,824 27,110 22,385
Selling, general, and administrative 12,480 12,172 8,825
Taxes other than income taxes ...... 3,762 3,623 2,294
Depreciation and amortization ...... 9,048 7,090 2,494
------------------------------------
60,114 49,995 35,998
------------------------------------
INCOME FROM TELECOMMUNICATIONS
OPERATIONS ..................... 35,640 49,960 11,927
COAL:
REVENUES:
Revenues ........................... 197,053 177,961 167,623
Intersegment revenues .............. 39,729 38,796 34,164
------------------------------------
236,782 216,757 201,787
EXPENSES:
Operations and maintenance ......... 150,801 132,963 119,085
Selling, general, and administrative 16,174 20,588 21,355
Taxes other than income taxes ...... 25,759 24,050 23,455
Depreciation and amortization ...... 7,446 6,596 9,043
------------------------------------
200,180 184,197 172,938
------------------------------------
INCOME FROM COAL OPERATIONS ........ 36,602 32,560 28,849
INDEPENDENT POWER:
REVENUES:
Revenues ........................... 75,101 73,707 70,932
Earnings from unconsolidated
investments .................... 21,042 89,525 14,980
Intersegment sales ................. 1,764 2,014 1,820
------------------------------------
97,907 165,246 87,732
EXPENSES:
Operations and maintenance ......... 65,343 65,009 63,837
Selling, general, and administrative 4,160 4,746 4,290
Taxes other than income taxes ...... 1,840 1,767 1,868
Depreciation and amortization ...... 3,122 9,005 2,774
------------------------------------
74,465 80,527 72,769
------------------------------------
INCOME FROM INDEPENDENT
POWER OPERATIONS ............... $ 23,442 $ 84,719 $ 14,963
OIL AND NATURAL GAS:
REVENUES:
Revenues ........................... $ 338,869 $ 221,662 $ 163,656
Intersegment revenues .............. 16,663 17,606 3,120
------------------------------------
355,532 239,268 166,776
EXPENSES:
Operations and maintenance ......... 284,517 183,536 118,266
Selling, general, and administrative 18,091 20,925 10,723
Taxes other than income taxes ...... 6,049 4,908 4,555
Depreciation, depletion,
and amortization ............... 23,832 22,259 16,922
Write-downs of long-lived assets ... 7,083 -- --
------------------------------------
339,572 231,628 150,466
INCOME FROM OIL AND
NATURAL GAS OPERATIONS ......... 15,960 7,640 16,310
OTHER OPERATIONS:
REVENUES:
Revenues ........................... 47,451 47,988 939
Intersegment revenues .............. 1,874 1,913 5,719
------------------------------------
49,325 49,901 6,658
EXPENSES:
Operations and maintenance ......... 50,140 51,634 3,780
Selling, general, and administrative (49) 2,210 6,923
Taxes other than income taxes ...... 1,281 1,433 4
Depreciation and amortization ...... 4,844 4,088 494
------------------------------------
56,216 59,365 11,201
------------------------------------
LOSS FROM OTHER
OPERATIONS ..................... (6,891) (9,464) (4,543)
INTEREST EXPENSE AND OTHER INCOME:
Interest ........................... 4,910 11,420 6,605
Other income - net ................. (17,572) (8,065) (31,160)
------------------------------------
(12,662) 3,355 (24,555)
------------------------------------
INCOME BEFORE INCOME TAXES .............. 117,415 162,060 92,061
INCOME TAXES ............................ 32,123 51,615 26,227
------------------------------------
NONUTILITY NET INCOME
AVAILABLE FOR COMMON STOCK ......... $ 85,292 $ 110,445 $ 65,834
====================================
<PAGE>
NONUTILITY OPERATIONS
. TELECOMMUNICATIONS OPERATIONS
1999 Compared With 1998
- -----------------------
Because Touch America received the $257,000,000 prepayment on January 16,
1999, revenues from sales on Touch America's fiber-optic network were
approximately $23,200,000 less than they would have been had the customer not
exercised its option. (The effect for a full year will be approximately
$24,000,000.) Touch America is recognizing the prepayment in revenues over the
remaining term of the agreement. Earnings from unconsolidated investments,
approximately $9,800,000 of which were attributable to revenues from dark-fiber
sales through the FTV joint venture, were approximately $10,400,000 in 1999,
compared with earnings from unconsolidated investments in 1998 of approximately
$10,900,000. The decrease primarily resulted from a change in how we account for
dark-fiber transactions. The change in accounting resulted from Financial
Accounting Standards Board (FASB) Interpretation No. 43, "Real Estate Sales" (an
interpretation of SFAS No. 66, "Accounting for Sales of Real Estate"). As a
result, Touch America will recognize earnings of approximately $7,000,000 from
dark-fiber transactions pursuant to existing agreements entered into after June
30, 1999, over the applicable contract term.
After adjusting private-line revenues for the accounting effects of the
prepayment and after excluding the dark-fiber sales included in earnings from
unconsolidated investments, Touch America's 1999 operating revenues increased
approximately 21 percent as compared to 1998. With the same adjustments above,
Touch America's 1999 operating income increased approximately 24 percent.
The increase in operating revenues, after the above adjustments, mainly
consists of two elements. First, it reflects increased private-line revenues of
approximately $10,100,000 due to higher revenues from sales of fiber capacity.
Second, long-distance revenues, including Internet-service and equipment-service
revenues, increased approximately $7,800,000 as a result of increased
long-distance customer and minute sales and customer growth.
- --------------------------------------------------------------------------------
Table The following table shows year-to-date changes in long-distance
revenues for the previous two years, in millions of dollars, and the
related percentage changes in minutes sold, price per minute, and
customer growth.
- --------------------------------------------------------------------------------
1999 1998
---------------------
Revenues .................... $ 4 $ 3
Minutes sold ................ 31% 43%
Price per minute ............ (9%) (15%)
Customer growth ............. 26% 61%
- --------------------------------------------------------------------------------
Operations and maintenance (O&M) expense increased approximately
$7,700,000 as a result of increased private-line, equipment-service, and
long-distance sales. Depreciation and amortization expense increased
approximately $2,000,000 as a result of an increase in plant.
1998 Compared With 1997
- -----------------------
Revenues from telecommunications operations increased primarily due to
sales on Touch America's Washington-to-Minnesota and Colorado-to-Canada
fiber-optic network and a higher volume of long-distance minutes sold. We began
earning revenues from the fiber-optic network late in the third quarter of 1997.
We have a one-third interest in the FTV joint venture, which made dark-fiber
sales on an inland Portland-to-Los Angeles fiber-optic network. These dark-fiber
sales account for the $10,500,000 increase in earnings from unconsolidated
investments.
Expenses for 1998 were higher due to the operation of Touch America's
fiber-optic network mentioned above, increased marketing expenses, and costs
related to the increased long-distance service.
. COAL OPERATIONS
1999 Compared With 1998
- -----------------------
Income from coal operations in 1999 increased approximately $4,000,000
over 1998 mainly because of a one-time refund in 1998 to Colstrip Units 3 and 4
owners. Northwestern Resources' lignite revenues increased approximately
$13,600,000 as a result of a 1 percent increase in volumes sold and an increase
in reimbursable mining costs, partially offset by a reversal of revenues
previously recorded for deferred benefits.
Western Energy's consolidated 1999 revenues increased approximately
$6,400,000 over 1998 primarily because Western Energy paid approximately
$7,900,000 in one-time refunds in the third quarter of 1998 to the owners of
Colstrip Units 3 and 4 to settle contract disputes. This increase was offset in
part by a refund of $2,700,000 in the first quarter of 1999 for final pit
reclamation funds previously collected. In addition, volumes sold at the Rosebud
Mine increased 1 percent in 1999.
O&M expenses increased approximately $17,800,000 due to higher royalties,
equipment maintenance and rentals, and overburden stripping costs. SG&A expenses
decreased approximately $4,400,000 primarily from reversal of deferred benefit
costs at Northwestern Resources in 1999 and a lease abandonment in the fourth
quarter of 1998. Taxes other than income taxes increased due to the higher value
of coal sold in 1999 and a property tax refund received by Northwestern
Resources at the Jewett Mine in the third quarter of 1998, partially offset by
credits resulting from a court decision upholding Western Energy's position
regarding severance tax credits.
<PAGE>
1998 Compared With 1997
- -----------------------
Income from coal operations increased by $3,700,000 primarily due to an
increase in tons sold. Revenues from the Rosebud Mine, including revenues from a
synthetic fuel project at the mine, increased $9,500,000. Volume of coal sold to
the Colstrip Units in 1998 was 18 percent higher due to less downtime 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. As discussed earlier, these changes will result in modest
profit reductions until mid-year 2000 with greater 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 lignite sold.
O&M expenses increased primarily due to higher volumes at the Rosebud Mine
and increased stripping costs at the Jewett Mine. Depreciation and amortization
expenses decreased primarily as a result of the resolution of matters booked in
a prior year relating to the former Colorado mining operations.
. INDEPENDENT POWER OPERATIONS
1999 Compared With 1998
- -----------------------
Earnings from unconsolidated investments decreased approximately
$68,500,000 mainly because of the three events discussed at the beginning of the
MD&A section, "1999 Compared With 1998." After adjusting 1998 earnings from
unconsolidated investments by those items, CES' 1999 revenues increased
approximately $5,400,000 from its existing projects as a result of improved
operations.
Amortization expense was lower than in 1998 because CES recorded
amortization expense of approximately $5,900,000 in 1998 to reflect the reduced
value of its investment in the Encogen Four project as a result of the contract
buyout.
1998 Compared With 1997
- -----------------------
Earnings from unconsolidated investments increased approximately
$74,500,000 primarily because of CES' recognition of earnings in 1998 as a
result of the events discussed above.
Expenses increased approximately $7,800,000 mainly because of a $6,200,000
increase in the amortization of CES' independent power investments. Power-supply
expenses increased $2,200,000 resulting from increased generation, partially
offset by a decrease in project development costs of $1,100,000.
. OIL AND NATURAL GAS OPERATIONS
- --------------------------------------------------------------------------------
Table 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.
- --------------------------------------------------------------------------------
1999 1998
---------------------------------
Natural gas -revenue $ 101 $ 72
-volume 36% 96%
-price/Mcf 11% (20%)
Natural gas
liquids -revenue $ 12 $ 12
-volume 49% 244%
-price/bbl 11% (10%)
Oil -revenue $ 1 $ (12)
-volume (16%) (38%)
-price/bbl 30% (38%)
Miscellaneous -revenue $ 2 $ --
- --------------------------------------------------------------------------------
1999 Compared With 1998
- -----------------------
Income from oil and natural gas operations increased approximately
$8,300,000 due mainly to higher market prices in 1999. Natural gas revenues
increased because marketing and trading revenues and volumes were significantly
higher as a result of increased sales into California and Midwestern markets.
Natural gas production and prices were both higher than the prior year. Revenues
from oil operations were slightly higher because improved prices more than
offset lower production. Natural gas liquids revenues were higher, again because
of increased marketing and trading activities and higher prices.
O&M expenses increased mainly because of higher purchased natural gas and
higher gas prices. SG&A expenses decreased primarily from reduced incentive
compensation accruals and lower expenditures for outside services. Taxes other
than income taxes increased because of the higher value of the natural gas
produced from our reserves. Depreciation, depletion, and amortization expenses
increased reflecting higher natural gas production, as well as write-downs of
long-lived assets in our Canadian oil and natural gas operations in accordance
with SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of."
1998 Compared With 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. Natural gas and
natural gas liquids revenues increased due to production from properties
<PAGE>
acquired in the second quarter of 1997 and from former utility 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 lower prices in 1998.
O&M expenses increased due to the costs of operating the acquired
properties and transferred assets and because of purchased natural gas needed to
serve the new wholesale customers. Lower prices for purchased gas partially
offset this increase. New operations also accounted for the increases in SG&A
and depreciation, depletion, and amortization expenses.
. INTEREST EXPENSE AND OTHER INCOME, AND INCOME TAXES
1999 Compared With 1998
- -----------------------
Interest expense decreased primarily because we used funds from the
telecommunications prepayment to reduce nonutility debt.
Other income - net increased by approximately $9,500,000, of which
approximately $4,400,000 was attributable to interest income received on
investments. The remaining increase is largely because of increased intersegment
interest income on loans from nonutility operations to utility operations.
Income tax expense decreased because of lower pretax income and an
estimated lower effective tax rate for 1999.
1998 Compared With 1997
- -----------------------
Interest expense increased primarily due to increases in the amount of
outstanding borrowings to provide short-term financing for our nonutility
operations expansion and higher interest rates.
Other income - net decreased due to 1997 gains of approximately
$23,000,000 on sales of non-strategic oil and natural gas properties and a
$10,300,000 gain on the sale of our investment in a Brazilian gold mine. These
gains were partially offset by a loss on the sale of non-strategic Wyoming coal
properties. The absence of dividend income from the Brazilian gold mine and
interest income associated with a 1997 settlement with the IRS also reduced
other income.
The increase in income tax expense resulted from higher pretax income as
well as a credit to expense in 1997 associated with a settlement with the IRS.
LIQUIDITY AND CAPITAL RESOURCES
. OPERATING ACTIVITIES
Net cash provided by operating activities was $660,183,000 in 1999,
compared to $255,677,000 in 1998, and $201,091,000 in 1997. The current year
increase of $404,506,000 was attributable mainly to a $257,000,000 prepayment
received in January 1999 from a Touch America customer and $106,000,000 that we
received as a result of the termination of the purchase-power agreement with the
LADWP and the establishment of the new agreement. We are recognizing these
revenues over the remaining terms of the Touch America agreement and the new
agreement with the LADWP. Both agreements have approximately 11 years remaining.
We used cash from the telecommunications prepayment to reduce long-term debt and
short-term borrowings and pay taxes on the prepayment and on expected gains
resulting from the sale of our electric generating assets. We expect to use the
LADWP proceeds for general corporate purposes, including the expansion of Touch
America.
. INVESTING ACTIVITIES
Net cash provided by investing activities was $306,504,000 in 1999,
compared to net cash used for investing activities of $159,552,000 in 1998 and
$199,368,000 in 1997. The current year increase of $466,056,000 was due
primarily to the proceeds received from the sale of our generating assets. As
discussed in the "Financing Activities" section below, we have used some of the
sales proceeds to repurchase shares of our common stock, and we have begun to
retire long-term debt. We also intend to use some of the proceeds to expand
Touch America. See Note 5, "Sale of Electric Generating Assets," for information
regarding the sale of our generating assets and the use of proceeds from the
sale.
- --------------------------------------------------------------------------------
Table Forecasted capital expenditures for 2000 and capital expenditures
during the prior three years are as follows:
- --------------------------------------------------------------------------------
Forecasted Actual
---------------------------------------------
2000 1999 1998 1997
--------- --------------------------------
(Thousands of Dollars)
Utility ........................ $ 57,000 $ 63,598 $ 83,323 $138,318
Nonutility* .................... 397,000 221,709 130,078 173,368
-------- -------------------------------
Total ....................... $454,000 $285,307 $213,401 $311,686
======== ===============================
*Approximately $287,000,000 of the $397,000,000 forecasted 2000 nonutility
capital expenditures is for telecommunications operations. These forecasted
capital expenditures do not include amounts that may be necessary as a result of
the Qwest asset acquisition discussed in Note 3, "Commitments." If the Qwest
acquisition is closed, we do not expect the purchase price and subsequent
additional related capital expenditures to exceed $300,000,000.
- --------------------------------------------------------------------------------
Consistent with our strategy, we intend to invest the majority of our
utility's capital expenditures during 2000 in upgrading our electric and natural
gas transmission and distribution systems, and extending our electric and
natural gas distribution lines. Similarly, we expect to invest the majority of
our nonutility capital expenditures during 2000 on expanding and developing
Touch America's fiber-optic network and wireless
<PAGE>
communications systems. We also expect Touch America's network traffic to
increase and, therefore, expect these efforts to result in further capital
expenditures. See Item 1, "Business," under the "Telecommunications Operations,"
and Note 3, "Commitments," for further discussion of Touch America's projects
and commitments. In addition, we expect expenditures for future project
investments by our independent power operations; drilling, development, and
capital-improvement projects for our natural gas operations; and the
implementation of our ERP system.
We estimate that internally generated funds for 2000, by business unit,
will average 142 percent of our utility's capital expenditures, exclusive of the
expenses associated with the sale of our generation facilities, and 26 percent
of our nonutility construction program, exclusive of the Qwest asset acquisition
discussed in Note 3, "Commitments." We expect to finance any remaining capital
expenditure balances, as well as the repayment of maturing long-term debt, with
the remaining generation-sale proceeds, short-term and long-term debt, and with
sales of equity securities. The amounts and timing of these activities will
depend upon future market conditions. We expect to have adequate sources of
external capital to meet our financing needs.
. FINANCING ACTIVITIES
Net cash used for financing activities was $422,396,000 in 1999, compared
to $88,779,000 in 1998 and $27,981,000 in 1997.
In December 1998, the MPC Natural Gas Funding Trust (Trust), a wholly
owned subsidiary, issued $62,700,000 of 6.2 percent asset-backed securities
known as transition bonds. On February 1, 1999, we used the majority of these
proceeds to retire $55,000,000 of our 7.7 percent First Mortgage Bonds. The
transition bonds will be retired from funds collected by the Trust through
usage-based charges levied on natural gas transportation and distribution
customers. The retirements will occur at six-month intervals from September 15,
1999, through March 15, 2012, and will be in varying amounts depending on
revenues collected from customers. At December 31, 1999, $2,603,194 is
classified as due within one year on the Consolidated Balance Sheet.
As part of the Tier II rate filing discussed in Note 4, "Deregulation and
Regulatory Matters," we indicated our intention to retire approximately
$266,000,000 of long-term debt. We estimate that the expenses associated with
these retirements will be approximately $20,000,000. On September 3, 1999, we
retired $10,000,000 of our 7.875 percent Series B Unsecured Medium-Term Notes
(MTNs) due December 23, 2026. We retired an additional $5,000,000 of these MTNs
on October 13, 1999. In addition, we retired $5,000,000 of 7.25 percent Secured
MTNs due January 19, 2024, and $7,000,000 of 8.68 percent Unsecured Series A
MTNs due February 7, 2022, in January of 2000. We plan to retire the remaining
$239,000,000 of long-term debt throughout the year 2000.
We retired at maturity $2,500,000 of 8.90 percent Series A MTNs on October
1, 1999.
See Note 7, "Common Stock," for a discussion of our December 23, 1999,
purchase of 4,682,100 shares of our common stock, at a cost of $144,872,000,
through our share-repurchase program.
Dividends paid on common and preferred stock were $90,902,000 in 1999,
$91,598,000 in 1998, and $91,112,000 in 1997. During 1999, our regular quarterly
dividend level was 20 cents per share of outstanding stock or 80 cents per share
on an annual basis.
The Board of Directors periodically reviews our dividend policy to ensure
that our dividend payout and dividend rate are appropriate given our business
plan, strategy, and outlook. Our common stock dividend rate is dependent on our
results of operations, financial position, anticipated future uses of cash, and
other factors. In assessing the dividend policy, the Board of Directors also
evaluates the effect of the sale of our generation assets and the continued
growth of, and investment in, Touch America. As discussed in Item 1, Goldman,
Sachs & Co. is assisting in evaluating options with respect to implementing a
strategy to separate Touch America from Montana Power and maximize shareholder
value. The Board of Directors will continue to assess and adjust our dividend
policy in light of these and other developments.
The consolidated borrowing ability under our Revolving Credit and Term
Loan Agreements was $179,400,000, of which $161,900,000 was unused at December
31, 1999. We also have short-term borrowing facilities with commercial banks
that provide both committed and uncommitted lines of credit and the ability to
sell commercial paper.
Our long-term debt as a percentage of capitalization was 35 percent during
1999, and 37 percent in 1998 and 1997. Approximately $59,000,000 of long-term
debt will mature during the year 2000. With the generation sales proceeds
available to repurchase long-term debt, the above ratio could decrease during
2000. We have also entered into long-term lease arrangements and other long-term
contracts for sales and purchases that are not reflected on the Consolidated
Balance Sheet. For additional information, see Note 3, "Commitments."
While we do not expect to issue additional First Mortgage Bonds in 2000,
the Mortgage and Deed of Trust would not preclude us from issuing sufficient
First Mortgage Bonds to meet our expected financing requirements for the year.
Neither our restated Articles of Incorporation, the Mortgage and Deed of Trust,
or our Sinking Fund Debenture Agreement contain any restrictions on issuance of
short-term debt or preferred stock.
See Note 10, "Long-Term Debt," and Note 11, "Short-Term Borrowing," for
further information on our financing activities.
SEC RATIO OF EARNINGS TO FIXED CHARGES
For the twelve months ended December 31, 1999, our ratio of earnings to
fixed charges was 3.25 times compared to
<PAGE>
3.34 times for 1998 and 2.94 times for 1997. Fixed charges include interest, the
implicit interest of Colstrip Unit 4 rentals, and one-third of all other rental
payments.
INFLATION
We believe that, at currently anticipated levels, inflation will not
materially affect our results of operations.
YEAR 2000
We did not have any significant disruptions as a result of the calendar
rollover from 1999 to 2000. To achieve this result, we inventoried critical
information technology (IT) systems and non-information (non-IT) systems,
analyzed the systems to determine their Year 2000 (Y2K) readiness, replaced or
repaired systems, if necessary, and tested the systems to ensure their
availability and integrity. We completed and tested contingency plans to ensure
business continuity in the event of unanticipated problems, but we did not have
to activate any of our contingency plans.
We did not establish a formal process to track Y2K expenditures. Many of
the measures that mitigated Y2K effects coincided with normal operations and
maintenance and, therefore, were not accounted for separately as Y2K
expenditures. For example, a capital upgrade to the energy management system
that cost $460,000 was necessary to provide additional functionality and also
resulted in a Y2K benefit. Likewise, we implemented a new method of customer
billing at a cost of $3,100,000 and although it addressed the Y2K issue, the new
method was planned for reasons other than Y2K. Our Information Services
Department did track its Y2K expenditures and estimates that it spent
approximately $2,400,000 to address the Y2K issue. Although we are unable to
estimate our overall costs of ensuring that we were Y2K ready, these costs were
not material to our consolidated financial position, results of operations, or
cash flows.
The above information is a Year 2000 Readiness Disclosure pursuant to the
Federal Year 2000 Information and Readiness Disclosure Act.
NEW ACCOUNTING PRONOUNCEMENTS
New requirements associated with the accounting for derivative instruments
and hedging and trading activities eventually will affect MPT&M. In addition, a
recent interpretation of how to properly account for certain dark-fiber sales
has affected Touch America.
. SFAS No. 133 AND SFAS No. 137
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. In July 1999, the FASB issued SFAS No. 137, "Accounting for
Derivative Instruments and Hedging Activities: Deferral of the Effective Date of
FASB Statement No. 133." SFAS No. 137 delays for one year the effective date of
SFAS No. 133. This delay means that we are not required to adopt SFAS No. 133
until January 1, 2001. However, we can adopt it earlier if we choose to do so.
We have not yet determined the effect that adopting SFAS No. 133 will have on
our consolidated financial position, results of operations, or cash flows.
Changes in the fair value of derivatives will be 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. The
statement distinguishes between (1) fair-value hedges, defined as hedges of
assets, liabilities, or firm commitments, and (2) 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 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 affected by the variability of the cash flows of the
hedged item. The ineffective portions of all hedges will be recognized in
current earnings.
. FASB INTERPRETATION NO. 43
On July 8, 1999, the FASB issued Interpretation No. 43, "Real Estate
Sales," which is an interpretation of SFAS No. 66, "Accounting for Sales of Real
Estate." This interpretation, which requires entities to recognize revenues from
dark-fiber sales over the period of the contract rather than at the time of sale
if title to the rights of use does not transfer to the lessee at the end of the
contract, applies to transactions entered into after June 30, 1999. As a result
of FASB Interpretation No. 43, we changed how we account for transactions
involving dark-fiber sales on a prospective basis. Rather than recognizing
approximately $7,000,000 in revenues in the fourth quarter from dark-fiber
transactions pursuant to existing agreements entered into after June 30, 1999,
Touch America will recognize these earnings over the term of the applicable
contract.
ENVIRONMENTAL ISSUES
For a discussion of environmental issues and how they affect us, see Item
1, "Business," under the "Environmental Issues" section.
<PAGE>
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
- -------------------------------------------------------------------
Our energy commodity-producing, trading, and marketing activities and
other investments and agreements expose us to the market risks associated with
fluctuations in commodity prices, interest rates, and changes in foreign
currency translation rates. We specify below what these risks are to our
businesses and estimate what could occur under certain adverse market conditions
and other assumptions. Because we base our estimates on assumptions only, actual
results under the conditions assumed below could differ materially from our
estimates. In addition, these disclosures indicate only reasonably possible
losses and do not necessarily indicate expected future losses.
TRADING INSTRUMENTS
Commodity price risk represents the primary market risk to which our
unregulated energy-commodity producing, trading, and marketing operations are
exposed. We discuss the derivative financial instruments that we use to manage
this risk in Note 1, "Summary of Significant Accounting Policies, Derivative
Financial Instruments." We do not use derivative financial instruments to hedge
against exposure to fluctuations in interest rates or foreign currency exchange
rates. We do, however, have investments in independent power partnerships, some
of which have used derivative financial instruments to hedge against interest
rate exposure on floating rate debt. At December 31, 1999, however, we believe
that we would not experience any material adverse effects from the risks
inherent in the independent power partnerships' instruments.
. ELECTRICITY
In June 1998, prior to our August 1998 decision to exit the electric
trading and marketing businesses, MPT&M entered into a derivative financial
transaction, called a "swap," in conjunction with one of our electric retail
sales contracts. That swap allows us to receive the difference between a fixed
price and a market-index price for electricity. We net the difference against
the cost of purchasing electricity to serve the retail sales contract. Thus, the
swap, which expires before the supply contract, allows us to mitigate our losses
on the retail sales contract.
. CRUDE OIL, NATURAL GAS, AND NATURAL GAS LIQUIDS
In December 1998, our Audit Committee adopted commodity risk-management
policies and practices to govern the execution, recording, and reporting of
derivative financial instruments and physical transactions associated with the
trading and marketing activity of crude oil, natural gas, and natural gas
liquids engaged in by MPT&M. These policies and practices require MPT&M to
identify, quantify, and report commodity risks and to hold regular Risk
Management Committee meetings. Our Risk Management Committee (1) approves the
risk-related trading activities in which MPT&M participates and the kinds of
instruments that MPT&M may use, and (2) recommends to our Audit Committee
specific limits for MPT&M's trading activity.
MPT&M's value-at-risk (VaR) is based on J.P. Morgan's RiskMetrics(TM)
approach: variance/co-variance. This approach uses historical estimates of
volatility and correlation and values optionality using delta equivalents. Thus,
it provides us a measure of MPT&M's exposure to potential losses from future
adverse changes in the fair value of the commodities and financial instruments
MPT&M trades. Because actual future changes in markets - prices, volatilities,
and correlations - may be inconsistent with historical observations, MPT&M's VaR
as measured by RiskMetrics(TM) may not accurately reflect future adverse changes
in fair values.
MPT&M calculates its VaR assuming a forward 24-month time period, a
one-day holding period, and a 95 percent confidence level. The calculation
indicates how much MPT&M could lose from its trading transactions under those
and other assumptions. At December 31, 1999, MPT&M's VaR calculation for
physical and financial crude oil, natural gas, and natural gas liquids
transactions, including forecasts of affiliate-owned production, was
approximately $1,400,000.
Our Audit Committee established a "VaR limit" to manage our exposure to
potential losses from trading activity. MPT&M must report to that committee the
number of times it exceeds the established limit. On June 21, 1999, our Audit
Committee increased MPT&M's VaR limit to $2,000,000, to include crude oil and
natural gas liquids and forecasts of affiliate-owned production.
VAR RESULTS
. From January 1, 1999, through June 20, 1999, when MPT&M's VaR limit
was set at $1,000,000, it reported daily adverse changes in fair
values in excess of that $1,000,000 limit on seven occasions;
. From June 21, 1999, through December 31, 1999, when MPT&M's VaR
limit was set at $2,000,000, it reported daily adverse changes in
fair values in excess of that $2,000,000 limit on six occasions; and
. From January 1, 2000, through March 1, 2000, MPT&M reported daily
adverse changes in fair values in excess of its VaR limit on no
occasions.
. COUNTERPARTY CREDIT RISK
Commodity price changes may provide a motive to our counterparties to
default on their delivery or payment obligations to us under our physical and
financial crude oil, natural gas, and natural gas liquids trading instruments.
Our
<PAGE>
corporate credit risk policy requires us to investigate and monitor the
creditworthiness of our physical and financial trading counterparties. We do not
expect nonperformance by these trading counterparties to have a material adverse
effect on our consolidated financial position, results of operations, or cash
flows.
. SUMMARY OF 1998 AND COMPARISON OF 1999 WITH 1998
At December 31, 1998, we had no derivative financial contracts relating to
crude oil or natural gas liquids, nor did our VaR limit include those
commodities. At December 31, 1999, we include derivative financial contracts
relating to those commodities in the calculation of our VaR limit. At both
dates, however, our VaR calculation was less than $2,000,000.
OTHER-THAN-TRADING INSTRUMENTS
. COMMODITY PRICE EXPOSURE
UTILITY
The Public Utilities Regulatory Policies Act (PURPA) required that our
electric utility enter into agreements with Qualifying Facilities (QFs) for the
purchase or exchange of electricity under contracts with expiration terms
ranging from 2003 through 2031. At December 31, 1999, we estimate that these
contracts could result in above-market costs of between $300,000,000 and
$500,000,000 throughout their duration. 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. We are evaluating options for divestiture of
these contracts.
Our electric utility also entered into two Wholesale Transition Service
Agreements (WTSAs), effective December 17, 1999, with PPL Montana. These
agreements enable us to fulfill our obligation to supply power until July 2002
to those customers who have not chosen another supplier. Both agreements price
the power sold at a market index, with a monthly floor and an annual cap and,
therefore, limit our exposure to price fluctuations of the electricity market to
the cap, but expose us to price fluctuations below the floor.
Our natural gas utility entered into take-or-pay contracts with Montana
natural gas producers to provide adequate supplies of natural gas for our
utility customers. We currently have six of these contracts, with expirations
between 2000 and 2006.
These electric and natural gas agreements have liquidating damage clauses
that require the non-performing party to pay the other party the positive
difference between the market and contract prices plus transportation and other
fees. We believe that the possibility of non-performance is remote and,
therefore, have not calculated its financial effect.
We expect to recover all reasonable costs associated with the QF contracts
through competitive transition charges (CTCs), all reasonable costs associated
with the WTSA contracts in the electric restructuring process, and the
reasonable costs associated with the take-or-pay contracts through future
natural gas rates. Therefore, we do not expect these contracts to expose us to
market risks related to commodity price fluctuations. However, recovery of the
costs associated with these contracts is subject to the possibility of
regulatory lag or even disallowance. For additional information, see Note 4,
"Deregulation and Regulatory Matters."
We entered into a contract to sell electricity to an industrial customer
at terms that include a fixed price for a portion of the power delivered and an
index-based price for another portion. Approximately three years from now, the
contract provides that we sell all power to our customer at an index-based
price. Since the sale of our generating assets on December 17, 1999, we have had
to serve this customer with power purchased in the electricity market. Because
the price of that power could be greater than the fixed-price portion of the
contract, the fixed-price portion subjects us to commodity price risk. With the
uncertainties relating to the supply requirements of the contract and
uncertainties surrounding various arrangements that would allow us to serve the
contractual demand, we cannot determine at this time the potential effects of
this contract on our future consolidated financial position, results of
operations, and cash flows. MPT&M has entered into a swap agreement to mitigate
the commodity price risk inherent in this contract, and we continue to examine
other options to minimize our costs.
NONUTILITY
Northwestern Resources 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 of
certain mining costs as well as management and dedication fees and, therefore,
does not expose us to commodity price risk. Under a settlement reached in August
1999, the pricing structure will change July 1, 2002, to one driven by the
market for Powder River Basin (PRB) coal adjusted for transportation and other
costs. We estimate that, after mid-2002, a hypothetical 10 percent decrease of
the PRB market price adjusted for transportation costs would reduce annual
revenues by approximately $3,000,000.
Western Energy also has full-requirements contracts for the sale of coal
to the four mine-mouth electric generating plants at Colstrip. The contract for
Units 1 and 2 provides for a price re-opener in 2001 to adjust prices that
reflect changes in mining costs. Because our mining costs are not directly tied
to market price changes, the Units 1 and 2 contract is not subject to commodity
price risk. The contract for Colstrip Units 3 and 4 requires that we constantly
evaluate alternative supplies.
<PAGE>
1999 Form 10-K The Montana Power Company
- --------------------------------------------------------------------------------
Part II . Item 7A . Quantitative And Qualitative Disclosures About Market Risk
However, neither Western Energy nor the Colstrip Project Division has a unit
train off-loading facility. Because the prices of alternative supplies must
include the substantial cost of constructing this facility, a hypothetical 10
percent decrease in the prices of these competitive coal supplies would not
materially affect us.
Before MPT&M exited the electric trading and marketing business, it
entered into both electric purchase and sale contracts, expiring between 2000
and 2002. Some of these contracts are based on indexed-based prices and others
on fixed prices. The fair values of the fixed-price contracts are subject to
changes in electric market prices.
CES has equity interests in various electric generation and co-generation
projects, expiring between 2008 and 2023. These projects sell power under
contracts with prices determined by PURPA and other contracts with indexed-based
or fixed prices. Even the fixed-price contracts limit our exposure to commodity
price risk, because fuel costs are controlled through long-term or pass-through
contracts.
CES' Colstrip 4 Lease Management Division sells the leased share of
Colstrip Unit 4 generation principally to the LADWP and to Puget under contracts
that expire at the same time as our sale-leaseback agreement of Colstrip Unit 4.
In December 1999, we agreed with the LADWP to terminate the 11 remaining years
of the existing contract, and we entered into a new power purchase agreement
with the LADWP to provide 111 MWs of capacity and energy from December 21, 1999,
to December 29, 2010, scheduled at rates over the duration of the agreement. We
received $106,000,000 from the LADWP as consideration for the termination of the
existing agreement and the establishment of the new agreement. The new agreement
subjects us to commodity price risk to the extent that our operational and fuel
costs exceed the revenues allowable under the price schedule.
- --------------------------------------------------------------------------------
Table Based on mark-to-market analyses and the net present value of
forecasted cash flows at December 31, 1999, the table set forth
below contains estimates of the fair market values of the above
electric purchase and sale contracts as well as the effect on those
values of a hypothetical 10 percent increase in electricity prices:
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Effect of 10%
Fair Price Increase On
Company Market Value Fair Market Value Difference
- ---------------------------------------------------------------------------------------------
<S> <C> <C> <C>
MPT&M $ 1,300,000 $ 1,200,000 $ 100,000
CES 110,000,000 102,700,000 7,300,000
Colstrip Management 43,400,000 42,300,000 1,100,000
---------------------------------------------------------
Total $ 154,700,000 $ 146,200,000 $ 8,500,000
</TABLE>
- --------------------------------------------------------------------------------
. INTEREST RATE EXPOSURE
SFAS No. 107, "Disclosures about Fair Value of Financial Instruments,"
defines instruments readily convertible to cash as "financial instruments."
These financial instruments principally include our cost-basis investments in
independent power projects, the reclamation fund, mandatorily redeemable
preferred securities, and long-term debt. All of these instruments are exposed
to potential loss in fair value from adverse changes in interest rates. Assuming
the fair values estimated for the SFAS No. 107 analysis and a hypothetical 10
percent adverse change in interest rates, we estimate that (1) the potential
loss in the December 31, 1999, fair value of the reclamation fund and cost-based
investments would be immaterial; and (2) the potential loss in the December 31,
1999, fair values of the mandatorily redeemable preferred securities and
long-term debt would be approximately $5,700,000 and $26,500,000, respectively.
Note 1, "Summary of Significant Accounting Policies, Fair Value of Financial
Instruments," provides further information about fair valuation.
. FOREIGN CURRENCY EXPOSURE
Our primary foreign currency exposure results from (1) our Canadian
subsidiaries - Altana Exploration Company and Altana Exploration Ltd. -
exploring for, producing, gathering, processing, transporting, and marketing
natural gas and crude oil in Canada, and (2) MPT&M trading and marketing natural
gas in Canada. There has been no material change in these activities or the
corresponding foreign currency risk associated with these activities. We
believe, therefore, that the market risk associated with a hypothetical 10
percent adverse change in foreign currency translation is immaterial.
. SUMMARY OF 1998 AND COMPARISON OF 1999 WITH 1998
At December 31, 1998, our utility and nonutility businesses exposed us to
the same kinds of risks that we reported at December 31, 1999. We summarize
below the significant differences between our discussion of those risks in 1998
and 1999:
<PAGE>
. In 1998, we estimated the commodity price risk associated with
Northwestern Resources' contract from 2002 to 2015, assuming that the
market price of PRB coal would remain flat. In 1999, we did not consider
that assumption relevant and, therefore, did not estimate its effect on
Northwestern Resources' projected pretax income.
. In 1998, we did not estimate the total fair market value of CES' equity
investments in power sale projects or the effect of a hypothetical 10
percent increase of electric market prices on that fair market value.
Based on the same assumptions that we used to calculate those values for
1999 above, we estimate that, at December 31, 1998, those values would
have been $111,500,000 and $104,000,000, respectively.
. In 1998, we estimated that a hypothetical 10 percent increase in interest
rates would decrease the fair market values of our long-term debt by
$15,200,000. In 1999, we estimated that it would decrease it by
$26,500,000. The estimated decrease was greater in 1999 due to the higher
interest rates of 1999 used to compute the fair market value of long-term
debt.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
- ---------------------------------------------------
INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page
Management's Responsibility
for Financial Statements ........................................... 58
Report of Independent Accountants ....................................... 58
Consolidated Financial Statements:
Consolidated Statements of Income
for the Years Ended
December 31, 1999, 1998, and 1997 .............................. 59
Consolidated Balance Sheets as of
December 31, 1999 and 1998 ..................................... 60
Consolidated Statements of Cash Flows
for the Years Ended
December 31, 1999, 1998, and 1997 .............................. 62
Consolidated Statements of
Common Shareholders' Equity
for the Years Ended
December 31, 1999, 1998, and 1997 .............................. 63
Notes to Consolidated Financial Statements ......................... 64
Supplementary Data (Unaudited) .......................................... 88
Financial Statement Schedule II,
Valuation and Qualifying Accounts and Reserves .......................... 98
Financial Statement Schedules not included in this Form 10-K have been omitted
because they are inapplicable or the required information is shown in the
Consolidated Financial Statements or in the Notes to the Consolidated Financial
Statements.
<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 on Form 10-K 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 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
Robert P. Gannon J. P. Pederson
Chairman of the Board and Vice President and
Chief Executive Officer Chief Financial Officer
- --------------------------------------------------------------------------------
REPORT OF INDEPENDENT ACCOUNTANTS
[LOGO OF PRICEWATERHOUSECOOPERS LLP]
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, 1999
and 1998, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 1999, in conformity with
accounting principles generally accepted in the United States. In addition, in
our opinion, the financial statement schedule listed in the accompanying index
presents fairly, in all material respects, the information set forth therein
when read in conjunction with the related consolidated financial statement.
These financial statements and financial statement schedule are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements and financial statement schedule based on
our audits. We conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States, 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.
As more fully discussed in Note 1 to the Consolidated Financial
Statements, as of July 1, 1999, the Company changed its method of accounting for
transactions involving the sale of dark fiber.
/s/ PriceWaterhouseCoopers LLP
Portland, Oregon
February 10, 2000, except in Note 3 for the final paragraph under the
"Telecommunications" section entitled "Investments and Acquisitions," as to
which the date is March 13, 2000
<PAGE>
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Consolidated Statement of Income
The Montana Power Company and Subsidiaries
- -----------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31
---------------------------------------------------
1999 1998 1997
---------------------------------------------------
(Thousands of Dollars)
(except per-share amounts)
<S> <C> <C> <C>
REVENUES ............................................................... $ 1,342,309 $ 1,267,271 $ 1,023,597
EXPENSES:
Operations ......................................................... 668,521 541,743 420,032
Maintenance ........................................................ 81,553 81,064 82,702
Selling, general, and administrative ............................... 138,248 128,741 116,054
Taxes other than income taxes ...................................... 103,881 96,181 92,967
Depreciation, depletion, and amortization .......................... 111,145 114,267 95,340
Write-downs of long-lived assets ................................... 7,083 -- --
---------------------------------------------------
1,110,431 961,996 807,095
---------------------------------------------------
INCOME FROM OPERATIONS ......................................... 231,878 305,275 216,502
INTEREST EXPENSE AND OTHER INCOME:
Interest ........................................................... 43,006 60,851 54,667
Distributions on company obligated mandatorily
redeemable preferred securities of subsidiary trust ............ 5,492 5,492 5,492
Other income - net ................................................. (11,029) (4,862) (34,159)
---------------------------------------------------
37,469 61,481 26,000
---------------------------------------------------
INCOME TAXES ........................................................... 44,063 78,174 61,870
---------------------------------------------------
NET INCOME ............................................................. 150,346 165,620 128,632
DIVIDENDS ON PREFERRED STOCK ........................................... 3,690 3,690 3,690
---------------------------------------------------
NET INCOME AVAILABLE FOR COMMON STOCK .................................. $ 146,656 $ 161,930 $ 124,942
===================================================
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING-Basic (000) ................ 109,795 109,962 109,298
BASIC EARNINGS PER SHARE OF COMMON STOCK ............................... $ 1.34 $ 1.47 $ 1.14
===================================================
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING-Diluted (000) .............. 110,553 110,156 109,400
DILUTED EARNINGS PER SHARE OF COMMON STOCK ............................. $ 1.33 $ 1.47 $ 1.14
===================================================
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
The accompanying notes are an integral part of these statements.
<PAGE>
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------
Consolidated Balance Sheet
The Montana Power Company and Subsidiaries
Assets
- -----------------------------------------------------------------------------------------
December 31
-----------------------
1999 1998
-----------------------
(Thousands of Dollars)
<S> <C> <C>
PLANT AND PROPERTY IN SERVICE:
Utility plant ............................................. $1,466,727 $2,246,847
Less - accumulated depreciation and depletion ......... 464,653 732,385
-----------------------
1,002,074 1,514,462
Nonutility property ....................................... 1,051,997 864,981
Less - accumulated depreciation and depletion ......... 349,045 297,933
-----------------------
702,952 567,048
-----------------------
1,705,026 2,081,510
MISCELLANEOUS INVESTMENTS:
Independent power investments ............................. 23,460 24,268
Reclamation fund .......................................... 43,460 41,542
Other ..................................................... 93,231 84,256
-----------------------
160,151 150,066
CURRENT ASSETS:
Cash and cash equivalents ................................. 554,407 10,116
Temporary investments ..................................... 40,417 --
Accounts receivable, net of allowance for doubtful accounts 182,248 170,652
Notes receivable .......................................... -- 29,089
Materials and supplies (principally at average cost) ...... 37,928 42,292
Prepayments and other assets .............................. 53,733 57,331
Deferred income taxes ..................................... 18,303 18,755
-----------------------
887,036 328,235
DEFERRED CHARGES:
Advanced coal royalties ................................... 12,506 14,312
Regulatory assets related to income taxes ................. 60,538 121,735
Regulatory assets - other ................................. 150,486 154,193
Other deferred charges .................................... 73,000 78,044
-----------------------
296,530 368,284
$3,048,743 $2,928,095
-----------------------
- -----------------------------------------------------------------------------------------
</TABLE>
The accompanying notes are an integral part of these statements.
<PAGE>
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------
Consolidated Balance Sheet
The Montana Power Company and Subsidiaries
Liabilities and Shareholders' Equity
- ------------------------------------------------------------------------------------------------------------
December 31
--------------------------
1999 1998
--------------------------
(Thousands of Dollars)
<S> <C> <C>
CAPITALIZATION:
Common shareholders' equity:
Common stock (240,000,000 shares without par
value authorized; 110,218,973 and 110,121,040 shares issued) ..... $ 702,773 $ 702,511
Treasury stock (4,682,100 shares authorized, issued, and
repurchased by the Company) ...................................... (144,872) --
Unallocated stock held by trustee for Retirement Savings Plan ......... (20,401) (23,298)
Retained earnings and other shareholders' equity ...................... 488,975 430,309
Accumulated other comprehensive loss .................................. (17,659) (20,717)
--------------------------
1,008,816 1,088,805
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 ............................................................ 618,512 698,329
--------------------------
1,749,982 1,909,788
CURRENT LIABILITIES:
Short-term borrowings ..................................................... -- 69,820
Long-term debt-portion due within one year ................................ 58,955 96,292
Dividends payable ......................................................... 22,746 22,765
Income taxes .............................................................. 152,739 24,857
Other taxes ............................................................... 54,630 51,777
Accounts payable .......................................................... 115,654 97,197
Interest accrued .......................................................... 11,597 13,156
Other current liabilities ................................................. 92,277 40,087
--------------------------
508,598 415,951
DEFERRED CREDITS:
Deferred income taxes ..................................................... 8,847 323,906
Investment tax credits .................................................... 13,330 33,819
Accrued mining reclamation costs .......................................... 135,075 129,558
Deferred revenue .......................................................... 311,751 19,950
Net proceeds from the generation sale ..................................... 219,726 --
Other deferred credits .................................................... 101,434 95,123
--------------------------
790,163 602,356
--------------------------
CONTINGENCIES AND COMMITMENTS (Notes 2 and 3)
$ 3,048,743 $ 2,928,095
==========================
- ------------------------------------------------------------------------------------------------------------
</TABLE>
The accompanying notes are an integral part of these statements.
<PAGE>
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Consolidated Statement of Cash Flows
The Montana Power Company and Subsidiaries
- -----------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31
---------------------------------------------------
1999 1998 1997
---------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
NET CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ......................................................... $ 150,346 $ 165,620 $ 128,632
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation, depletion, and amortization ...................... 111,145 114,267 95,340
Write-downs of long-lived assets ............................... 7,083 -- --
Deferred income taxes .......................................... (304,854) (24,733) 10,677
Noncash earnings from unconsolidated investments ............... (20,608) (10,871) (14,016)
(Gains) losses on sales of property and investments ............ (1,960) 4,669 (33,849)
Other - net .................................................... 17,230 31,092 24,699
Changes in assets and liabilities:
Accounts and notes receivable ............................. 17,493 (68,754) 19,760
Deferred income taxes ..................................... 452 (8,216) 556
Accounts payable .......................................... 18,457 19,376 15,603
Generation asset sale - net proceeds ...................... 219,726 -- --
Income taxes payable ...................................... 127,882 21,054 (7,281)
Deferred revenue and other ................................ 291,801 11,948 6,597
Other assets and liabilities - net ........................ 25,990 225 (45,627)
---------------------------------------------------
Net cash provided by operating activities .................... 660,183 255,677 201,091
---------------------------------------------------
NET CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures ............................................... (285,307) (213,401) (311,686)
Proceeds from property and investments ............................. 594,762 55,643 135,577
Additional investments ............................................. (2,951) (1,794) (23,259)
---------------------------------------------------
Net cash provided by (used for) investing activities ......... 306,504 (159,552) (199,368)
---------------------------------------------------
NET CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends paid ..................................................... (90,902) (91,598) (91,112)
Sales of common stock .............................................. 751 7,421 2,201
Purchase of treasury stock ......................................... (144,872) -- --
Issuance of long-term debt ......................................... 30,089 139,947 103,375
Retirement of long-term debt ....................................... (147,642) (80,411) (71,634)
Issuance of mandatorily redeemable preferred securities ............ -- -- (67)
Net change in short-term borrowing ................................. (69,820) (64,138) 29,256
---------------------------------------------------
Net cash used for financing activities ....................... (422,396) (88,779) (27,981)
---------------------------------------------------
CHANGE IN CASH FLOWS ................................................... 544,291 7,346 (26,258)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR ........................... 10,116 2,770 29,028
---------------------------------------------------
CASH AND CASH EQUIVALENTS, END OF YEAR ................................. $ 554,407 $ 10,116 $ 2,770
===================================================
SUPPLEMENTAL DISCLOSURES OF CASH FLOW:
Cash paid during the year for:
Income taxes, net of refunds ................................... $ 213,362 $ 90,663 $ 50,797
Interest ....................................................... 53,273 67,777 59,681
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
The accompanying notes are an integral part of these statements.
<PAGE>
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Consolidated Statement of Common Shareholders' Equity
The Montana Power Company and Subsidiaries
- -----------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31
---------------------------------------------------
1999 1998 1997
---------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
COMMON STOCK:
Balance at beginning of year ....................................... $ 702,511 $ 694,561 $ 691,853
Issuances (100,857; 663,622; and 195,430 shares) ................... 357 7,950 2,708
Reacquired capital stock (4,682,100 shares) ........................ (144,872) -- --
Premium on capital stock ........................................... (95) -- --
---------------------------------------------------
Balance at end of year ............................................. 557,901 702,511 694,561
---------------------------------------------------
RETAINED EARNINGS AND OTHER SHAREHOLDERS' EQUITY:
Balance at beginning of year ........................................ 430,309 356,327 318,977
Net income .......................................................... 150,346 165,620 128,632
Dividends on common stock (80 cents per share each year) ............ (88,155) (88,008) (87,494)
Dividends on preferred stock ........................................ (3,690) (3,690) (3,690)
Other ............................................................... 165 60 (98)
---------------------------------------------------
Balance at end of year .............................................. 488,975 430,309 356,327
---------------------------------------------------
ACCUMULATED OTHER COMPREHENSIVE INCOME (loss):
Balance at beginning of year ........................................ (20,717) (13,354) (11,173)
---------------------------------------------------
Net income .......................................................... 150,346 165,620 128,632
Foreign currency translation adjustments ............................ 3,058 (7,363) (2,181)
---------------------------------------------------
Total comprehensive income .......................................... 153,404 158,257 126,451
Deduct net income included in comprehensive income .................. (150,346) (165,620) (128,632)
---------------------------------------------------
Other comprehensive income (loss) ................................... 3,058 (7,363) (2,181)
---------------------------------------------------
Balance at end of year .............................................. (17,659) (20,717) (13,354)
---------------------------------------------------
UNALLOCATED STOCK HELD BY TRUSTEE FOR RETIREMENT SAVINGS:
Balance at beginning of year ........................................ (23,298) (25,945) (28,360)
Distributions ....................................................... 2,897 2,647 2,415
---------------------------------------------------
Balance at end of year .............................................. (20,401) (23,298) (25,945)
---------------------------------------------------
TOTAL COMMON SHAREHOLDERS' EQUITY AT END OF YEAR ....................... $ 1,008,816 $ 1,088,805 $ 1,011,589
===================================================
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
The accompanying notes are an integral part of these statements.
<PAGE>
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
- ---------------------------------------------------
BASIS OF ACCOUNTING
Our accounting policies conform with generally accepted accounting
principles. With respect to our utility operations, these policies are in
accordance with the accounting requirements and ratemaking practices of
applicable regulatory authorities.
USE OF ESTIMATES
Preparing financial statements requires the use of estimates based on
information available. Actual results may differ from our accounting estimates
as new events occur or we obtain additional information.
RECLASSIFICATIONS
We have made reclassifications to certain prior-year amounts to make them
comparable to the 1999 presentation. These changes had no effect on previously
reported results of operations or shareholders' equity.
CONSOLIDATION PRINCIPLES
The consolidated financial statements include accounts and results of our
wholly owned subsidiaries. We have eliminated significant intercompany balances
and transactions. We account for our significant telecommunications and
independent power investments using the equity method, because we exercise
significant influence over those operations. To facilitate the timely
preparation of the consolidated financial statements, the accounts of certain
operations have been consolidated for fiscal years ending in November. The
consolidated financial statements in fiscal year 2000 will eliminate the
one-month lag in reporting for these operations. The results of operations of
December 1999 for these entities, which would have previously been reported in
results of fiscal year 2000, will be recorded as an adjustment to beginning
retained earnings for fiscal year 2000.
. PROPERTY AND PLANT
- --------------------------------------------------------------------------------
Table The following table provides year-end balances of the major
classifications of property and plant:
- --------------------------------------------------------------------------------
December 31
-----------------------
1999 1998
-----------------------
(Thousands of Dollars)
UTILITY PLANT:
- -------------
Electric:
Generation (including
jointly owned) ................................ $ 11,954 $ 724,483
Transmission .................................... 372,174 373,630
Distribution .................................... 573,531 550,844
Other ........................................... 92,684 192,899
Natural Gas:
Production and storage .......................... 73,959 75,658
Transmission .................................... 163,968 152,804
Distribution .................................... 147,764 146,896
Other ........................................... 30,693 29,633
-----------------------
Total Utility ................................. 1,466,727 2,246,847
NONUTILITY PLANT:
- ----------------
Coal ............................................ 240,228 237,913
Oil and Natural Gas ............................. 432,763 388,153
Technology ...................................... 238,147 113,474
Electric generation ............................. 76,536 76,189
Other ........................................... 64,323 49,252
-----------------------
Total Nonutility .............................. 1,051,997 864,981
-----------------------
Total Plant ................................... $2,518,724 $3,111,828
=======================
- --------------------------------------------------------------------------------
We capitalize the cost of plant additions and replacements, including an
allowance for funds used during construction (AFUDC), of utility plant. We
determine the rate used to compute AFUDC in accordance with a formula
established by the Federal Energy Regulatory Commission (FERC). This rate
averaged 7.1 percent for 1999, 8.3 percent for 1998, and 8.0 percent for 1997.
We charge costs of utility depreciable units of property retired, plus costs of
removal less salvage, to accumulated depreciation and recognize no gain or loss.
We recognize gain or loss upon the sale or other disposition of nonutility
property. We charge maintenance and repairs of plant and property, as well as
replacements and renewals of items determined to be less than established units
of plant, to operating expenses.
For information on the sale of our electric generating assets, see Note 5,
"Sale of Electric Generating Assets."
Included in the plant classifications are utility plant under construction
in the amounts of $3,782,000 and $37,966,000 for 1999 and 1998, respectively,
and nonutility plant under construction in the amounts of $134,817,000 and
$10,990,000 for 1999 and 1998, respectively.
We record provisions for depreciation and depletion at amounts
substantially equivalent to calculations made on straight-line and
unit-of-production methods by applying various rates based on useful lives of
properties determined
<PAGE>
from engineering studies. As a percentage of the depreciable and depletable
utility plant at the beginning of the year, our provisions for depreciation and
depletion of utility plant were approximately 3 percent for 1999, 1998, and
1997.
Our nonutility oil and natural gas operations use the successful-efforts
method of accounting for exploration and development costs.
JOINTLY OWNED ELECTRIC PLANT
Prior to the sale of the utility generating assets discussed in Note 5,
"Sale of Electric Generating Assets," we were a joint-owner of Colstrip Units 1,
2, and 3. We owned 50 percent of Units 1 and 2 and 30 percent of Unit 3. We also
owned an approximate 30 percent interest in the transmission facilities serving
these units. After the asset sale, we still own the transmission assets and
associated microwave equipment which remain in property, plant, and equipment
and, at December 31, 1999, our investment in these facilities was $43,380,000
and the related accumulated depreciation was $15,452,000.
We also own $43,084,000 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. The accumulated depreciation related to Unit 4 production and
transmission plant was $20,327,000 and $9,255,000, respectively.
Each joint-owner provides its own financing. Our share of direct expenses
associated with the operation and maintenance of these joint facilities,
including Colstrip Units 1, 2, and 3 through December 17, 1999, is included in
the corresponding operating expenses in the Consolidated Statement of Income.
RECLAMATION FUND
Under the current Colstrip Units 3 and 4 coal supply agreement, we
maintain a reclamation fund representing restricted cash necessary to meet our
estimated reclamation obligation at Western Energy for Units 3 and 4. We invest
the funds required for these reclamation obligations until we need them to
perform reclamation. At December 31, 1999, we had the funds invested entirely in
a money market account. We regularly accrue an expense and an offsetting
liability associated with our reclamation obligation. The reclamation fund is
not offset against our accumulated liability.
REVENUE AND EXPENSE RECOGNITION
We record operating revenues on the basis of consumption or service
rendered. To match revenues with associated expenses, we accrue unbilled
revenues for electric, natural gas, and telecommunication services delivered to
customers but not yet billed at month-end.
The Emerging Issues Task Force (EITF) Issue No. 98-10 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
fiscal years beginning after December 15, 1998. We adopted EITF 98-10 as of
January 1, 1999, and accordingly mark to market energy contracts that qualify as
"trading activities." The cumulative effect of adopting EITF 98-10 was not
significant.
On July 8, 1999, the FASB issued Interpretation No. 43, "Real Estate
Sales," which is an interpretation of SFAS No. 66, "Accounting for Sales of Real
Estate." This interpretation, which requires entities to recognize revenues from
dark-fiber sales over the period of the contract rather than at the time the
contract was entered into, if title to the rights of use does not transfer to
the lessee at the end of the contract, applies to transactions entered into
after June 30, 1999. As a result of FASB Interpretation No. 43, we changed, on a
prospective basis, how we account for transactions involving dark-fiber sales.
Rather than recognizing approximately $7,000,000 in revenues in the fourth
quarter from dark-fiber transactions pursuant to existing agreements entered
into after June 30, 1999, Touch America will recognize these earnings over the
applicable contract term. Net income for 1999 would have been approximately
$4,200,000 higher and both basic and diluted earnings per share would have been
$0.03 higher if we were not required to make this accounting change.
REGULATORY ASSETS AND LIABILITIES
For our regulated operations, we follow 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 to the customers.
Accordingly, we have recorded the following regulatory assets and liabilities
that will be recognized in expenses and revenues in future periods when the
matching revenues are collected.
<PAGE>
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------
Table The following table provides year-end balances of the major
classifications of regulatory assets and liabilities:
- -------------------------------------------------------------------------------------
December 31
----------------------------------------------
1999 1998
Assets Liabilities Assets Liabilities
----------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Income taxes ....................... $ 57,526 $119,080
Colstrip Unit 3
carrying charge ................. 38,494 40,325
Conservation
programs ........................ 28,378 33,353
Competitive
transition
charges (CTCs) .................. 53,768 56,059
Investment
tax credits ..................... $ 13,330 $ 33,819
Other .............................. 44,646 12,178 43,308 9,474
--------------------------------------------
Subtotal ...................... 222,812 25,508 292,125 43,293
Less:
Current portions ................ 11,788 3,402 16,197 5,057
--------------------------------------------
Total .............................. $211,024 $ 22,106 $275,928 $ 38,236
============================================
</TABLE>
- --------------------------------------------------------------------------------
Income taxes reflect the effects of temporary differences that we will
recover in future rates. In August 1985, the PSC issued an order allowing us to
recover deferred carrying charges and depreciation expenses over the remaining
life of Colstrip Unit 3. These recoveries compensated us for unrecovered costs
of our investment for the period from January 10, 1984, to August 29, 1985, when
we placed the plant in service. We were amortizing this asset to expense and
recovering in rates $1,831,000 per year. Conservation programs represent our
Demand Side Management programs, which are in rate base and which we were
amortizing to income over a 10-year period. We are recovering the CTCs, which
relate to natural gas properties that we removed from regulation on November 1,
1997, through rates over 15 years. Investment tax credits and account balances
included in "Other" represent items that we are amortizing currently or are
subject to future regulatory confirmation.
With the sale of the generating assets, it is our position that any of
these amounts related to electric supply should be recovered from sales proceeds
in excess of book value. For further information on the effects of the sale of
our electric generating assets, see Note 5, "Sale of Electric Generating
Assets." For further information on the removal in 1997 of our natural gas
production assets from rate base, see Note 4, "Deregulation and Regulatory
Matters."
CASH AND CASH EQUIVALENTS AND TEMPORARY INVESTMENTS
We consider all liquid investments with original maturities of three
months or less as cash equivalents, and investments with original maturities
over three months and up to one year as temporary investments. At December 31,
1999, all of our investments were available for sale, and their fair value
approximate the value reported on the Consolidated Balance Sheet.
ACCOUNTS RECEIVABLE
Accounts receivable are presented net of allowance for doubtful accounts
of $2,105,000 in 1999 and $1,906,000 in 1998.
STORM DAMAGE AND ENVIRONMENTAL REMEDIATION COSTS
When losses from costs of storm damage and environmental remediation
obligations for our utility operations are probable and reasonably estimable, we
charge these costs against established, approved operating reserves. We consider
the reserves adequate. The reserves balance at December 31, 1999, was
approximately $11,200,000, and at December 31, 1998, was approximately
$9,300,000. We have included these reserves in "current liabilities" on the
Consolidated Balance Sheet.
INCOME TAXES
We and our United States subsidiaries file a consolidated United States
income tax return. We allocate consolidated United States income taxes to
utility and nonutility operations as if we filed separate United States income
tax returns for each operation. We defer income taxes to provide for the
temporary differences between the financial reporting basis and the tax basis of
our assets and liabilities. For further information on income taxes, see
"Regulatory Assets and Liabilities" in this Note 1 and also Note 6, "Income Tax
Expense."
DEFERRED REVENUES
We defer revenues to account for the timing differences between cash
received and revenues earned and reflect these amounts on the Consolidated
Balance Sheet in "Deferred Revenue." We reflect the current portion of these
amounts in "Other Current Liabilities" on the Consolidated Balance Sheet. We are
recognizing the $257,000,000 prepayment received in January 1999 from a
telecommunications customer and the $106,000,000 payment received in December
1999 from the Los Angeles Department of Water and Power in revenues over the
original terms of the agreements, approximately 11 years in each case.
NET INCOME PER SHARE OF COMMON STOCK
We compute basic net income per share of common stock 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 would 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 our earnings.
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," we periodically
review long-lived assets for
<PAGE>
impairment whenever events or changes in circumstances indicate that we may not
recover the carrying amount of an asset.
. COMPREHENSIVE INCOME (Loss)
FASB defines comprehensive income as all changes to the equity of a
business enterprise during a period, except for those resulting from
transactions with owners. For example, dividend distributions are excepted.
Comprehensive income consists of 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, 1999, 1998, and 1997, our only item of
other comprehensive income was foreign currency translation adjustments of the
assets and liabilities of our foreign subsidiaries. These adjustments resulted
in increases to retained earnings of $3,058,000 in 1999, and decreases to
retained earnings of $7,363,000 in 1998 and $2,181,000 in 1997. No current
income tax effects resulted from the adjustments, nor will there be any net
income effects unless we sell a foreign subsidiary.
Most of the 1998 adjustment was the result of transferring a Canadian
natural gas production company from utility to nonutility operations. Until
November 1, 1997, the property, plant and equipment (PP&E) of that company was
included in our natural gas utility rate base at its original United States
dollar value. After that company was transferred to nonutility operations, we
were no longer required to state its PP&E at original United States dollar
value, but were required, instead, to convert its PP&E at the foreign exchange
rate in effect at the balance sheet date. At the time of the transfer, the
Canadian-United States exchange rate was considerably lower than the rates used
to convert most of the original United States dollar values of that company's
PP&E. Consequently, the adjustment from original to current United States dollar
value decreased other comprehensive income approximately $5,100,000 in 1998.
DERIVATIVE FINANCIAL INSTRUMENTS
. TRADING AND MARKETING OF ELECTRICITY
Although we decided in August 1998 to exit the electric trading and
marketing businesses, The Montana Power Trading & Marketing Company (MPT&M), a
subsidiary of Entech, remains a party to a single derivative financial
instrument. MPT&M entered into this instrument in June 1998 with an electric
retail customer to manage a portion of the customer's commodity price risk, and
the instrument expires in approximately fifteen months. We do not expect this
instrument to have a material effect on our consolidated financial position,
results of operations, or cash flows.
. TRADING AND MARKETING OF CRUDE OIL, NATURAL GAS, AND NATURAL GAS LIQUIDS
We produce, purchase, transport, and sell crude oil, natural gas, and
natural gas liquids. Changes in the prices of these commodities can affect our
financial results. We manage this exposure to price risk, in part, through
MPT&M's use of derivative financial instruments.
DERIVATIVE FINANCIAL INSTRUMENTS USED
We use derivative financial instruments to reduce earnings volatility and
stabilize cash flows by hedging some of the price risk associated with our
nonutility energy commodity-producing assets, contractual commitments for firm
supply, and natural gas transportation agreements. We also use derivative
financial instruments in speculative transactions to seek enhanced profitability
based on expected market movements, as discussed below in "Speculative
Transactions." In all cases, financial swap and option agreements constitute the
principal kinds of derivative financial instruments used for these purposes.
SWAP AGREEMENTS
Under a typical swap agreement, we make or receive payments based on the
difference between a specified fixed price and a variable price of crude oil or
natural gas at the time of settlement. The variable price is either a crude oil
or natural gas price quoted on the New York Mercantile Exchange or a natural gas
price quoted in Inside FERC's Gas Market Report or other recognized industry
index.
OPTION AGREEMENTS
Under a typical option agreement, we make or receive monthly payments
based on the difference between the actual price of crude oil or natural gas and
the price established in a private agreement at the time of execution. Receiving
or making payments is dependent on whether we buy (own or hold) or sell (write
or issue) the option. Buying options involves paying a premium - the price of
the option - and selling options involves receiving a premium. When we use
options, we defer all premiums paid or received and recognize the applicable
expenses or revenues monthly throughout the option term. As of December 31,
1999, our deferred revenues due to option premiums was $1,700,000.
HEDGED TRANSACTIONS
Hedged transactions are those in which we have a position (either current
or anticipated) in an underlying commodity or derivative of that commodity that
exposes us to risk if the price of the underlying item adversely changes. We
enter into these transactions primarily to reduce earnings volatility and
stabilize cash flows. We recognize gains or losses from these derivative
financial instruments in the Consolidated Statement of Income at the same time
that we recognize the revenues or expenses associated with the underlying hedged
item; until then, we do not reflect these gains or losses in our financial
<PAGE>
statements. At December 31, 1999, we had unrecognized gains of approximately
$2,100,000 related to these transactions. As of December 31, 1999, we had not
terminated any hedging instrument before the date of the anticipated commodity
production, commodity purchase or sale, or natural gas transportation
commitment.
At December 31, 1999, we had no hedge agreements on natural gas
production, but we did have swap and option agreements on approximately
1,280,000 barrels, or 46 percent of our estimated nonutility crude oil and
natural gas liquids production through December 2001. In addition, we had swap
and option agreements to hedge approximately 5.0 Bcf, or 20.1 percent of our
expected delivery obligations under long-term natural gas sales contracts
through December 2000. At December 31, 1999, we also had sold swap and option
agreements to hedge approximately 25.4 Bcf of our nonutility natural gas
pipeline transportation obligations under contracts through December 2001, and
we had purchased swap and option agreements to hedge approximately 27.4 Bcf of
these obligations.
SPECULATIVE TRANSACTIONS
We also enter into derivative financial transactions in which we have no
underlying price risk exposure nor any interest in making or taking delivery of
crude oil or natural gas commodities. We try, by these speculative transactions,
to profit from the market movements of the prices of these commodities. In
accordance with EITF Issue No. 98-10, "Accounting for Contracts Involved in
Energy Trading and Risk Management Activities," we mark to market all of our
speculative transactions and recognize any corresponding gain or loss in the
Consolidated Statement of Income. Through December 31, 1999, we recorded pretax
gains of approximately $700,000 related to these transactions.
COUNTERPARTY CREDIT RISK
Commodity price changes may provide a motive to our counterparties to
default on their delivery or payment obligations to us under our physical and
financial crude oil, natural gas, and natural gas liquids trading instruments.
Our corporate credit risk policy requires us to investigate and monitor the
creditworthiness of our physical and financial trading counterparties.
INDEPENDENT POWER OPERATIONS
CES has investments in independent power partnerships, some of which have
entered into derivative financial instruments to hedge interest rate exposure on
floating-rate debt and natural gas price fluctuations. We believe that, as of
December 31, 1999, we have not been exposed to any material adverse effects from
the risks inherent in these instruments.
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------
Table Fair Value of Financial Instruments
1999 1998
- -----------------------------------------------------------------------------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
- -----------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
ASSETS:
Investments in independent
power projects (cost basis only)................. $ 3,504 $ 1,641 $ 394 $ 1,543
Reclamation fund................................... 43,460 43,460 41,542 41,542
Other significant investments...................... 52,523 55,689 83,102 83,102
LIABILITIES:
Company obligated mandatorily
redeemable preferred securities.................. $ 65,000 $ 63,206 $ 65,000 $ 69,160
Long-term debt(including due
within one year)................................. 677,467 655,652 794,621 829,870
</TABLE>
- --------------------------------------------------------------------------------
The following methods and assumptions were used to estimate fair value:
. Investments in independent power projects - The fair value
represents our 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>
NOTE 2 - CONTINGENCIES
- ----------------------
KERR PROJECT
A FERC order that preceded our sale of the Kerr Project to PPL Montana
required us to implement a plan to mitigate the effect of Kerr Project
operations on fish, wildlife, and habitat. To implement this plan, we were
required to make payments of approximately $135,000,000 between 1985 and 2020,
the term during which we would have been the licensee. The net present value of
the total payments, assuming a 9.5 percent annual discount rate, was
approximately $57,000,000, an amount we recognized as license costs in plant and
long-term debt on the Consolidated Balance Sheet in 1997. A payment of
approximately $15,600,000 for the period from 1985 to 1997 was included in this
amount. In the sale of the Kerr Project, PPL Montana assumed the obligation to
make post-closing license compliance payments; however, we retained the
obligation to make payments regarding pre-closing license compliance payments.
In December 1998 and January 1999, we asked the United States Court of
Appeals for the District of Columbia Circuit to review FERC's orders and the
United States Department of Interior's conditions contained in them. On
September 17, 1999, the court granted the motion of the parties and intervenors
to hold up the appeal pending settlement efforts. In December 1999, we, along
with PPL Montana, the United States Department of the Interior, the Confederated
Salish and Kootenai Tribes (the Tribes), and Trout Unlimited, in a court-ordered
mediation, agreed in principle to settle this litigation.
A Statement of Agreement containing the principles for settlement of the
disputes underlying the appeals was developed in December 1999. It provides that
its terms are binding against all parties, with the understanding that the
signatory parties will jointly draft additional documents as necessary to
establish the terms of the settlement in detail. The parties are currently in
the process of drafting these documents, but the court's procedure requires that
the parties keep the settlement terms confidential. We have paid our settlement
payment under the Statement of Agreement into an escrow account. If the parties
agree on these additional documents, and if FERC approves, in a final
non-appealable order, the settlement terms as reflected in proposed license
amendments, we will dismiss the petitions in the court of appeals, and the
escrow agent will release the payments to the Tribes. In addition, we will
transfer to the Tribes 669 acres of land we own on the Flathead Indian
Reservation. If the parties cannot agree upon the additional documents or FERC
does not approve the proposed license amendments in the form agreed to by the
parties, or if, as a result of the appeal of a FERC order, that order is not
final after a specified period, the money will be returned to us, and the
litigation will resume. The settlement, subject to the conditions described
above, substantially reduces our obligation to pay for fish, wildlife, and
habitat mitigation assigned to the pre-closing period in the sale of the Kerr
Project.
MISCELLANEOUS
We are parties to various other legal claims, actions, and complaints
arising in the ordinary course of business. We do not expect the conclusion of
any of these matters to have a material adverse effect on our consolidated
financial position, results of operation, or cash flows.
<PAGE>
NOTE 3 - COMMITMENTS
- --------------------
PURCHASE COMMITMENTS
. ELECTRIC UTILITY
The Public Utilities Regulatory Policies Act (PURPA) requires a public
utility to purchase power from QFs at a rate equal to what it would pay to
generate or purchase power. These QFs are power production or co-generation
facilities that meet size, fuel use, ownership, and operating and efficiency
criteria specified by PURPA. The electric utility has 15 long-term QF contracts
with expiration terms ranging from 2003 through 2031 that require us to make
payments for capacity and energy received at prices currently above market.
Three contracts account for 96 percent of the 101 MWs of capacity provided by
these facilities. Montana's Electric Act designates the above-market portion of
the QF costs as Competitive Transition Costs (CTCs) and allows for their
recovery. For more information about CTCs, see Note 4, "Deregulation and
Regulatory Matters."
The Asset Purchase Agreement (Agreement) dated as of October 31, 1998, and
amended June 29, 1999 and October 29, 1999, with PPL Montana included the
assignment of our contract with Basin Electric Power Cooperative (Basin) to PPL
Montana. That contract committed us to purchase 98 MWs of seasonal capacity from
Basin from 1994 until November 2010 at prices above current and projected market
prices. However, Basin did not release us from that contract. Consequently, if
PPL Montana were to default, Basin could hold us liable to perform according to
the terms of the contract. Because we believe that PPL Montana will not default,
we do not consider this contract our unconditional purchase obligation.
The Agreement also included two Wholesale Transition Service Agreements
(WTSAs), effective December 17, 1999. These agreements enable us to fulfill our
obligation to supply power until July 2002 to those customers who will not have
chosen another supplier. One agreement commits us to purchase 200 MWs per hour
through December 2001, and the other agreement to purchase through June 2002 any
power requirements remaining after having received power through the first WTSA,
QFs, and Milltown Dam, which we still own and operate. Both agreements price the
power sold at a market index, with a monthly floor and an annual cap. Assuming a
7.23 percent discount rate and current load forecasts, the net present value of
the power purchased under the WTSAs may range from $94,000,000 to $104,000,000
for 2000, $61,000,000 to $69,000,000 for 2001, and $24,000,000 to $27,000,000
for 2002. In accordance with SFAS No. 47, "Disclosure of Long-Term Obligations,"
we use the lower estimate in the tables below.
. NATURAL GAS UTILITY
The natural gas utility entered into take-or-pay contracts with Montana
natural gas producers to provide adequate supplies of natural gas for our
utility customers. We currently have six of these contracts, with expirations
between 2000 and 2006. If we can supply customers with less expensive natural
gas, we purchase the minimum required by the take-or-pay contracts. The cost of
purchases through take-or-pay contracts is part of those costs submitted to the
PSC for recovery in future rates. Since 1998, the natural gas utility enters
only into one-year take-or-pay contracts, because of the uncertainty about the
number and timing of customers who will choose another natural gas supplier
under Montana's Natural Gas Act.
. TRADING AND MARKETING
Before the sale of our electric generating facilities, MPT&M supplied its
customers with power purchased mainly from our generation facilities.
Anticipating the sale of those facilities, MPT&M entered into two electric
purchase contracts in August 1998. One contract obligates MPT&M to purchase 40
MWs per hour at a fixed rate from October 1999 through May 2001, and the other
to purchase 100 MWs per hour of firm capacity and firm energy at 100 percent
load factor at a market-indexed rate until August 2001. We sell this power to
several large customers with whom we have contracts to supply power at
negotiated rates.
. OIL AND GAS
Nonutility oil and natural gas operations have one take-or-pay contract,
expiring in 2006, to purchase natural gas, and contracts with pipeline
companies, with expiration dates between 2000 and 2013, to provide reserve
capacity for natural gas shipments to customers.
<PAGE>
- --------------------------------------------------------------------------------
Table Total payments under these contracts for the prior three years were as
follows:
- --------------------------------------------------------------------------------
Utility Nonutility Total
-------------------------------------------------------
Electric Natural Gas Electric Natural Gas
-------------------------------------------------------
(Thousands of Dollars)
1999 ............ $61,274 $ 4,069 $26,076 $ 7,898 $99,317
1998 ............ 50,611 3,508 15,355 4,454 73,928
1997 ............ 44,153 7,554 -- 3,289 54,996
- --------------------------------------------------------------------------------
Table Under the above agreements, the present value of future minimum
payments, at a discount rate of 7.23 percent, is as follows:
- --------------------------------------------------------------------------------
Utility Nonutility Total
-------------------------------------------------------
Electric Natural Gas Electric Natural Gas
-------------------------------------------------------
(Thousands of Dollars)
2000 ........ $102,050 $ 4,023 $24,315 $ 7,647 $138,035
2001 ........ 69,752 2,312 10,743 4,661 87,468
2002 ........ 32,052 1,945 -- 2,200 36,197
2003 ........ 7,543 317 -- 2,051 9,911
2004 ........ 7,317 280 -- 1,912 9,509
Remainder ... 106,074 502 -- 17,594 124,170
-------------------------------------------------------
$324,788 $ 9,379 $35,058 $ 36,065 $405,290
=======================================================
- --------------------------------------------------------------------------------
. COAL
Northwestern Resources entered into a lignite lease agreement that
requires minimum annual payments of overriding royalty that began in 1991 for
$1,125,000, adjusted quarterly for inflation. The payments will continue until
Northwestern Resources pays the equivalent of $18,750,000, in 1986 dollars. At
December 31, 1999, the remaining payments under this agreement were $7,217,000.
Under current mine plans, Northwestern Resources should recoup these payments
through lignite sales.
Northwestern Resources also agreed to pay the State of Texas $2,250,000 in
May 2000 for a highway relocation that enables it to gain access to lignite
under existing leases.
. TELECOMMUNICATIONS
Construction Projects
In 1999 and 1998, Touch America contracted with Northern Telecom, Inc.
(Nortel) to install optical electronic equipment on certain fiber-optic
networks. (That equipment transmits pulses of laser light through the fiber to
increase the rate at which data are transmitted.) We expect the installations to
be completed in the fourth quarter of 2000 at a cost of $51,800,000, of which
$28,300,000 was paid in 1999 and 1998 in the aggregate, and $23,500,000 is
scheduled for payment in 2000. In 1999, Touch America also contracted with
Nortel to upgrade a telephone switch in the first quarter of 2000 at a cost of
$3,000,000. TW Wireless (TWW), a joint venture of Touch America and US WEST
Wireless, will lease the switch from Touch America for the life of the venture.
In October 1999, Touch America entered into a contract to construct a
high-speed, fiber-optic network for AT&T Corp (AT&T). The contract allows Touch
America to install its own fiber-optic network at the same time and along the
same routes it is constructing the network for AT&T. The network will span more
than 4,300 miles and will cover six different routes in the West, Pacific
Northwest, Northern Rocky Mountains, and Midwest. The contract contains capped
performance incentives if we meet, and capped penalties if we do not meet,
aggressive completion targets. The first route is scheduled for completion in
the fourth quarter of 2000 and the last route in the second quarter of 2001. We
estimate the cost of the project at $500,000,000, of which approximately
one-half will be expended in 2000. We expect AT&T and other third parties to
reimburse us for approximately 50 percent of the total cost, as stages of the
project are completed.
Joint Ventures
Touch America has entered into strategic alliances to expand its network
and increase its revenues. In accordance with the
<PAGE>
agreements governing these relationships, Touch America is committed to
contribute capital at various times.
In January 2000, Touch America and AEP Communications LLC, a subsidiary of
American Electric Power, formed a 50-50 joint venture named America Fiber Touch,
LLC (AFT) to connect national and regional fiber-optic networks. The venture's
first project is to construct a 330-mile fiber-optic route between St. Louis,
Missouri, and Plano, Illinois, which makes up the Midwest route of the 4,300
mile build-out discussed above. This Midwest route is scheduled for completion
in December 2000, at an estimated cost of $25,000,000, of which Touch America's
portion is $12,500,000.
In August 1999, Touch America and New Century Energies (NCE) formed a
50-50 joint venture named Northern Colorado Telecommunications LLC to provide a
full range of telecommunication services, including private-line service, to
enterprises in the Denver metropolitan area by the middle of 2000. For the
venture, NCE contributed long-term indefeasible rights of use of its existing
fiber-optic network in the Denver metropolitan area. Touch America will
construct six miles of fiber-optic cable and install optical electronic
equipment at an estimated cost of $10,000,000. In 1999, Touch America
contributed $1,500,000 to the venture and plans to contribute $7,000,000 in 2000
and $1,500,000 in 2001.
In 1999, Touch America and Iowa Network Services, Inc. formed Iowa
Telecommunications Services, Inc. (ITS). ITS will purchase from a third party
280,422 domestic access lines connected to 296 telephone exchanges in Iowa.
Touch America holds a 31 percent interest in ITS, in which Touch America will
invest approximately $46,000,000. ITS will fund the purchase of access lines and
telephone exchanges primarily through long-term non-recourse debt, obligating
ITS solely. We expect this transaction to close in the second quarter of 2000,
subject to the satisfaction of various conditions and receipt of required
regulatory approvals. In 1999, Touch America loaned ITS $5,000,000 to purchase
computers and licenses, and will loan ITS another $5,000,000 for operations at
payments scheduled for the first four months of 2000. These notes are payable on
demand.
In August 1999, Touch America and US WEST Wireless entered into TWW to
provide "one number" wireless telephone service in an eight-state region of the
Pacific Northwest and Upper Midwest. That service provides a customer with one
directory number for cell phone and home or business phone. Touch America holds
approximately a 50 percent interest in the venture and will contribute
approximately $45,000,000 over the next two years toward construction of TWW's
physical infrastructure. Both companies contributed PCS licenses to the venture.
In November 1999, FTV Communications LLC (FTV), the limited liability
company formed by Touch America, Williams Communications, and Enron Broadband
Services, began an expansion of regeneration sites along the Portland-to-Las
Vegas portion of the fiber-optic route that FTV constructed. FTV expects to
complete the project in mid-2000. Touch America's share of the costs will be
approximately $3,300,000.
Exchanges
In January 2000, Touch America and PF.Net, a privately held
telecommunications company, agreed to an exchange of fiber, conduit, and cash to
expand both companies' fiber-optic networks. Touch America receives
approximately 5,900 route miles of fiber and conduit from PF.Net, in exchange
for 4,400 miles of Touch America's fiber and conduit and a cash payment of
$48,500,000 for the difference in route miles. This exchange will expand Touch
America's network from Los Angeles to San Diego, Phoenix, El Paso, Dallas,
Austin, San Antonio, Houston, New Orleans, Jacksonville, Orlando, Greensboro,
Washington D.C., New York City, Tulsa, Kansas City, and St. Louis. Touch America
paid $4,850,000 down and will pay the remainder as segments of the routes under
construction are completed. Segments are scheduled for completion at various
times in 2000 and 2001.
Investments and Acquisitions
In January 2000, Touch America agreed to purchase, from Century Tel Inc.,
400 route miles of fiber-optic network linking Chicago and Detroit through
central and southern Michigan communities for approximately $10,000,000.
In January 2000, Touch America signed a purchase agreement with Minnesota
PCS, LP (MPCS) to acquire a 25 percent interest in MPCS' wireless telephone
business, which owns PCS licenses in North Dakota, South Dakota, Minnesota, and
Wisconsin. In accordance with the agreement, Touch America expects to make a
$2,700,000 equity payment to MPCS and, over the years 2000-2001, will loan it
$12,000,000 in interest-bearing notes payable on October 1, 2002. The agreement
also obligates Touch America, until 2007, to $7,000,000 in guarantees for loans
made to MPCS by the Rural Telephone Financing Corporation. The guarantees are
callable only upon MPCS' default.
On March 13, 2000, Touch America signed an agreement with Qwest to acquire
for approximately $190,000,000, subject to certain adjustments, Qwest's
wholesale, private-line and long-distance telecommunications services in US
WEST's 14-state region, which covers 250,000 customers for voice, data, and
video services with multimedia and high-speed data applications. By this
agreement, Touch America will also acquire a fiber-optic network of 1,800 route
miles and associated optronics and switches. The network will connect to Touch
America's fiber-optic network, and Touch America will offer employment to
Qwest's sales agents in the region. We expect this acquisition to close in
mid-2000, subject to the satisfaction of various conditions and the receipt of
required regulatory approvals.
<PAGE>
SALES COMMITMENTS
Our nonutility oil and natural gas operations have agreed to supply
approximately 81 Bcf of natural gas to four co-generation facilities. These
contracts have expiration dates between 2005 and 2011. We can supply the
remaining natural gas required by these contracts with sufficient proved,
developed, and undeveloped reserves and by our control of commitments to sell
our production.
We entered into a contract to sell electricity to an industrial customer
at terms that include a fixed price for a portion of the power delivered and an
index-based price for another portion. Approximately three years from now, the
contract provides that we sell all power to our customer at an index-based
price. We have been supplying our customer with power purchased through an
index-based contract between MPT&M and a power generator that remains effective
through July 2001. Our industrial customer has given us usage estimates that do
not exceed the amount of electricity that we are committed to purchase.
Because the price of power under the index-based purchase contract could
exceed the price of power under the fixed-price portion of our sales contract,
we are subject to commodity price risk. Due to uncertainties relating to the
supply requirements of the sales contract and uncertainties surrounding various
arrangements that would allow us to serve the contractual demand, we are unable
to determine the effects that this contract ultimately may have on our
consolidated financial position, results of operations, or cash flows. We will
continue to examine our options and take steps to mitigate the commodity price
risk that we face because of our fixed-price sales contract.
MPT&M has agreements, expiring between December 2000 and December 2002,
with four other industrial customers to sell a maximum of approximately 103.8
MWs and a minimum of 59.3 MWs per hour. MPT&M can supply these customers from
power purchased through contracts with a power generator discussed above under
"Purchase Commitments."
LEASE COMMITMENTS
On December 30, 1985, we sold our 30 percent share of Colstrip Unit 4 and
agreed to lease back our share under a net, 25-year lease with annual payments
of approximately $32,000,000. We have been accounting for this transaction as an
operating lease. We did not sell this nonutility leasehold interest and its
related assets and liabilities and contract obligations to PPL Montana. We have
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
$66,000,000 for 1999, $63,000,000 for 1998, and $60,000,000 for 1997.
We have restated the previously reported 1998 and 1997 rental expenses of
$58,800,000 and $56,600,000 for the inclusion of property taxes paid in
accordance with our Colstrip Unit 4 Sale Lease-Back Agreement.
NOTE 4 - DEREGULATION AND REGULATORY MATTERS
- --------------------------------------------
DEREGULATION
The electric and natural gas utility businesses in Montana are
transitioning to a competitive market in which commodity energy products and
related services are sold directly to wholesale and retail customers. Montana's
Electric Act, passed in 1997, provides that all customers will be able to choose
their electric supplier by July 1, 2002. Montana's Natural Gas Act, also passed
in 1997, provides that a utility may voluntarily offer its customers choice of
natural gas suppliers and provide open access. Since restructuring is voluntary,
no deadline for choice exists.
. ELECTRIC
Through December 1999, approximately 900 electric customers representing
more than 1,300 accounts crossing all customer classifications - or
approximately 27 percent of our pre-choice electric load - have moved to
competitive supply since the inception of customer choice on July 1, 1998.
Residential customers were eligible to move to choice during the fourth quarter
of 1999. However, the majority of the load associated with our pre-choice
electric customers who moved to other suppliers was predominantly industrial and
large commercial customers.
As required by the Electric Act, we filed a comprehensive transition plan
with the PSC in July 1997. Initial hearings on the filing began in April 1998,
and the issues were separated into two groups: Tier I and Tier II.
Tier I issues dealt with:
. Accounting orders;
. Customer choice for large industrial customers;
. Pilot programs for the remaining customers; and
. Standards of conduct for utility and nonutility affiliates.
Tier II issues address:
. The recovery and treatment of the QF purchase-power contract
costs, which are above-market costs;
. Regulatory assets associated with our electric generating
business; and
. A review of our electric generating assets sale, including the
treatment of sale proceeds in excess of the book value of the
assets and other generation-related transition costs.
In June 1998, the PSC rendered an order on Tier I issues, and on July 1,
1999, we filed a case with the PSC to resolve
<PAGE>
Tier II issues. We will update our Tier II filing as a result of the closing of
the sale of our electric generating assets, but we do not expect an order from
the PSC until late 2000.
With deregulation and the resulting competition, certain generation and
power supply-related costs become stranded, or unrecoverable, absent recovery
from customers as a transition cost. CTCs are generation and power
supply-related costs that we incurred in the regulated environment with the
expectation that we would recover these costs from our customers well into the
future. Included within the CTCs are the following: (1) generation-related
regulatory assets, (2) utility owned generation and other purchase-power
contracts, and (3) our purchase-power contracts with the QFs. We are evaluating
options with respect to the QF contracts to minimize costs and are working on a
number of potential buy-out agreements. The owners of the QF contracts must
approve any agreements related to the contracts. In addition, the PSC must
approve future cost recovery. The Electric Act allows us to issue transition
bonds to refinance CTCs.
In the implementation of our comprehensive transition plan, we have
initiated litigation in Montana District Court in Butte seeking reversal of a
PSC decision regarding our ability to use tracking mechanisms to ensure fair and
accurate recovery of above-market QF costs and certain other transition costs.
In an order issued as part of its consideration of our transition plan, the PSC
concluded that the Electric Act does not provide for tracking mechanisms and
that transition costs must be mitigated and determined as a final matter in the
transition filing. In the litigation, we also are seeking court clarification on
whether the Electric Act authorized a rate freeze or a rate cap during the
transition period that ends July 1, 2002. The PSC has concluded that the
Electric Act authorized a rate cap, but we disagree with this interpretation.
. NATURAL GAS
Through December 1999, approximately 240 natural gas customers with annual
consumption of 5,000 Dkt or more - or 52 percent of our pre-choice natural gas
supply load - have chosen alternate suppliers since the transition to a
competitive natural gas environment began in 1991.
In accordance with a 1997 PSC order, we transferred substantially all of
our natural gas utility's production assets to unregulated affiliates in 1997 at
an agreed-upon amount, which was approximately $33,600,000 lower than the book
value of the assets. As a component of CTCs, the PSC is allowing us to recover
from our transportation and distribution customers (a) this $33,600,000
difference between transfer value and book value, and (b) approximately
$25,400,000 of existing regulatory assets related to the natural gas production
assets. In 1998, we issued $62,700,000 in transition bonds to refinance the CTCs
for the benefit of customers. The transition bonds will be retired over 15 years
through rate revenues established in accordance with Montana's Natural Gas Act.
The amortization of the assets is proportionate to the repayment of principal on
the bonds, resulting in no net income statement impact. The transition plan also
includes a fixed-price supply contract until July 1, 2002 between our
unregulated gas supply operations and our regulated distribution operations to
serve the remaining customers who have not chosen other suppliers.
REGULATORY MATTERS
Milltown Dam and our electric transmission operations remain subject to
FERC and PSC regulation, and the PSC regulates our electric distribution
operations.
As a Hinshaw pipeline (interstate pipeline exempt from FERC jurisdiction),
our natural gas transportation pipelines are not subject to FERC jurisdiction.
However, we conduct interstate transportation subject to FERC jurisdiction,
through an exception of our Hinshaw status. Presently, FERC has allowed the PSC
to set the rates for this interstate service. Our natural gas distribution and
storage operations remain subject to PSC regulation. In addition, the Alberta
Energy and Utilities Board, the National Energy Board of Canada, and the United
States Department of Energy all must approve the importing of Canadian natural
gas.
As a public utility, we also are subject to PSC jurisdiction when we
issue, assume, or guarantee securities, or when we create liens on our
properties.
. ELECTRIC
FERC
On March 30, 1998, we filed a request with FERC to increase our
open-access transmission rates and the rates for bundled wholesale electric
service to two rural electric cooperatives. FERC approved an interim increase in
rates charged for transmission service, pending final approval in 2000.
In January 1999, we reached a rate settlement with one of the
cooperatives, resulting in an immaterial increase in rates for bundled wholesale
electric service. This cooperative moved to another supplier in December 1999.
In March 1999, we reached a separate settlement with the other
cooperative. Rates did not change as a result of the settlement. The cooperative
was able to retain its right to continue with its separate rate-reduction
complaint. We agreed to assist the cooperative in moving to choice when its
full-service wholesale contract expires in exchange for its agreement to
withdraw the rate-reduction complaint. This cooperative will move to another
supplier in June 2000.
Finally, on March 11, 1999, we reached a settlement on open-access
transmission rates. This settlement increased transmission rates by
approximately $4,300,000, which had a positive effect on the results of our
transmission operations.
<PAGE>
We will also pursue, through new FERC proceedings, recovery of the
transition costs associated with serving both of the wholesale electric
cooperatives to correspond with our transition-costs recovery proceedings in
Montana.
PSC
The Electric Act established a rate freeze for all electric customers,
meaning that transmission and distribution rates cannot be increased until July
1, 2000. In January 2000, we filed a voluntary rate reduction with the PSC for
approximately $16,700,000 annually, which we would implement by using the sales
proceeds in excess of the book value from the recent generation sale. The
reduction is effective on an interim basis pending PSC review of our Tier II
filing. For additional information on the generation sale, see Note 5, "Sale of
Electric Generating Assets."
. NATURAL GAS
On August 12, 1999, we filed a natural gas rate docket with the PSC
requesting, among other matters, an increase in annual revenues of $15,400,000,
with a proposed interim increase of $11,500,000. The filing also proposes:
. An alternative rate plan;
. "Trackers" to reflect property taxes and replacement facilities in
rates on a more timely basis;
. A change in the allocation of costs to customer classes; and
. Rate-design changes that include recovery of distribution charges
through a fixed monthly system charge.
On December 9, 1999, the PSC approved an interim increase of $7,600,000
regarding the natural gas rate docket discussed above. Since then, we negotiated
a settlement with a group of intervenors concerning this natural gas rate
filing. The settlement allows for an increase of annual revenues of $10,300,000,
which includes the interim increase of $7,600,000. The PSC will discuss the
settlement at a working session in March 2000. If the settlement is acceptable,
the rates will be implemented shortly thereafter.
On November 17, 1999, we filed a second natural gas rate docket with the
PSC requesting recovery of costs associated with tracking gas costs annually.
Approval by the PSC would result in an increase in annual revenues of
$4,800,000. On December 9, 1999, the PSC approved an interim increase for this
amount until we receive the final order, which we expect by mid-2000.
NOTE 5 - SALE OF ELECTRIC GENERATING ASSETS
ASSETS SOLD
On December 17, 1999, in accordance with the Agreement, we sold to PPL
Montana substantially all of our electric generating assets, related contracts,
and associated transmission assets totaling less than 40 miles. This included 11
of our 12 hydroelectric facilities; a storage reservoir; a coal-fired thermal
generating plant at Billings, Montana; all of our interest in three coal-fired
thermal generating plants at Colstrip, Montana; and other related assets,
including inventories associated with the power plants. The total gross capacity
of the hydroelectric facilities and coal-fired thermal generating plants sold to
PPL Montana was 1,314.5 MWs.
The asset sale did not include the Milltown Dam near Missoula, Montana
(gross capacity of 3 MWs) or any of our QF purchase-power contracts. It also did
not include our leased share of the Colstrip Unit 4 generation or transmission
assets.
In the sale of these assets, we generally retained all pre-closing
obligations, and PPL Montana assumed all post-closing obligations. However, with
respect to environmental liabilities, PPL Montana assumed all pre-closing
(subject to the indemnification provisions discussed below) and post-closing
environmental liabilities associated with the purchased assets, with three
exceptions for pre-closing liabilities:
. 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; and
. Remediation costs of any silts behind the Thompson Falls Dam related
to pre-closing activity.
We agreed to indemnify PPL Montana from losses arising from pre-closing
environmental conditions. The indemnity for required remediation of pre-closing
conditions, whether known or unknown at the closing, is limited to:
. 50 percent of the loss. (Our share of this indemnity obligation at
the Colstrip Project is limited to our pro-rata share of this 50
percent based on our pre-sale ownership share.)
. A two-year period after closing for unknown conditions. The
indemnity for required remediation of pre-closing conditions known
at the time of the closing continues indefinitely.
. An aggregate amount no greater than 10 percent of the purchase price
paid for the assets.
<PAGE>
We do not expect this indemnity obligation to have a material adverse
effect on our consolidated financial position, results of operations, or cash
flows. We have accrued the estimated amount of the potential liability
associated with these retained obligations.
CASH PROCEEDS
The cash proceeds received for the sale of the assets, including pro-rated
adjustments for such items as property taxes, was approximately $758,600,000
(including approximately $1,000,000 received in 2000.) Our transaction costs to
complete the sale amounted to approximately $12,100,000.
At December 31, 1999, we recorded approximately $219,700,000 as net
proceeds in excess of the book value, based on net cash proceeds of $746,500,000
less (1) approximately $497,300,000 book value of the assets sold and (2)
approximately $29,500,000 of previously flowed-through tax benefits. We also
recorded an income tax liability of approximately $164,100,000, based on the net
proceeds less the tax basis of the assets sold.
As part of our Tier II filing, we plan to deduct from the regulatory
liabilities approximately $39,300,000 of other generation-related transition
costs and approximately $64,600,000 of regulatory asset transition costs. The
other generation-related transition costs consist mainly of SG&A costs and costs
to retire debt. The regulatory asset transition costs consist mainly of
capitalized conservation costs and carrying charges associated with Colstrip
Unit 3.
PPL Montana also agreed to purchase 1,058 MWs of additional gross capacity
in Colstrip, Montana from Puget and Portland General. Pursuant to the terms of
the Agreement with PPL Montana, we would receive an additional $152,000,000 from
PPL Montana, for added value, if Puget and Portland General both close their
transactions. The added value would arise from the controlling interest in the
Colstrip Units that PPL Montana would hold, as a result of the combination of
our former assets with those of Puget and Portland General. However, if only
Puget or Portland General - but not both - closes its respective transaction, we
will receive only $117,000,000 from PPL Montana rather than $152,000,000. If
neither Puget or Portland General closes its transaction, the Agreement provides
that, subject to the receipt of required regulatory approvals, PPL Montana will
purchase the portion of our 500-kilovolt Colstrip transmission system not
associated with Colstrip Unit 4. Our sales proceeds from PPL Montana for these
properties would be $97,100,000.
During February 2000, the Oregon Public Utility Commission indicated that
it would deny Portland General's request to sell its ownership interest in
Colstrip Units 3 and 4 to PPL Montana.
EFFECT ON 1999 EARNINGS
The asset sale positively affected our electric utility's 1999 earnings
through the reversal of approximately $3,000,000 (after taxes) in interest
expense recorded in prior years relating to Kerr Project liabilities and through
recognition of approximately $10,000,000 in ITCs.
USE OF PROCEEDS
We have used a portion of the net cash proceeds received (less the sale
proceeds in excess of the book value) for the following general corporate
purposes:
. Funding utility and nonutility projects, including those involving
expansion of Touch America;
. Reducing debt; and
. Purchasing shares of our common stock.
For additional information on the purchase of shares of common stock and
the reduction of debt, see Note 7, "Common Stock," and Note 10, "Long-Term
Debt."
<PAGE>
NOTE 6 - Income tax expense
- ---------------------------
- --------------------------------------------------------------------------------
Table Income before income taxes was as follows:
- --------------------------------------------------------------------------------
1999 1998 1997
---------------------------------------------
(Thousands of Dollars)
United States ............. $ 189,186 $ 246,242 $ 177,114
Canada .................... 3,871 (2,927) 12,780
Other countries ........... 1,352 479 608
---------------------------------------------
$ 194,409 $ 243,794 $ 190,502
=============================================
- --------------------------------------------------------------------------------
Table The provision for income taxes differs from the amount of income tax
that would result by applying the applicable United States statutory
federal income tax rate to pretax income because of the following
differences:
- --------------------------------------------------------------------------------
1999 1998 1997
---------------------------------------------
(Thousands of Dollars)
Computed "expected"
income tax
expense ................ $ 68,043 $ 85,328 $ 66,675
Adjustments for
tax effects of:
Statutory
depletion .......... (3,440) (4,156) (2,891)
Tax credits .......... (25,775) (4,722) (11,645)
State income tax,
net ................ 4,545 7,393 7,147
Reversal of
utility book/tax
depreciation ....... 5,318 2,784 5,636
Other ................ (4,628) (8,453) (3,052)
---------------------------------------------
Actual income
tax expense ............ $ 44,063 $ 78,174 $ 61,870
=============================================
- --------------------------------------------------------------------------------
Table Income tax expense as shown on the Consolidated Statement of Income
consists of the following components:
- --------------------------------------------------------------------------------
1999 1998 1997
---------------------------------------------
(Thousands of Dollars)
Current:
United States .......... $ 293,319 $ 88,233 $ 36,680
Canada ................. 1,710 1,212 994
Other countries ........ 30 -- 3,684
State .................. 53,858 13,462 9,835
---------------------------------------------
348,917 102,907 51,193
---------------------------------------------
Deferred:
United States .......... (267,958) (20,331) 6,491
Canada ................. 9,930 (1,851) 2,802
State .................. (46,826) (2,551) 1,384
---------------------------------------------
(304,854) (24,733) 10,677
---------------------------------------------
$ 44,063 $ 78,174 $ 61,870
=============================================
- --------------------------------------------------------------------------------
Table Deferred tax liabilities (assets) are comprised of the following:
- --------------------------------------------------------------------------------
December 31
----------------------------
1999 1998
----------------------------
(Thousands of Dollars)
Plant related .............................. $ 321,383 $ 403,832
Investment in nonutility
generation projects ..................... 6,171 7,132
Other ...................................... 44,520 35,344
----------------------------
Gross deferred
tax liabilities ....................... 372,074 446,308
----------------------------
Coal reclamation ........................... (48,096) (47,487)
Amortization of gain on
sale/leaseback .......................... (11,649) (12,755)
Deferred revenues .......................... (103,578) --
Investment tax credit
amortization ............................ (14,055) (21,833)
Other ...................................... (204,152) (59,082)
----------------------------
Gross deferred tax assets ............... (381,530) (141,157)
----------------------------
Net deferred tax (assets)
liabilities ........................... (9,456) 305,151
Less current deferred
tax assets - net ...................... (18,303) (18,755)
----------------------------
Total noncurrent deferred
tax liabilities ......................... $ 8,847 $ 323,906
============================
- --------------------------------------------------------------------------------
Table The change in net deferred tax liabilities differs from current year
deferred tax expense as a result of the following:
- --------------------------------------------------------------------------------
December 31
-------------
(Thousands of
Dollars)
Change in noncurrent deferred tax ........................... $(315,059)
Regulatory assets related to income taxes ................... 61,182
Current deferred tax assets - net ........................... 452
Amortization of investment tax credits ...................... (21,732)
Other ....................................................... (29,697)
---------
Deferred tax expense ................................... $(304,854)
=========
- --------------------------------------------------------------------------------
<PAGE>
NOTE 7 - COMMON STOCK
- ---------------------
STOCK SPLIT
On June 22, 1999, the Board of Directors approved a two-for-one split of
our outstanding common stock. As a result of the split, which was effective
August 6, 1999, for all shareholders of record on July 16, 1999, 55,099,015
outstanding shares of common stock were converted to 110,198,030 outstanding
shares of common stock. We have retroactively applied the split to all periods
presented.
SHARE REPURCHASE PROGRAM
In 1998, the Board of Directors authorized a share-repurchase program over
the next five years to repurchase up to 20,000,000 shares, (approximately 18
percent of our then outstanding common stock) on the open market or in privately
negotiated transactions. As of December 31, 1999, we had 105,536,873 common
shares outstanding. 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.
As a result of this authorization, we entered into a Forward Equity
Acquisition Transaction (FEAT) program with a bank that committed to purchase on
our behalf up to 5,000,000 shares, but not to exceed $125,000,000. On November
12, 1999, we amended the FEAT program to increase the monetary limit to
$200,000,000. The expiration date of the program is October 31, 2000. Until that
date, when all transactions must be settled, we can elect to fully or partially
settle either on a full physical (cash) or a net share basis. A full physical
settlement would be the purchase of shares from the bank for cash at the bank's
average purchase price, including interest costs less dividends. A net share
settlement would be the exchange of shares between the parties so that the bank
receives shares with value equivalent to its original purchase price, including
interest costs less dividends. Only at the time that the transactions are
settled can our capital or outstanding stock be affected, and settlement has no
effect on results of operations.
Since the FEAT program began and through December 23, 1999, the bank had
acquired for us 4,682,100 shares of our stock. The purchase of these shares
averaged approximately $30.94 per share and ranged from $27.05 per share to
$33.52 per share for a total cost of $144,872,000. On December 23, 1999, we used
proceeds from the sale of our generation assets to effect a full physical
settlement for that amount. We have reflected the shares purchased as treasury
stock on the Consolidated Balance Sheet. As of December 31, 1999, no additional
shares had been acquired under the program.
SHAREHOLDER PROTECTION RIGHTS PLAN
We have a Shareholder Protection Rights Plan (SPRP) that provides one
preferred share purchase right on each outstanding common share. Each purchase
right entitles the registered holder, upon the occurrence of certain events, to
purchase from us one one-hundredth of a share of Participating Preferred Shares,
A Series, without par value. If it should become exercisable, each purchase
right would have economic terms similar to one share of common stock. The
purchase rights trade with the underlying shares and will, except under certain
circumstances described in the SPRP, expire on June 6, 2009, unless redeemed
earlier or exchanged by us.
DIVIDEND REINVESTMENT AND STOCK PURCHASE PLAN
Our 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; and (b) deposit common and preferred stock certificates into
their Plan accounts for safekeeping. It also 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.
RETIREMENT SAVINGS PLAN
We have a Retirement Savings Plan that covers all regular eligible
employees. We contribute, on behalf of the employee, a matching percentage of
the amount contributed to the Plan by the employee. In 1990, we 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 used the proceeds to purchase 3,844,594 shares of our
common stock. Shares acquired with loan proceeds are allocated to Plan
participants. The loan, which is reflected as long-term debt, is offset by a
similar amount in common shareholders' equity as unallocated stock. Our
contributions plus the dividends on the shares held under the Plan are used to
meet principal and interest payments on the loan with the Plan Trustee. As
principal payments on the loan are made, long-term debt and the offset in common
shareholders' equity are both reduced. At December 31, 1999, 2,500,678 shares
had been allocated to the participants' accounts. We recognize expense for the
Plan using the Shares Allocated Method, and the pretax expense was $4,890,000,
$4,923,000, and $5,194,000 for 1999, 1998, and 1997, respectively.
LONG-TERM INCENTIVE PLAN
Under the Long-Term Incentive Plan, we have issued options to our
employees. Options issued to employees are not reflected in balance sheet
accounts until exercised, at which time:
(1) authorized, but unissued shares are issued to the employee,
(2) the capital stock account is credited with the proceeds, and
(3) no charges or credits to income are made.
Options were granted at the average of the high and low
<PAGE>
prices as reported on the New York Stock Exchange composite tape on the date
granted and expire ten years from that date.
On December 31, 1999, restrictions were removed on the remaining shares of
restricted stock issued in 1994 under the Long-Term Incentive Plan. During 1999,
a grant of 12,000 shares of restricted stock was issued to an individual. The
award is subject to forfeiture or proration if the individual should terminate
employment. Earned awards are reflected as common stock on the Consolidated
Balance Sheet and as compensation expense in the Consolidated Statement of
Income over the period of required employment. At December 31, 1999, 12,000
shares of restricted stock remained.
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
Table Option activity is summarized below:
- -------------------------------------------------------------------------------------------------------------------
1999 1998 1997
---------------------------------------------------------------------------
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 ... 2,548,094 $22.71 1,081,330 $11.00 1,389,608 $10.95
Granted ..................... 919,510 32.14 2,234,658 24.50 -- --
Exercised ................... 88,857 10.83 702,562 11.25 251,506 10.73
Cancelled ................... 98,422 24.08 65,332 13.47 56,772 11.01
---------------------------------------------------------------------------
Outstanding, end of year ......... 3,280,325 $25.63 2,548,094 $22.71 1,081,330 $11.00
===========================================================================
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------
Table Shares under option at December 31, 1999, are summarized below:
- ------------------------------------------------------------------------------------------------------
Options Outstanding Options Exercisable
------------------------------------- ---------------------
Wtd Avg Wtd Avg Wtd Avg
Exercise Exercise Exercise
Exercise Price Range Shares Price Life Shares Price
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
$10.81 to $11.31 .................. 271,779 $11.06 5 yrs 271,779 $11.06
$18.00 to $19.17 .................. 488,000 18.56 8 yrs 12,000 18.00
$26.53 to $27.56 .................. 1,981,814 26.73 9 yrs -- --
$35.36 ............................ 538,732 35.36 10 yrs -- --
--------- -------
3,280,325 283,779
========= =======
- ------------------------------------------------------------------------------------------------------
</TABLE>
As permitted by SFAS No. 123, "Accounting for Stock-Based Compensation,"
we have elected to follow Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees" (APB 25) and related interpretations
in accounting for our employee stock options. Under APB 25, because the exercise
price of the 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 we had accounted for
our employee stock options under the fair value method of that statement. The
weighted-average fair value of options granted in 1999 and 1998 was $7.03 and
$7.12 per share, respectively. We employed the binomial option-pricing model to
estimate the fair value of each option grant on the date of grant. We used the
following weighted-average assumptions for grants in 1999 and 1998,
respectively: (1) risk-free interest rate of 6.35 percent and 5.08 percent; (2)
expected life of 9.8 and 10 years; (3) expected volatility of 24.92 percent and
19.34 percent; and (4) a dividend yield of 5.97 percent and 6.51 percent. Had we
elected to use SFAS No. 123, compensation expense would have increased
$5,280,000 in 1999, $795,000 in 1998, and $195,000 in 1997. The 1999 pro-forma
net income would be $143,456,000 with basic earnings per common share of $1.31
and diluted earnings per common share of $1.30. The 1998 and 1997 compensation
expense effects on net income and earnings per share are not significant.
<PAGE>
NOTE 8 - PREFERRED STOCK
- ------------------------
We have 5,000,000 authorized shares of preferred stock. We cannot declare
or pay dividends on our common stock while we have not either declared and set
apart cumulative dividends or paid dividends on any of our preferred stock.
- --------------------------------------------------------------------------------
Table Our preferred stock is in three series as detailed in the following
table:
- --------------------------------------------------------------------------------
Shares Issued Thousands
Stated and and Outstanding of Dollars
Liquidation ---------------------------------------------
Series Price* 1999 1998 1999 1998
- --------------------------------------------------------------------------------
$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.
We have the option of redeeming our preferred stock with the consent or
affirmative vote of the holders of a majority of the common shares on 30 days
notice at $110 per share for our $6.00 series and $103 per share for our $4.20
series, plus accumulated dividends. Our $6.875 series is redeemable in whole or
in part, at any time on or after November 1, 2003, for a price beginning at
$103.438 per share, which decreases annually through October 2013. After that
time, the redemption price is $100 per share.
NOTE 9 - COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF
- -------------------------------------------------------------------------
SUBSIDIARY TRUST
- ----------------
We established Montana Power Capital I (Trust) as a wholly owned business
trust to issue common and preferred securities and hold Junior Subordinated
Deferrable Interest Debentures (Subordinated Debentures) that we issue. At
December 31, 1999 and 1998, the Trust has issued 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 our Subordinated Debentures, 8.45 percent
Series due 2036. The Trust will use interest payments received on the
Subordinated Debentures that it holds to make the quarterly cash distributions
on the QUIPS.
On or after November 6, 2001, we can wholly redeem the Subordinated
Debentures at any time, or partially redeem the Subordinated Debentures from
time to time. We can also wholly redeem the Subordinated Debentures if certain
events occur before that time. Upon repayment of the Subordinated Debentures at
maturity or early redemption, the Trust Securities must be redeemed. In
addition, we can terminate the Trust at any time and cause the pro rata
distribution of the Subordinated Debentures to the holders of the Trust
Securities.
Besides our obligations under the Subordinated Debentures, we have agreed
to certain Back-up Undertakings. We have 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 we have agreed to pay all of the
expenses of the Trust. Considered together with the Subordinated Debentures, the
Back-up Undertakings constitute a full and unconditional guarantee of the
Trust's obligations under the QUIPS. We are 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>
NOTE 10 - LONG-TERM DEBT
- ------------------------
The 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 obligations
collateralized are First Mortgage Bonds, including those First Mortgage Bonds
designated as Secured Medium-Term Notes and those securing Pollution Control
Revenue Bonds.
- --------------------------------------------------------------------------------
Table Long-term debt consists of the following:
- --------------------------------------------------------------------------------
December 31
-----------------------
1999 1998
-----------------------
(Thousands of Dollars)
First Mortgage Bonds:
7.7% series, due 1999 ............................. $ 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 2000-2025 7.20%-8.11% ................ 88,000 88,000
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
Natural Gas Transition Bonds - 6.20%, due 2012 ....... 61,015 62,700
ESOP Notes Payable - 9.2%, due 2004 .................. 19,431 22,392
Unsecured Medium-Term Notes:
Series A - maturing 1999-2022 8.68%-8.9% ......... 17,000 19,500
Series B - maturing 2001-2026 6.37%-7.96% ........ 100,000 115,000
Revolving Credit Agreements .......................... 17,502 14,241
Other ................................................ 28,111 71,779
Unamortized Discount and Premium ..................... (3,797) (4,196)
-----------------------
677,467 794,621
Less: Portion due within one year ................... 58,955 96,292
-----------------------
$ 618,512 $ 698,329
======================
- --------------------------------------------------------------------------------
On February 1, 1999, we used the proceeds from asset-backed securities
issued by the special purpose entity (SPE) discussed below to retire $55,000,000
of our 7.7 percent First Mortgage Bonds.
The electric and natural gas legislation discussed in Note 4,
"Deregulation and Regulatory Matters," authorized the issuance of transition
bonds. These securitization bonds involve the issuance of a non-recourse debt
instrument. The bonds are repaid through, and secured by, a specified component
of future revenues meant to recover the regulatory assets, thereby reducing the
credit risk of the securities. This specific component of revenues is referred
to as a CTC. An April 1998 PSC Financing Order relating to natural gas approved
the issuance of up to $65,000,000 of such bonds. In December 1998, we issued
$62,700,000 of 6.2 percent bonds. We will retire the bonds at six-month
intervals from September 15, 1999, through March 15, 2012. Retirements are in
varying amounts depending on revenues collected from customers. We established
an SPE, which is a wholly owned subsidiary, to issue the bonds. At December 31,
1999, approximately $61,015,000 was outstanding, of which approximately
$2,600,000 was classified as due within one year on the Consolidated Balance
Sheet.
Although the bonds were issued by an SPE and are without recourse to our
general credit, the bonds are shown as debt on the Consolidated Balance Sheet.
Similarly, the right to receive the revenues pledged to secure the bonds is a
specific right of
<PAGE>
the SPE and not of Montana Power's. However, as a wholly owned subsidiary, the
SPE's revenues and expenses are shown as revenues and expenses in the
Consolidated Statement of Income. Due to the regulatory mechanism for
recognizing the operations of the SPE, including the amortization of the
regulatory assets, we do not expect it to have a material effect on our
consolidated financial position, results of operations, or cash flows.
To ensure that collections by the SPE are neither more nor less than the
amount necessary to pay interest, principal, and other related issuance costs,
we are required to file for periodic adjustments, or reconciliations, to the
annual amounts to be collected by the SPE. The PSC is required to approve these
adjustments.
We retired at maturity $2,500,000 of 8.90 percent Series A Unsecured
Medium-Term Notes (MTNs) on October 1, 1999.
On September 3, 1999, we retired $10,000,000 of our 7.875 percent Series B
Unsecured MTNs due December 23, 2026. We retired an additional $5,000,000 of
these MTNs on October 13, 1999.
Altana Exploration Ltd. (Altana), a wholly owned Canadian subsidiary,
purchased the stock of a Canadian company for approximately $26,500,000 (United
States dollars) in December 1997. We arranged financing for the purchase 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, 1999 and 1998, the United
States dollar amounts outstanding under the agreement were $17,502,000
($24,259,000 Canadian dollars) and $14,241,000 ($21,796,000 Canadian dollars),
respectively. These amounts are included in "Revolving Credit Agreements" in the
table above. Interest under the agreement is calculated on the Royal Bank's
prime rate that ranged from 6.25 percent to 6.75 percent during 1999.
In April 1997, we entered into a $160,000,000 Revolving Credit Agreement
(Credit Agreement) for some of our nonutility operations. Under the terms of the
Credit Agreement, the amount of the facility decreased on March 31, 1998,
reducing the borrowing ability to $100,000,000. This Credit Agreement terminates
on April 4, 2000, and all outstanding borrowings must be repaid on this date.
Fixed or variable interest rate options are available under the Credit Agreement
with facility fees or commitment fees on the unused portions.
As discussed in Note 2, "Contingencies," we recorded long-term debt of
approximately $57,000,000 regarding the Kerr mitigation in June 1997. This
amount represented the net present value of future costs to be paid over the
life of the license. With the sale of the generating assets, payments after the
sale date are no longer our responsibility. Therefore, we reduced debt on the
sale date to approximately $24,300,000. On December 30, 1999, we paid
approximately $14,100,000 of this amount. We included the remaining $10,200,000
in "Other" in the table above, and it is classified as due within one year on
the Consolidated Balance Sheet at December 31, 1999. The final payment for
$10,200,000 occurred on January 3, 2000.
Scheduled debt repayments for the five years ending December 31, 2004, on
the long-term debt outstanding at December 31, 1999, amount to: $59,000,000 in
2000; $94,000,000 in 2001; $9,000,000 in 2002; $42,000,000 in 2003; $9,000,000
in 2004; and $464,000,000 thereafter. However, as part of the Tier II rate
filing discussed in Note 4, "Deregulation and Regulatory Matters," we indicated
our intention to retire approximately $266,000,000 of long-term debt. We
estimate that the expenses associated with these retirements will be
approximately $20,000,000. As discussed above, we have already repurchased
$15,000,000 of our 7.875 percent Series B Unsecured MTNs due December 23, 2026.
In addition, we repurchased $5,000,000 of 7.25 percent Secured MTNs due January
19, 2024, and $7,000,000 of 8.68 percent Unsecured Series A MTNs due February 7,
2022, in January of 2000. We plan to retire additional long-term debt throughout
2000.
NOTE 11 - SHORT-TERM BORROWING
- ------------------------------
We have short-term borrowing facilities with commercial banks that provide
both committed and 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, 1999, we had lines of credit consisting of $210,000,000
committed and $95,000,000 uncommitted. Facility fees or commitment fees on the
committed lines of credit are not significant. We have 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.
At December 31, 1999, we had no short-term obligations. At December 31,
1998, we had notes payable to banks for $40,000,000 at 5.87 percent interest and
commercial paper issued for $29,820,000 at 6.04 percent interest.
NOTE 12 - RETIREMENT PLANS
- --------------------------
We maintain trusteed, noncontributory retirement plans covering
substantially all of our employees. Prior to 1998, our retirement benefits were
based on salary, years of service, and social security integration levels. In
1998, we amended our retirement plan's benefit provisions. Our retirement
benefits are now based on salary, age, and years of service.
Our plan assets consist primarily of domestic and foreign corporate
stocks, domestic corporate bonds, and United States Government securities.
<PAGE>
We also have an unfunded, nonqualified benefit plan for senior management
executives and directors. In December 1998, we froze the benefits earned and
curtailed the plan and accrued approximately $4,300,000 of expense in accordance
with SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of
Defined Benefit Pension Plans."
As a result of the sale of our electric generating assets to PPL Montana,
454 participants related to electric generation operations were curtailed from
the retirement plan and approximately $22,700,000 in assets were transferred
from the retirement plan trust to the PPL retirement plan trust. Pursuant to the
Agreement, an estimated $3,100,000 of assets will be transferred to the PPL
trust when the calculation is finalized in 2000. In accordance with SFAS No. 88,
we calculated a curtailment gain of approximately $4,100,000 and a settlement
gain of approximately $7,800,000. Due to regulatory accounting treatment, the
gains were recorded as regulatory liabilities or offsets to regulatory assets,
resulting in no income statement impact.
Together with the majority of our subsidiaries, we also provide certain
health care and life insurance benefits for eligible retired employees. The plan
assets consist primarily of domestic and foreign corporate stocks, domestic
corporate bonds, and United States Government securities. The PSC allows us to
include in rates all utility Other Postretirement Benefits costs on the accrual
basis provided by SFAS No. 106, "Employers' Accounting for Postretirement
Benefits Other Than Pensions."
We also have a voluntary retirement savings plan in conjunction with our
retirement plans. We make matching contributions, including shares from a
leveraged Employee Stock Ownership Plan arrangement and shares purchased on the
open market. For costs associated with these plans, see Note 7, "Common Stock."
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------
Table 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, 1999, and
a statement of the funded status as of December 31 of both years:
- ----------------------------------------------------------------------------------------------------
Pension Benefits Other Benefits
-------------------------------------------------
1999 1998 1999 1998
-------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
CHANGE IN BENEFIT OBLIGATION:
Benefit obligation at January 1 ............. $ 273,401 $ 247,903 $ 24,512 $ 22,191
Service cost on benefits earned ............. 8,724 8,170 844 776
Interest cost on projected benefit obligation 19,529 18,289 1,776 1,665
Plan amendments ............................. 8,578 8,387 -- --
Actuarial (gain) loss ....................... (32,712) 5,878 (502) 2,149
Curtailments ................................ (5,712) (4,303) (3,093) --
Settlements ................................. (18,096) -- -- --
Gross benefits paid ......................... (11,707) (10,923) (1,909) (2,269)
-------------------------------------------------
Benefit obligation at December 31 ........... $ 242,005 $ 273,401 $ 21,628 $ 24,512
=================================================
CHANGE IN PLAN ASSETS:
Fair value of plan assets at January 1 ...... $ 289,881 $ 259,059 $ 8,782 $ 8,168
Actual return on plan assets ................ 18,620 39,765 226 1,036
Employer contributions ...................... -- -- 2,817 1,847
Divestitures ................................ (22,707) -- -- --
Gross benefits paid ......................... (9,546) (8,943) (1,909) (2,269)
-------------------------------------------------
Fair value of plan assets at December 31 .... $ 276,248 $ 289,881 $ 9,916 $ 8,782
=================================================
RECONCILIATION OF FUNDED STATUS:
Funded status at end of year ................ $ 34,262 $ 16,463 $ (11,712) $ (15,730)
Unrecognized net:
Actuarial gain ........................... (65,893) (54,169) (6,263) (5,212)
Prior service cost ....................... 17,856 12,980 1,822 826
Transition obligation .................... (363) (337) 11,751 15,440
-------------------------------------------------
Net amount recognized at December 31 ..... $ (14,138) $ (25,063) $ (4,402) $ (4,676)
=================================================
- ----------------------------------------------------------------------------------------------------
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------
Table The following table provides the amounts recognized in the statement of financial
position as of December 31:
- ------------------------------------------------------------------------------------------
Pension Benefits Other Benefits
-------------------------------------------------
1999 1998 1999 1998
-------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Prepaid benefit cost ................. $ 7,571 $ 4,028
Accrued benefit cost ................. (21,709) (29,091) $ (4,402) $ (4,676)
-------------------------------------------------
Net amount recognized at December 31 . $ (14,138) $ (25,063) $ (4,402) $ (4,676)
=================================================
- ------------------------------------------------------------------------------------------
</TABLE>
- --------------------------------------------------------------------------------
Table 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 1999, 1998,
and 1997:
- --------------------------------------------------------------------------------
Pension Benefits
---------------------------------
1999 1998 1997
---------------------------------
(Thousands of Dollars)
Service cost on benefits earned ............. $ 8,719 $ 8,079 $ 6,625
Interest cost on projected benefit
obligation .............................. 19,540 18,238 16,316
Expected return on plan assets .............. (25,650) (22,870) (19,900)
Amortization of:
Transition obligation ................... 43 358 383
Prior service cost ...................... 1,741 1,468 965
Actuarial gains ......................... (1,658) (1,062) (1,474)
Immediate recognition of DC conversion ...... -- (142) --
---------------------------------
Net periodic benefit cost ................... 2,735 4,069 2,915
Curtailment (gain) loss ..................... (3,751) 3,964 960
Settlement gain ............................. (7,844) -- --
---------------------------------
Net periodic benefit cost after curtailments
and settlements ......................... $ (8,860) $ 8,033 $ 3,875
=================================
Other Benefits
---------------------------------
1999 1998 1997
---------------------------------
(Thousands of Dollars)
Service cost on benefits earned ............. $ 844 $ 777 $ 571
Interest cost on projected benefit obligation 1,776 1,665 1,486
Expected return on plan assets .............. (722) (671) (459)
Amortization of:
Transition obligation ................... 1,098 1,120 1,100
Prior service cost ...................... 177 69 --
Actuarial gain .......................... (133) (274) (384)
---------------------------------
Net periodic benefit cost ................... 3,040 2,686 2,314
Curtailment gain ............................ (374) -- --
---------------------------------
Net periodic benefit cost after curtailments $ 2,666 $ 2,686 $ 2,314
=================================
<PAGE>
In 1999, funding for pension costs exceeded SFAS No. 87, "Employers
Accounting for Pensions," pension expense by $1,631,000. In 1998 and 1997,
pension costs exceeded SFAS No. 87 pension expense by $1,780,000 and $5,441,000,
respectively. The PSC allows recovery for the funding of pension costs through
rates. Any differences between funding and expense are deferred for recognition
in future periods. At December 31, 1999, the regulatory liability was
$5,755,000.
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------------------------
Table The following assumptions were used in the determination of actuarial present values of the projected benefit obligations:
- ----------------------------------------------------------------------------------------------------------------------------------
Pension Benefits Other Benefits
-----------------------------------------------------
1999 1998 1999 1998
-----------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Weighted average assumptions as of December 31:
Discount rate ................................................. 7.75% 6.75% 7.75% 6.75%
Expected return on plan assets ................................ 9.00% 9.00% 9.00% 9.00%
Rate of compensation increase ................................. 4.40% 3.97% 4.40% 3.75%
- ----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------
Table Assumed health care costs trend rates have a significant effect on the
amounts reported for the health care plans. A change of 1 percent in
assumed health care cost trend rates would have the following effects:
- -----------------------------------------------------------------------------------
1% Increase 1% Decrease
--------------------------
1999 1998
--------------------------
(Thousands of Dollars)
<S> <C> <C>
Effect on the total of service and interest
cost components of net periodic post-
retirement health care benefit cost ............ $ 116 $(108)
Effect on the health care component of
the accumulated postretirement benefit
obligation ..................................... 854 (804)
</TABLE>
- --------------------------------------------------------------------------------
The assumed 2000 health care cost trend rates used to measure the expected
cost of benefits covered by the plans is 7.00 percent. The trend rate decreases
through 2004 to 5 percent.
<PAGE>
NOTE 13 - INFORMATION ON INDUSTRY SEGMENTS
- ------------------------------------------
Our utility operations purchase, transmit, and distribute electricity and
natural gas. With the sale of our electric generating assets other than Milltown
Dam, we no longer are primarily engaged in regulated electric generation. In our
nonutility businesses, our telecommunications operation designs, develops,
constructs, operates, maintains, and manages a fiber-optic network and wireless
facilities; it also sells long-distance, Internet, and private-line services and
equipment. In other nonutility operations, we mine and sell coal and lignite;
manage long-term power sales, and develop and invest in independent power
projects and other energy-related businesses; and explore for, develop, produce,
process, and sell oil and natural gas. We also trade crude oil, natural gas, and
natural gas liquids.
In 1997, our coal operations recognized $104,231,000 in revenues from
sales to Reliant Energy. This amount exceeded 10 percent of our 1997
consolidated revenues. The loss of these revenues would have a material adverse
effect on our coal operations. In our independent power operations, the loss of
revenues pursuant to contracts with two customers would have a material adverse
effect on that segment.
The PSC approved our open-access and reorganization plan for our natural
gas utility effective November 1, 1997. Under the approved plan, we transferred
substantially all of our utility's natural gas production assets, including
those of a Canadian subsidiary, to our nonutility oil and natural gas operations
as of that date.
We consider segment information for foreign operations immaterial.
- --------------------------------------------------------------------------------
Table Information on industry segments
- --------------------------------------------------------------------------------
OPERATIONS INFORMATION:
UTILITY
-----------------------
Electric Natural Gas
-----------------------
Sales to unaffiliated customers .................... $456,933 $111,118
Earnings from unconsolidated investments ........... -- --
Intersegment revenues .............................. 13,616 629
Depreciation, depletion, and amortization .......... 53,574 9,279
Write-downs of long-lived assets ................... -- --
Pretax operating income (loss) ..................... 110,666 16,459
Interest expense ................................... 38,467 15,229
Interest revenue ................................... 3,801 545
Income tax expense ................................. 11,549 391
Capital expenditures ............................... 50,167 13,115
Identifiable assets ................................ 910,066 406,413
UTILITY
-----------------------
Electric Natural Gas
-----------------------
Sales to unaffiliated customers .................... $450,719 $107,052
Earnings from unconsolidated investments ........... -- --
Intersegment revenues .............................. 7,576 727
Depreciation, depletion, and amortization .......... 56,524 8,705
Pretax operating income (loss) ..................... 124,841 15,019
Interest expense ................................... 48,903 12,946
Interest revenue ................................... 3,521 925
Income tax expense ................................. 26,391 168
Capital expenditures ............................... 61,334 21,989
Identifiable assets ................................ 1,577,583 405,670
UTILITY
-----------------------
Electric Natural Gas
-----------------------
Sales to unaffiliated customers .................... $435,986 $122,355
Earnings from unconsolidated investments ........... -- --
Intersegment revenues .............................. 4,685 588
Depreciation, depletion, and amortization .......... 51,674 11,939
Pretax operating income (loss) ..................... 111,002 37,994
Interest expense ................................... 44,571 13,112
Interest revenue ................................... 5,626 2,174
Income tax expense ................................. 25,969 9,674
Capital expenditures ............................... 122,639 15,679
Identifiable assets ................................ 1,560,055 390,463
* The amounts indicated include certain eliminations among the business
segments.
<PAGE>
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 1999
- -----------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
NONUTILITY CORPORATE RECONCILIATION TO CONSOLIDATED
- ------------------------------------------------------------------------ ----------- -----------------------------------------
Tele- Independent Oil and Segment Consolidated
Communications Coal Power Natural Gas Other Total Adjustments* Total
- ------------------------------------------------------------------------ -----------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
$ 84,350 $ 197,053 $ 75,101 $ 338,869 $ 47,451 $ 1,310,875 $ 1,310,875
10,392 -- 21,042 -- -- 31,434 31,434
1,012 39,729 1,764 16,663 1,874 75,287 $ (75,287) --
9,048 7,446 3,122 23,832 4,844 111,145 111,145
-- -- -- 7,083 -- 7,083 7,083
35,640 36,602 23,442 15,960 (6,891) 231,878 231,878
1 364 18 1,170 3,356 58,605 (10,107) 48,498
810 832 6,368 2,774 6,945 22,075 (10,107) 11,968
14,088 3,298 9,641 2,363 2,733 44,063 44,063
153,617 10,187 336 41,902 27 $ 15,956 285,307 285,307
290,722 237,036 203,066 304,537 66,935 629,968 3,048,743 3,048,743
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 1998
- -----------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
NONUTILITY CORPORATE RECONCILIATION TO CONSOLIDATED
- ------------------------------------------------------------------------ ----------- -----------------------------------------
Tele- Independent Oil and Segment Consolidated
Communications Coal Power Natural Gas Other Total Adjustments* Total
- ------------------------------------------------------------------------ -----------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
$ 87,748 $ 177,961 $ 73,707 $ 221,662 $ 47,988 $ 1,166,837 $ 1,166,837
10,909 -- 89,525 -- -- 100,434 100,434
1,298 38,796 2,014 17,606 1,913 69,930 $(69,930) --
7,090 6,596 9,005 22,259 4,088 114,267 114,267
49,960 32,560 84,719 7,640 (9,464) 305,275 305,275
1 443 58 1,203 9,716 73,270 (6,927) 66,343
668 2,406 4,839 (450) 989 12,898 (6,927) 5,971
19,772 8,107 32,315 (2,522) (6,057) 78,174 78,174
56,203 7,746 11,329 53,319 1,292 $ 189 213,401 213,401
189,560 235,438 120,675 289,453 67,049 42,667 2,928,095 2,928,095
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 1997
- -----------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
NONUTILITY CORPORATE RECONCILIATION TO CONSOLIDATED
- ------------------------------------------------------------------------ ----------- -----------------------------------------
Tele- Independent Oil and Segment Consolidated
Communications Coal Power Natural Gas Other Total Adjustments* Total
- ------------------------------------------------------------------------ -----------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
$ 46,691 $ 167,623 $ 70,932 $ 163,656 $ 939 $ 1,008,182 $ 1,008,182
435 -- 14,980 -- -- 15,415 15,415
799 34,164 1,820 3,120 5,719 50,895 $ (50,895) --
2,494 9,043 2,774 16,922 494 95,340 95,340
11,927 28,849 14,963 16,310 (4,543) 216,502 216,502
-- 424 32 106 6,043 64,288 (4,129) 60,159
143 (13,675) 3,886 25,238 16,293 39,685 (4,129) 35,556
4,824 (700) 6,762 10,776 4,565 61,870 61,870
27,955 4,588 294 140,437 -- $ 94 311,686 311,686
101,581 247,981 156,282 290,110 7,987 51,437 2,805,896 2,805,896
</TABLE>
<PAGE>
SUPPLEMENTARY DATA (Unaudited)
- ------------------------------
OIL AND NATURAL GAS PRODUCING ACTIVITIES
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------------
Table For the years ended December 31, 1999, 1998, and 1997, 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:
- --------------------------------------------------------------------------------------------------------------------------
1999 1998
------------------------------------------------------------------------------
U.S. Canada Storage U.S. Canada Storage
------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
PROVED DEVELOPED AND UNDEVELOPED RESERVES:
UTILITY OPERATIONS:
- -------------------
Natural Gas (Mmcf):
Beginning Balance ................ 1,862 0 58,309 2,097 0 56,840
Production ....................... (157) (235)
Additions ........................
(Sales) and Purchases
of Reserves in Place ...........
Transfers Out ....................
Revisions - Other ................
Revisions - Price ................ (1,584) 1,469
-------------------------------------------------------------------------
Ending Balance .............. 1,705 0 56,725 1,862 0 58,309
-------------------------------------------------------------------------
NONUTILITY OPERATIONS:
- ----------------------
Natural Gas (Mmcf):
Beginning Balance .................... 196,050 138,139 191,250 125,135
Production ........................... (18,749) (12,189) (14,099) (11,216)
Additions ............................ 46,120 44,190 39,774 41,456
(Sales) and Purchases
of Reserves in Place ............... (534) 2,040 1,400 (2,808)
Transfers In .........................
Revisions - Other .................... (13,190) (24,482) (4,635) (16,001)
Revisions - Price .................... 11,776 (297) (17,640) 1,573
-------------------------------------------------------------------------
Ending Balance .................. 221,473 147,401 196,050 138,139
-------------------------------------------------------------------------
Natural Gas Liquids (bbls):
Beginning Balance .................... 8,486,800 1,922,000 8,246,554 2,542,585
Production ........................... (760,600) (205,000) (218,000) (325,000)
Additions ............................ 1,262,100 23,000 1,321,300 431,000
(Sales) and Purchases
of Reserves in Place ............... (41,200) (295,000) (57,000)
Revisions - Other .................... (99,200) (985,000) 438,946 (667,585)
Revisions - Price .................... 440,600 145,000 (1,302,000) (2,000)
-------------------------------------------------------------------------
Ending Balance .................. 9,288,500 605,000 8,486,800 1,922,000
-------------------------------------------------------------------------
Oil (bbls):
Beginning Balance .................... 3,275,500 941,000 5,025,390 2,700,071
Production ........................... (438,900) (151,000) (242,800) (258,000)
Additions ............................ 835,600 0 543,300 22,000
(Sales) and Purchases
of Reserves in Place ............... (7,000) (1,000) (540,000)
Revisions - Other .................... 288,200 (172,000) (874,071)
Revisions - Price .................... 604,500 81,000 (2,050,390) (109,000)
-------------------------------------------------------------------------
Ending Balance .................. 4,557,900 698,000 3,275,500 941,000
=========================================================================
<CAPTION>
- ---------------------------------------------------------------------------------
1997
-------------------------------------
U.S. Canada Storage
-------------------------------------
PROVED DEVELOPED AND UNDEVELOPED RESERVES:
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
===================================
</TABLE>
<PAGE>
OIL AND NATURAL GAS PRODUCING ACTIVITIES (Continued)
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------
1999 1998 1997
---------------------------------------------------------------
U.S. Canada U.S. Canada U.S. Canada
---------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
PROVED DEVELOPED RESERVES:
UTILITY OPERATIONS:
- -------------------
Natural Gas (Mmcf):
Ending Balance ........ 1,705 0 1,862 0 2,097 0
NONUTILITY OPERATIONS:
- ----------------------
Natural Gas (Mmcf):
Ending Balance ........ 149,671 125,555 133,578 118,452 139,802 104,799
Natural Gas Liquids (bbls):
Ending Balance ........ 6,890,200 574,000 5,802,800 1,650,000 8,246,184 2,298,585
Oil (bbls):
Ending Balance ........ 3,709,700 583,000 2,778,500 941,000 3,474,602 2,079,071
</TABLE>
- --------------------------------------------------------------------------------
Our nonutility United States natural gas, natural gas liquids, and oil
reserves increased in 1999 primarily due to successful drilling in Wyoming,
Colorado, and Oklahoma. Substantially higher year-end prices, which improve
production economics, also increased our United States reserves. In 1999, as in
the prior year, our Canadian natural gas reserves increased due to successful
development drilling in Southeast Alberta. Upward price revisions also increased
our Canadian natural gas liquids and oil reserves. These Canadian increases were
partially offset by downward revisions reflecting disappointing performance in
the Caroline field.
Nonutility United States natural gas and natural gas liquids 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 United States 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 United States natural gas and natural gas liquids 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.
As determined by engineers, utility natural gas reserves were revised
during 1997 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
United States 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.
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 United States and Canadian natural gas reserves
in 1997.
<PAGE>
OIL AND NATURAL GAS PRODUCING ACTIVITIES (Continued)
The following table presents information for 1999, 1998, and 1997 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, we are
authorized to earn a rate of return on our utility natural gas plant rate base.
Our 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, we are unable to identify revenues resulting solely from
utility natural gas producing activities. Accordingly, the information on
revenues, income taxes, results of operations, and estimated future net cash
flows and changes therein relating to proved utility natural gas reserves are
not presented for our utility natural gas producing activities.
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
Table Utility Operations
- ------------------------------------------------------------------------------------------------------------------------------------
1999 1998 1997
----------------------------------------------------------------------
U.S. Canada U.S. Canada U.S. Canada
----------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
At December 31:
Capitalized costs relating
to natural gas producing activities .............. $2,026 $0 $ 2,026 $0 $2,023 $ 0
Accumulated depreciation,
depletion, and valuation allowances .............. 1,856 0 1,853 0 1,833 0
----------------------------------------------------------------------
Net capitalized costs ........................ $ 170 $0 $ 173 $0 $ 190 $ 0
======================================================================
For the year ended December 31:
Costs incurred in natural gas property
acquisition, exploration, and
development activities:
Acquisition of properties.....................
Exploration .................................. $ 35 $ 168
Development .................................. $ 0 $0 $ (5) $0 1 66
Costs reflected in results of operations:
Production costs ............................. $ 80 $0 $ 98 $0 $3,361 $1,359
Exploration expenses ......................... 0 0 (3) 0 35 168
Development expenses ......................... 0 0 0 0 0 66
Depreciation, depletion,
and valuation provisions ................ 3 19 2,072 686
- ------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<PAGE>
OIL AND NATURAL GAS PRODUCING ACTIVITIES (Continued)
The following table presents information for 1999, 1998, and 1997 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>
- ------------------------------------------------------------------------------------------------------------------------------------
Table Nonutility Operations
- ------------------------------------------------------------------------------------------------------------------------------------
1999 1998 1997
-------------------------------------------------------------------------
U.S.* Canada U.S.* Canada U.S.* Canada
-------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
At December 31:
Capitalized costs relating
to natural gas producing activities .............. $221,164 $130,393 $200,743 $109,742 $181,077 $113,165
Accumulated depreciation,
depletion, and valuation allowances .............. 61,902 56,065 51,247 43,026 43,879 46,131
-------------------------------------------------------------------------
Net capitalized costs ........................ $159,262 $ 74,328 $149,496 $ 66,716 $137,198 $ 67,034
-------------------------------------------------------------------------
For the year ended December 31:
Costs incurred in oil and natural gas
property acquisition, exploration,
and development activities:
Acquisition of properties .................... $ 666 $ 3,438 $ 1,466 $ 1,408 $ 46,058 $ 22,762
Exploration .................................. 1,244 1,406 2,197 1,502 4,589 6,036
Development .................................. 23,430 13,317 20,868 15,287 12,758 8,535
Results of operations for oil and natural
gas producing activities:
Revenues ..................................... $ 37,272 $ 22,093 $ 28,366 $ 18,739 $ 34,182 $ 14,821
Production costs ............................. 10,636 6,774 10,075 7,222 10,041 5,041
Exploration expenses ......................... 1,244 1,387 2,158 1,439 3,233 2,905
Depreciation, depletion,
and valuation provisions ................ 12,689 11,007 11,050 6,779 9,464 3,781
-------------------------------------------------------------------------
12,703 2,925 5,083 3,299 11,444 3,094
Income tax expenses .......................... 3,344 300 425 1,472 3,188 1,380
-------------------------------------------------------------------------
Results of operations from producing
activities (excluding corporate
overhead and interest cost) ...................... $ 9,359 $ 2,625 $ 4,658 $ 1,827 $ 8,256 $ 1,714
=========================================================================
</TABLE>
* United States excludes capitalized costs and associated accumulated
depreciation, revenues, and expenses related to support equipment and
facilities. The capitalized costs of support equipment and facilities were
$73,127,000, $70,304,000, and $53,359,000 and the associated accumulated
depreciation was $12,248,000, $8,939,000, and $5,288,000 for 1999, 1998,
and 1997, respectively.
- --------------------------------------------------------------------------------
Estimated future cash flows are computed by applying year-end prices and
contract prices, when appropriate, of oil and natural gas to year-end quantities
of proved reserves. Estimated future development and production costs are
determined by estimating the expenditures to be incurred in developing and
producing the proved oil and natural gas reserves at the end of the year, based
on year-end costs. Estimated future income tax expenses are calculated by
applying year-end statutory tax rates to estimated future pretax net cash flows
related to proved oil and natural gas reserves, less the tax basis of the
properties involved. The future income tax expenses give effect to permanent
differences, tax credits and deferred taxes relating to proved oil and natural
gas reserves.
These estimates are furnished and calculated in accordance with
requirements of the Financial Accounting Standards Board and the Securities and
Exchange Commission (SEC). Management believes the usefulness of these
projections is limited because of the unpredictable variances in expenses,
capital forecasts, and crude oil and natural gas prices. Estimates of future net
cash flows presented do not represent management's assessment of our future
profitability or future cash flow. 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>
OIL AND NATURAL GAS PRODUCING ACTIVITIES (Continued)
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
Table The following are the standardized measure of discounted future net cash flows and changes therein relating to proved
oil and natural gas reserves:
- ------------------------------------------------------------------------------------------------------------------------------------
December 31
-----------------------------------------------------
1999 1998
-----------------------------------------------------
U.S. Canada U.S. Canada
-----------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Future cash inflows .................................................... $979,663 $347,464 $650,446 $273,644
Future production and development costs ................................ 500,548 119,763 327,784 108,436
Future income tax expenses ............................................. 133,736 83,629 80,957 51,102
-----------------------------------------------------
Future net cash flows .................................................. 345,379 144,072 241,705 114,106
10 percent annual discount for estimated timing of
cash flows ......................................................... 142,532 61,850 96,136 47,155
-----------------------------------------------------
Standardized Measure of Discounted Future Net Cash Flows ............... $202,847 $ 82,222 $145,569 $ 66,951
=====================================================
</TABLE>
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
Table The following are the principal sources of change in the standardized measure of discounted future net cash flows:
- ------------------------------------------------------------------------------------------------------------------------------------
December 31
-----------------------------------------------------
1999 1998
-----------------------------------------------------
U.S. Canada U.S. Canada
-----------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Sales and transfers of oil and gas produced,
net of production costs ............................................ $(14,957) $ (6,482) $(16,236) $(11,518)
Net changes in prices, development and production costs ................ 25,995 30,774 (57,866) (13,339)
Extensions, discoveries, and improved recovery,
less related costs ................................................. 41,755 30,406 25,625 15,424
Revisions of previous quantity estimates ............................... 7,937 (25,044) (17,259) (8,916)
Accretion of discount .................................................. 16,811 8,006 21,338 8,937
Net change in income taxes ............................................. (23,239) (20,689) 2,511 (5,061)
Other .................................................................. 2,976 (1,700) (868) 106
</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
1999 and 1998, the amount described as Other is primarily the result of changes
in the timing of production.
<PAGE>
QUARTERLY FINANCIAL DATA
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------
Table Operating revenues, operating income, and net income in thousands of dollars and net income per
common share for the four quarters of 1999 and 1998 are shown in the tables below. Operating revenues
and income include intersegment sales and expenses. Due to the weather-related nature of the utility
business, the annual amounts are not generated evenly by quarter during the year.
- -----------------------------------------------------------------------------------------------------------------
Quarter Ended
Dec. 31, Sept. 30, June 30, March 31,
1999 1999 1999 1999
------------------------------------------------------
<S> <C> <C> <C> <C>
Utility Operating Revenues.......................... $ 169,351 $ 121,429 $ 130,748 $ 160,768
Utility Operating Income............................ 39,441 20,159 27,711 39,814
Utility Net Income.................................. 40,979 682 6,013 13,690
Nonutility Operating Revenues....................... 225,518 233,155 196,528 180,099
Nonutility Operating Income......................... 26,714 33,286 22,654 22,099
Nonutility Net Income............................... 20,159 27,607 18,315 19,211
Consolidated Net Income Available for Common Stock.. $ 61,138 $ 28,289 $ 24,328 $ 32,901
Basic Earnings Per Share of Common Stock............ $ 0.56 $ 0.26 $ 0.22 $ 0.30
Diluted Earnings Per Share of Common Stock.......... $ 0.56 $ 0.25 $ 0.22 $ 0.30
<CAPTION>
------------------------------------------------------
Quarter Ended
Dec. 31, Sept. 30, June 30, March 31,
1998 1998 1998 1998
------------------------------------------------------
<S> <C> <C> <C> <C>
Utility Operating Revenues.......................... $ 158,884 $ 124,799 $ 123,423 $ 158,968
Utility Operating Income............................ 37,850 34,002 24,981 43,027
Utility Net Income.................................. 16,587 10,930 5,022 18,946
Nonutility Operating Revenues....................... 258,403 204,165 156,323 152,236
Nonutility Operating Income......................... 80,735 38,845 24,999 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............ $ 0.63 $ 0.32 $ 0.20 $ 0.32
Diluted Earnings Per Share of Common Stock.......... $ 0.63 $ 0.32 $ 0.20 $ 0.32
- ----------------------------------------------------------------------------------------------------------------
</TABLE>
ITEM 9. DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
- -----------------------------------------------------------------------------
None.
<PAGE>
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
- -----------------------------------------------------------
Information on The Montana Power Company Directors is incorporated by
reference from the Company's Notice of 2000 Annual Meeting of Shareholders and
Proxy Statement, pages 6 - 8.
- --------------------------------------------------------------------------------
Table The following table shows our current Executive Officers, who are
elected or appointed annually by our Board of Directors, their ages at
December 31, 1999, and their areas of responsibility. A brief
description of their business experience during the past five years is
also included.
- --------------------------------------------------------------------------------
Name Age Position/Business Experience
- --------------------------------------------------------------------------------
R. P. Gannon 55 Chairman of the Board, President, and Chief Executive
Officer. Mr. Gannon was elected to the Board of
Directors in 1990 and was elected Chairman of the Board
of Directors in 1998. He served as Vice Chairman of the
Board of Directors from 1996 to 1997. He has served as
President since 1990 and as Chief Executive Officer
since 1997.
J. P. Pederson 57 Vice President, Chief Financial Officer. Mr. Pederson
was elected to the Board of Directors in 1993. He has
served as Vice President and Chief Financial Officer
since 1991. He also served as Chief Information Officer
from 1996 - 1999.
M. J. Meldahl 50 Executive Vice President and Chief Operating Officer,
Technology Division. Mr. Meldahl has held his present
position since 1998. He served as Vice President,
Communication Services, Energy and Communications
Division, from 1996 - 1998. He served as Vice President,
Technology Operations - Entech, from 1997 - 1999 and as
Vice President, Technology Division, from 1988 - 1996.
J. D. Haffey 54 Executive Vice President and Chief Operating Officer,
Energy Services Division. Mr. Haffey has held his
present position since 1996. He served as Vice President
of Administration and Regulatory Affairs from 1993 -
1996.
R. F. Cromer 54 Executive Vice President and Chief Operating Officer,
Energy Supply Division. Mr. Cromer has held his present
position since 1996. He has served as Chief Executive
Officer, Continental Energy Services, since 1998. He
also served as President of Continental Energy Services
from 1996 - 1998 and as President and Chief Operating
Officer of Continental Energy Services from 1992 - 1996.
P. K. Merrell 47 Vice President, Human Resources, and Secretary. Ms.
Merrell has held her present position since 1996. She
served as Vice President and Secretary from 1993 - 1996.
M. E. Zimmerman 51 Vice President and General Counsel. Mr. Zimmerman has
held his present position since 1991.
P. J. Cole 42 Vice President, Corporate Business Development. Mr. Cole
has held his present position since 1999. He served as
Vice President, Business Development and Regulatory
Affairs, from 1996 - 1999. He served as Treasurer for
the Utility Division from 1993 - 1996.
D. S. Smith 56 Controller. Mr. Smith has held his present position
since 1996. He served as Controller for Entech from 1988
- 1996.
E. M. Senechal 50 Treasurer. Ms. Senechal has held her present position
since 1996. She served as Vice President and Treasurer
for Entech from 1984 - 1996.
<PAGE>
- --------------------------------------------------------------------------------
Name Age Position/Business Experience
- --------------------------------------------------------------------------------
D. A. Johnson 54 Vice President, Distribution Services. Mr. Johnson has
held his present position since 1996. He served as Vice
President for Utility Services from 1993 - 1996.
W. A. Pascoe 43 Vice President, Transmission Services. Mr. Pascoe has
held his present position since 1997. He served as
Assistant Vice President, Transmission Services, from
1996 - 1997 and as Manager of Transmission and Power
Transactions from 1990 - 1996.
D. J. Sullivan 44 Chief Information Officer. Mr. Sullivan has held his
present position since 1999. He served as Executive
Director of Information Systems from 1998 - 1999, Leader
of Information Systems from 1996 - 1998, and General
Manager of Information Systems from 1995 - 1996.
W. S. Dee 59 Vice President, Marketing. Mr. Dee has held his present
position since 1997. He was employed as a consultant
with Leo Burnett Inc., an advertising agency, from 1993
- 1996. Mr. Dee will retire as our Vice President,
Marketing, effective March 31, 2000.
ITEM 11. EXECUTIVE COMPENSATION
- -------------------------------
Incorporated by reference from Notice of 2000 Annual Meeting of
Shareholders and Proxy Statement, pages 15 - 20.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
- -----------------------------------------------------------------------
Incorporated by reference from Notice of 2000 Annual Meeting of
Shareholders and Proxy Statement, pages 9 - 11.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
- -------------------------------------------------------
None.
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) We filed the following reports on Form 8-K:
Date Subject
- --------------------------------------------------------------------------------
October 26, 1999 Item 5. Other Events. Discussion of Third Quarter Net Income.
Item 7. Exhibits. Consolidated Statements of Income for the
Quarters Ended September 30, 1999 and 1998, Nine Months Ended
September 30, 1999 and 1998, and for the Twelve Months Ended
September 30, 1999 and 1998. Utility Operations Schedule of
Revenues and Expenses for the Quarters Ended September 30,
1999 and 1998, Nine Months Ended September 30, 1999 and 1998,
and for the Twelve Months Ended September 30, 1999 and 1998.
Nonutility Operations Schedule of Revenues and Expenses for
the Quarters Ended September 30, 1999 and 1998, Nine Months
Ended September 30, 1999 and 1998, and for the Twelve Months
Ended September 30, 1999 and 1998.
January 3, 2000 Item 2. Disposition of Assets. Sale of Generation Assets. Date
of earliest event reported: December 17, 1999.
Item 7. Financial Statements and Exhibits. Unaudited Pro Forma
Consolidated Statements of Income for the Twelve Months Ended
December 31, 1998 and Nine Months Ended September 30, 1999.
Unaudited Pro Forma Consolidated Balance Sheet at September
30, 1999.
<PAGE>
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(CONT.)
(c) Exhibits
<TABLE>
<CAPTION>
Incorporation by Reference
--------------------------------
Previous Exhibit
Previous Filing Designation
--------------------------------
<C> <S> <C> <C>
2 Asset Purchase Agreement 1-4566 2(a)
Form 8-K
Dated
November 2,
1998
2(a) Amendment No. 1 to the Asset Purchase Agreement 1-4566 2(a)
December 17,
1999 Form 8-K
2(b) Amendment No. 2 to the Asset Purchase Agreement 1-4566 2(b)
December 17,
1999 Form 8-K
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 1-4566 3
3(a)(3) Amendment to the Articles of Incorporation 1-4566 3
August 16,
1999 Form 10-Q
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 1-4566 3(b)
4(a) Mortgage and Deed of 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)
- ------------------------------------------------------------------------------------------------------------------
</TABLE>
Instruments defining the rights of holders of long-term debt which are not
required to be filed with the SEC will be furnished to the SEC upon request.
<PAGE>
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(Cont.)
<TABLE>
<CAPTION>
(c) Exhibits Incorporation by Reference
--------------------------------
Previous Exhibit
Previous Filing Designation
--------------------------------
<C> <S> <C> <C>
4(t) Rights Agreement dated as of June 6, 1989 between 33-42882 4(d)
The Montana Power Company and First Chicago Trust
Company of New York, as Rights Agent
4(u) Amendment to Rights Agreement dated March 2, 1999 1-4566 99(a)
10(a)(i) Benefit Restoration Plan for Senior Management 33-42882 10(a)(i)
Executives and Board of Directors
10(a)(ii) Deferred Compensation Plan for Non-Employee Directors 33-42882 10(a)(ii)
10(a)(iii) Long-Term Incentive Stock Ownership Plan 1-4566 10(a)(iii)
1992
Form 10-K
10(a)(iv) The Montana Power Company Employee Stock Ownership 33-28096 4(c)
Plan (Revised)
10(a)(v) Termination Compensation Agreements with 1-4566 10(a)(v)
Senior Management Executives 1996
Form 10-K
10(a)(vi) Colstrip Unit No. 3 Wholesale Transmission 1-4566 10(a)
Service Agreement (Exhibit F-1 to the Asset Form 8-K
Purchase Agreement) Dated
November 2, 1998
10(a)(vii) Non-Colstrip Unit No. 3 Wholesale Transmission 1-4566 10(b)
Service Agreement (Exhibit F-2 to the Asset Form 8-K
Purchase Agreement) Dated
November 2, 1998
10(a)(viii) Generation Interconnection Agreement (Exhibit G to the 1-4566 10(c)
Asset Purchase Agreement) Form 8-K
Dated
November 2, 1998
10(a)(ix) Equity Contribution Agreement 1-4566 10(d)
Form 8-K
Dated
November 2, 1998
10(a)(x) Amended Long-Term Incentive Plan 1-4566 10
June 30, 1999
Form 10-Q
10(c) Participation Agreements among United States Trust 33-42882 10(c)
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
</TABLE>
<PAGE>
THE MONTANA POWER COMPANY AND SUBSIDIARIES SCHEDULE II - VALUATION AND
QUALIFYING ACCOUNTS AND RESERVES
<TABLE>
<CAPTION>
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- -------------------------------------------------------------------------------------------------------------------
Additions
--------------------------
Balance at Charged to Charged to Balance
beginning costs and other at close
Description of period expenses accounts Deductions* of period
- -------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Year Ended:
December 31, 1999
Reserves deducted in balance sheet
from assets to which they apply:
Doubtful accounts
Utility.......................... $ 1,044 $ 2,010 $ 1,950 $ 1,104
Nonutility....................... 862 187 $ (12) 38 999
-------------------------------------------------------------------------
Total........................ $ 1,906 $ 2,197 $ (12) $ 1,988 $ 2,103
=========================================================================
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
=========================================================================
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
* 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.
<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, a duly authorized signatory.
THE MONTANA POWER COMPANY
By /s/ Robert P. Gannon
-----------------------
Robert P. Gannon
(Chairman of the Board)
Date: March 15, 2000
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
- -------------------------- Officer and Director March 15, 2000
Robert P. Gannon
(Chief Executive Officer)
/s/ J. P. Pederson Principal Financial March 15, 2000
- -------------------------- and Accounting
J. P. Pederson Officer and Director
(Vice President and
Chief Financial Officer)
/s/ Tucker Hart Adams Director March 15, 2000
- --------------------------
Tucker Hart Adams
/s/ Alan F. Cain Director March 15, 2000
- --------------------------
Alan F. Cain
/s/ John G. Connors Director March 15, 2000
- --------------------------
John G. Connors
/s/ R. D. Corette Director March 15, 2000
- --------------------------
R. D. Corette
/s/ Kay Foster Director March 15, 2000
- --------------------------
Kay Foster
/s/ John R. Jester Director March 15, 2000
- --------------------------
John R. Jester
/s/ Carl Lehrkind III Director March 15, 2000
- --------------------------
Carl Lehrkind III
/s/ Deborah D. McWhinney Director March 15, 2000
- --------------------------
Deborah D. McWhinney
/s/ N. E. Vosburg Director March 15, 2000
- --------------------------
N. E. Vosburg
- --------------------------------------------------------------------------------
<PAGE>
Exhibit 12
THE MONTANA POWER COMPANY
Computation of Ratio of Earnings to Fixed Charges
(Dollars in Thousands)
<TABLE>
<CAPTION>
Twelve Months Ended
December 31,
1999 1998 1997 1996 1995
-------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Net Income $148,880 $162,761 $127,985 $119,147 $ 59,053
Income Taxes 44,064 78,174 61,870 72,813 21,573
-------- -------- -------- -------- --------
$192,944 $240,935 $189,855 $191,960 $ 80,626
Fixed Charges:
Interest $ 49,332 $ 66,275 $ 61,720 $ 50,937 $ 47,330
Amortization of Debt Discount,
Expense and Premium 1,269 1,556 1,538 1,610 1,567
Rentals 35,141 34,999 34,671 34,470 35,300
-------- -------- -------- -------- --------
$ 85,732 $102,830 $ 97,929 $ 87,017 $ 84,197
Earnings Before Income Taxes
and Fixed Charges $278,676 $343,765 $287,784 $278,977 $164,823
======== ======== ======== ======== ========
Ratio of Earning to Fixed Charges 3.25 x 3.34 x 2.94 x 3.21 x 1.96 x
======== ======== ======== ======== ========
</TABLE>
<PAGE>
SUBSIDIARIES OF REGISTRANT
Exhibit 21
Percentage of Voting
Securities Owned
by Registrant
--------------------
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 Capital 1
A Montana Corporation 100
MPC Natural Gas Funding Trust
A Montana Corporation 100
Entech, Inc.
A Montana Corporation 100
Canadian-Montana Gas Company Limited
An Alberta 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 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.
<PAGE>
Percentage of Voting
Securities Owned
by Registrant
--------------------
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
Western Energy Company
A Montana Corporation 100
Western SynCoal LLC
100% Owned by 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
<PAGE>
Percentage of Voting
Securities Owned
by Registrant
--------------------
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
Montana Power Services Company
A Montana Corporation 100
Note: The above listed companies are included in the Consolidated Financial
Statements of the registrant.
<PAGE>
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-8 (No. 333-59573), 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. 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 10, 2000, except in Note 3 for the final paragraph
under the "Telecommunications" section entitled "Investments and Acquisitions",
as to which the date is March 13, 2000, appearing on page 58 of The Montana
Power Company's Annual Report on Form 10-K for the year ended December 31, 1999.
/s/ PricewaterhouseCoopers LLP
PRICEWATERHOUSECOOPERS LLP
Portland, Oregon
March 20, 2000
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED BALANCE SHEET AT 12/31/99, THE CONSOLIDATED INCOME STATEMENT AND
THE CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE TWELVE MONTHS ENDED 12/31/99
AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,002,074
<OTHER-PROPERTY-AND-INVEST> 863,103
<TOTAL-CURRENT-ASSETS> 887,036
<TOTAL-DEFERRED-CHARGES> 296,530
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 3,048,743
<COMMON> 557,901
<CAPITAL-SURPLUS-PAID-IN> 2,312
<RETAINED-EARNINGS> 448,603
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,008,816
65,000
57,654
<LONG-TERM-DEBT-NET> 617,061
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 58,044
0
<CAPITAL-LEASE-OBLIGATIONS> 1,451
<LEASES-CURRENT> 911
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,239,806
<TOT-CAPITALIZATION-AND-LIAB> 3,048,743
<GROSS-OPERATING-REVENUE> 1,342,309
<INCOME-TAX-EXPENSE> 44,063
<OTHER-OPERATING-EXPENSES> 1,110,431
<TOTAL-OPERATING-EXPENSES> 1,154,494
<OPERATING-INCOME-LOSS> 187,815
<OTHER-INCOME-NET> 11,029
<INCOME-BEFORE-INTEREST-EXPEN> 198,844
<TOTAL-INTEREST-EXPENSE> 48,498
<NET-INCOME> 150,346
3,690
<EARNINGS-AVAILABLE-FOR-COMM> 146,656
<COMMON-STOCK-DIVIDENDS> 88,155
<TOTAL-INTEREST-ON-BONDS> 49,881
<CASH-FLOW-OPERATIONS> 660,183
<EPS-BASIC> 1.34
<EPS-DILUTED> 1.33
</TABLE>
