March 25, 1998
Securities and Exchange Commission
Attn: Mr. Charles Leber
Judiciary Plaza
450 - 5th Street NW
Mail Stop 7-5
Washington, D.C. 20549
RE: File Number 1-4566
Dear Mr. Leber:
The accounting principles and practices and the method of applying such
principles and practices reflected in the financial statements included in the
1997 Annual Report on Form 10-K are consistent with those of preceeding years.
Very truly yours,
/s/ J.P. Pederson
J. P. Pederson
Vice President and Chief
Financial and Information
Officer
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, 1997
-OR-
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ______________ to _______________.
Commission file number 1-4566
THE MONTANA POWER COMPANY
(Exact name of registrant as specified in its charter)
Montana 81-0170530
(State or other jurisdiction (IRS Employer
of incorporation or organization) Identification No.)
40 East Broadway, Butte, Montana 59701-9394
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code (406) 723-5421
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each Class on which registered
Common Stock New York Stock Exchange
Pacific Stock Exchange
8.45% Cumulative Quarterly Income New York Stock Exchange
Preferred Securities, Series A
of Montana Power Capital I, a
subsidiary of The Montana Power
Company
Securities registered pursuant to Section 12(g) of the Act:
Preferred Stock
(Title of Class)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K (Section 229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K [ ].
The aggregate market value of the voting stock held by nonaffiliates of the
registrant was $1,996,590,783 at March 12, 1998.
On March 12, 1998, the Company had 54,910,359 shares of common stock
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
(1) Notice of 1998 Annual Meeting of Shareholders and Proxy Statement,
pages 1-26, is incorporated into Part III of this report.
PART I
This Form 10-K contains forward-looking statements within the meaning of
Section 21E of the Securities Exchange Act of 1934. Forward-looking statements
should be read with the cautionary statements and important factors included in
this Form 10-K at Item 7, "Management's Discussion and Analysis of Financial
Conditions and Results of Operations - Safe Harbor for Forward-Looking
Statements." Forward-looking statements are all statements other than
statements of historical fact, including without limitation those that are
identified by the use of the words "anticipates", "estimates", "expects",
"intends", "believes", and similar expressions.
ITEM 1. BUSINESS
GENERAL - INDUSTRY SEGMENTS: The Montana Power Company (the Company) and
its subsidiaries engage in a number of diversified energy and communication
related businesses. The Company's principal business is the regulated Utility
operations involving the generation, purchase, transmission and distribution of
electricity and the purchase, transportation and distribution of natural gas.
The Company's Nonutility operations principally involve the mining and sale of
coal and lignite, exploration for, and the development, production, processing
and sale, of oil and natural gas and the sale of telecommunication equipment
and services. It also conducts the trading and marketing of electricity and
natural gas. In addition, the Company manages long-term power sales, and
develops and invests in nonutility power projects and other energy-related
businesses. The Company was incorporated in 1961 under the laws of the State of
Montana, where its principal business is conducted, as the successor to a New
Jersey Corporation incorporated in 1912. See Part II, Item 8, "Financial
Statements and Supplementary Data - Note 12 to the Consolidated Financial
Statements" for further information on the Company's business segments.
The Company's open-access and reorganization plan for its regulated
Natural Gas Utility was approved for implementation by the Montana Public
Service Commission (PSC), effective November 1, 1997. Under the approved
plan, almost all of the regulated Utility's natural gas production assets were
transferred to its unregulated oil and natural gas operations as of that date
at a value $33,600,000 below the existing book value. This difference between
book value and the transfer value and the existing $25,400,000 of regulatory
assets related to the natural gas production assets were approved as a
competitive transition charge (CTC) and will be reflected in rates over a 15-
year period. The assets, liabilities, equity and results of operations of the
regulated Utility's Canadian subsidiary, Canadian-Montana Gas Company,
Limited, have also been included in the unregulated oil and natural gas
operations as of November 1, 1997. Production from these transferred
properties will be sold in the competitive market in the unregulated
operations.
In December 1997, the Company announced that it would offer for sale all
of its Montana electric generating facilities, including 13 dams and four coal-
fired plants of the regulated utility, as well as its unregulated leasehold
interest in another coal-fired unit, its contracts for purchased power from
qualifying facilities and Basin Electric Power Cooperative (Basin) and two
power exchange agreements. The total book value of the electric generating
facilities owned by the Company that are being offered for sale is
approximately $550,000,000 including approximately $10,000,000 of fuel,
materials and supplies. Any amount over book value realized from the sale of
the regulated properties is expected to reduce the amount of transition costs
to be recovered from ratepayers. Correspondingly, any amount below book value
realized from the sale of the regulated properties is expected to be recovered
from ratepayers. Any gain or loss realized from the disposition of the
unregulated leasehold interest, and its related assets and liabilities, will be
reflected in the Consolidated Statement of Income and will not be passed on to
ratepayers. It is the intention of the Company to proceed with the sale
process as tentatively scheduled, however, this divestiture is not a
requirement of the Restructuring Bill as is the case in some other states with
deregulation legislation and the Company may at any time cease to continue
this option. The Company anticipates taking bids in mid-1998. Refer to Part
II, Item 8, Financial Statements and Supplementary Data, Note 4 to the
Consolidated Financial Statements.
In May 1996, the Company was restructured by management into two
divisions: Energy Supply and Energy and Communications Services. The Energy
Supply Division is responsible for coal, oil and natural gas operations, and
power generation including marketing, brokering and energy business
development. The Energy and Communications Services Division is responsible for
the transmission and distribution of electricity and natural gas as well as
telecommunications and regulated energy management services.
Pending regulatory approvals pertaining to the Company's restructuring,
the discussions and financial information which follow are presented in a
Utility and Nonutility format.
UTILITY OPERATIONS:
SERVICE AREA AND SALES: The Utility's service territory comprises
107,600 square miles or approximately 73% of Montana. Within its service
territory, 86% of the state's population resides. It serves approximately
603,000 residents, or 80% of the population within the service territory.
Additionally, energy is provided to cooperatives that serve approximately
76,000 residents. Dominant factors in Montana's economy are agriculture and
livestock, which constitute Montana's largest industry, tourism and recreation,
coal and metals mining, oil and natural gas production, and the forest products
industry, which includes the production of pulp and paper, plywood and lumber.
Electric service is provided to 191 communities, the rural areas
surrounding them and Yellowstone National Park, and natural gas service is
provided to 109 communities. Firm electric power is sold at wholesale to two
rural electric cooperatives. Natural gas is sold at wholesale or transported
to distribution companies in Great Falls, Cut Bank, Shelby, Kevin, Sweetgrass
and Sunburst, Montana.
COMPETITIVE ENVIRONMENT: Refer to Part II, Item 7, "Management's
Discussion and Analysis of Financial Conditions and Results of Operations -
Competitive Environment."
REGULATION AND RATES: The Company's public utility business in Montana
is subject to the jurisdiction of the PSC. The PSC has jurisdiction over the
setting of retail electric and natural gas rates, gas transportation tariffs,
issuance of securities and certain limitations on borrowing by the Company.
The Federal Energy Regulatory Commission (FERC) also has jurisdiction over the
Company, under the Federal Power Act, as a licensee of hydroelectric projects
and as a public utility with respect to wholesale sales of electricity. The
importation of natural gas from Canada requires approval by the Alberta Energy
Resources Conservation Board, the National Energy Board of Canada and the
United States Department of Energy.
The PSC requires the Company to file an Electric Least Cost Resource
Plan (Plan) biannually. The Plan identifies the Company's expectations for
energy and peak requirements, as well as the resources expected to meet those
requirements, and considers societal and environmental costs in addition to
actual dollar costs. The Company requested a waiver of the filing requirements
for a 1997 Plan and proposed to replace the Plan with an alternative planning
cycle in the form of a Status Report on the 1995 Plan. This alternative
planning cycle focuses on the implementation of the 1995 Plan, and explores
electric industry restructuring and the role Integrated Least Cost Planning
will play in the future. The waiver was granted and a Plan Status Report was
filed in March 1997. This planning process is expected to be modified
significantly by the intended sale of Montana generation assets and power
purchase contracts.
Also refer to Part II, Item 7, "Management's Discussion and Analysis of
Financial Conditions and Results of Operations - Competitive Environment."
ELECTRIC UTILITY: Total firm capability of the Utility's electric system
at December 31, 1997 was 1,510,700 kW. Of this capability, the Utility's
generating facilities provided 1,157,400 kW, and 353,300 kW was provided by
firm Electric Utility power purchase and exchange arrangements. The latter
includes deliveries which began in December 1997 from a 98,000 kW seasonal
contract that commenced in 1996. During 1997, two purchase power contracts
totaling approximately 154,000 kW expired and were not renewed. Also refer to
Part II, Item 8, "Financial Statements and Supplementary Data - Note 3 to the
Consolidated Financial Statements" for further discussion of power purchases.
The maximum demand on the resources in 1997 was 1,384,000 kW on January
13, 1997. The total firm capability on that date was 1,452,500 kW. Also on that
date, the Electric Utility's reserve margin, as a percentage of maximum demand,
was 5%.
Regardless of the timing of the sale of the generating assets and power
purchase contracts, the Company is obligated to continue to provide electric
power supply through the transition period to customers in its service
territory who have not had an opportunity to choose to purchase energy from
another power supplier. Such service will require the Company to have
available a power supply sufficient to meet those customers' electric loads.
The Company is evaluating options to meet these needs including market
purchases or a power supply contract with the purchasers of the generating
facilities.
During the year ended December 31, 1997, the sources of the Utility
Operations electric supply were: hydro, 40%; coal, 41%; and purchased power,
19%. The cost of coal burned has been as follows:
Year Ended December 31
1997 1996 1995
Average cost per million Btu's $ 0.59 $ 0.59 $ 0.56
Average cost per ton (delivered) 9.93 10.06 9.67
The Company's electric system forms an integral part of the Northwest
Power Pool consisting of the major electric suppliers in the United States,
Pacific Northwest and British Columbia, and in parts of Alberta, Canada. The
Company is a party to the Pacific Northwest Coordination Agreement which
integrates electric and hydroelectric operations of the 18 parties associated
with generating facilities in the Columbia River Basin. The Company is also a
member of the Western Systems Coordinating Council, organized by 84 member
systems and 21 affiliates in the 14 western states, British Columbia, Alberta
and Mexico to assure reliability of operations and service to their customers.
The Company participates in an interconnection agreement with The Washington
Water Power Company, Idaho Power Company, and PacifiCorp, providing for the
sharing of transmission capacity of certain lines on their respective
interconnected systems. The Company also operates, in coordination with its
own transmission lines and facilities, the transmission lines and facilities
which are jointly owned by the utility owners of the four Colstrip generating
units. The Company and the Western Area Power Administration have transmission
interconnection and agreements which provide for the mutual use of excess
capacity of certain lines on each party's system for the transmission of power
east of the Continental Divide in Montana and for the firm use of certain of
the Company's transmission lines to deliver government power. Also refer to
Part II, Item 7, "Management's Discussion and Analysis of Financial Conditions
and Results of Operations - Competitive Environment" for discussion of the
Company's participation in the formation of an independent grid operator called
"IndeGo".
NATURAL GAS UTILITY: Natural gas supply requirements in 1997 totaled
23,242 Mmcf, of which 11,450 Mmcf were from Montana and 9,930 Mmcf from Canada.
The Gas Utility produced 36% of the Montana natural gas and its Canadian
subsidiaries produced 41% of the Canadian natural gas through October 31, 1997.
A total of 1,826 Mmcf, or approximately 8% of the natural gas supply
requirements for the year, was purchased for the period November 1, 1997
through December 31, 1997 from an unregulated subsidiary, Montana Power Gas
Company (MP Gas).
Total 1998 natural gas requirements, estimated to be 21,729 Mmcf, are
anticipated to be supplied from MP Gas and other purchase contracts.
Approximately 30% of purchases under contracts with outside suppliers and the
Company's unregulated affiliate, MP Gas, expire each year beginning in 1999
through 2002. As a result of the natural gas restructuring order, the Company
anticipates these contracts will be allowed to expire and will not be
renegotiated.
As a result of the natural gas restructuring order effective on
November 1, 1997, natural gas customers with annual consumption of 5,000
dekatherms or more are eligible to be served through unbundled gas
transportation service. Consequently, the number of customers previously
receiving bundled service who have elected unbundled transportation service has
increased from 25 to over 175. Substantially all of these customers obtain
their supplies directly from other sources.
Total volumes of natural gas transported were 26,020 Mmcf, 26,969 Mmcf
and 27,325 Mmcf for 1997, 1996 and 1995 respectively. The 1998 transportation
volumes are anticipated to be 27,700 Mmcf. Also, the Company anticipates
filing a core aggregation pilot program (pilot program) in 1998 with the PSC,
providing supplier choice for residential and small commercial/industrial
customers. The pilot program will allow up to 500 Mmcf of the Utility's core
customers to purchase their gas supply from other sources beginning with the
1998/1999 heating season. Assuming the pilot program is successful, all
customers will have supplier choice by 2001. The regulated Natural Gas Utility
will continue to provide gas transmission, storage and distribution service to
its customers.
NONUTILITY OPERATIONS:
GENERAL: The coal and lignite business is conducted through several
subsidiaries. Western Energy Company (Western) holds leases and rights on coal
properties in Montana and operates the Rosebud Mine located in eastern Montana.
Western's subsidiaries, Western SynCoal Company (SynCoal) and Syncoal Inc., own
a patented coal enhancement process. SynCoal and Syncoal Inc. own the Rosebud
SynCoal Partnership, which owns and operates a coal enhancement process
demonstration plant located at the Rosebud Mine. Northwestern Resources Co.
(Northwestern) holds leases on lignite properties in Texas and operates the
Jewett Mine.
The oil and natural gas business is conducted in the United States
through North American Resources Company (NARCO) and MP Gas, and in Canada
through Altana Exploration Company (Altana), Roan Resources, Ltd. (Roan) and
Canadian Montana Gas Company (CMG). As a result of the PSC-approved Natural Gas
Utility's restructuring filing, almost all of the regulated Natural Gas
Utility's production assets, including those of CMG, were transferred to the
unregulated oil and natural gas operations in November 1997. MP Gas was created
to hold the previously regulated Montana reserves.
The independent power business, consisting of Colstrip 4 Lease Management
Division and Continental Energy Services, Inc. (CES), manages long-term power
sales and develops and invests in nonutility power projects and other energy-
related businesses. The 222 megawatt leasehold interest in Colstrip Unit 4 and
its related assets and liabilities are intended to be sold with the regulated
electric generating facilities and power purchase contracts.
The telecommunication business is conducted through Touch America, Inc.
Touch America offers four primary services to customers: equipment, private
lines, Internet and long distance services. Touch America also markets and
maintains PBX and key systems, call accounting systems, computer telephone
interface and voice mail systems. Its system includes private, dedicated
communication lines throughout Montana on a digital microwave and the expanded
3,000 mile fiber optic network from Seattle, Washington to St. Paul, Minnesota
and from Denver, Colorado to the Canadian Border.
Electricity, natural gas and oil commodity trading and marketing and
related energy services are provided by the Company's new subsidiary, The
Montana Power Trading and Marketing Company (MPT&MC). These traditionally
wholesale activities will be extended to other regions of the country and into
retail markets as they become deregulated.
Other Nonutility businesses are conducted by various subsidiaries, none
of which is a significant subsidiary.
COMPETITIVE ENVIRONMENT: Current production from the Rosebud and Jewett
Mines is sold under long-term contracts to mine-mouth customers. The Rosebud
Mine supplies Colstrip Units 1 through 4 under the terms of contracts
obligating the Colstrip Units to purchase all of the fuel required by the
plants from the Rosebud Mine. The Jewett Mine sells its entire production to
the two 800 MW Limestone Units owned by Houston Lighting & Power (HL&P). See
Part II, Item 8, "Financial Statements and Supplementary Data - Note 2 to the
Consolidated Financial Statements" for further information on this supply
agreement. The coal supply agreements for the Colstrip Units provide for
periodic price re-openers. The Company expects to profitably serve these
contracts over their remaining lives. The Rosebud Mine has production capacity
that exceeds the mine-mouth customers' fuel requirements. The Rosebud Mine
faces competition from Montana and Wyoming Powder River Basin producers
located south of the mine. These producers generally experience lower
operating costs and the Wyoming coal also has a lower sulfur content. The
Company does not anticipate significant spot market sales from the Rosebud
Mine for the foreseeable future. Western does not anticipate any significant
contract changes to result from the sale of the Company's generation assets.
The Company and the other owners of the Colstrip units are involved in
on-going mediation to restructure the relationship of these other owners and
the Company, as a joint-owner of the plants and fuel supplier. The outcome of
the restructuring mediation is uncertain.
The Nonutility oil and natural gas businesses compete with major oil and
natural gas companies, other independent and individual producers and operators
to acquire property, to develop, produce and market oil and natural gas and to
contract for equipment and services. The Company has production, development
and long-term marketing abilities, experience in acquiring properties, and the
financial resources to enable it to compete effectively.
Most of CES' current revenues are derived from long-term power supply
contracts. Some long-term power supply contracts in the nonutility power
industry are under pressure from customers to reconsider pricing.
The telecommunications business competes with major and regional
companies to provide long distance, Internet and private line network services,
and telecommunication equipment sales and maintenance. Despite the intense
price competition for these products and services, the telecommunication
business unit competes by maintaining low costs.
COAL OPERATIONS: Western's Rosebud Mine is at Colstrip, Montana, in the
northern Powder River Basin, where coal is surface-mined and, after crushing,
sold without further preparation. Western's principal customers from this mine
are the owners of the four mine-mouth Colstrip units. These customers
accounted for approximately 91% of 1997 coal sales volumes. The remainder of
Rosebud coal was sold under spot-market sale agreements and contracts in
Minnesota, North Dakota and Montana.
During 1997, Western mined and sold 9,127,000 tons, of which
3,013,000 tons were sold to the Company. Western's Rosebud Mine production is
estimated to be 9,818,000 tons in 1998, as a result of expected Colstrip
Units 3 & 4 increased coal purchases, and 9,868,000 tons in 1999.
Northwestern's Jewett Mine, located in central Texas, supplies surface-
mined lignite under a long-term lignite sale agreement (LSA) to the two
electric generating units, located adjacent to the mine, that are owned by
HL&P. Total deliveries in 1997 were 9,187,000 tons. The estimated production
for 1998 and 1999 are 8,884,000 and 8,933,000 tons, respectively. After 2000,
production is estimated to be approximately 9,100,000 tons annually. In
litigation regarding the agreement, HL&P obtained summary judgment from the
trial court declaring that the LSA is a requirements contract only for
lignite. Thus, the trial court concluded HL&P may substitute other fuel for
lignite at the plant. While Northwestern intends to appeal this judgment, the
eventual resolution of this matter may affect future deliveries.
OIL AND NATURAL GAS OPERATIONS: Oil and natural gas operations are
engaged in exploration, production, and marketing of oil and natural gas in the
United States and Canada. U.S. producing oil and natural gas properties are
principally located in the states of Wyoming, Colorado, Oklahoma and Montana.
Canadian properties are principally located in the Province of Alberta, Canada.
A subsidiary has entered into agreements to supply 107 Bcf of natural gas to
four co-generation facilities over a period of 7 to 13 years for which there is
sufficient proven, developed and undeveloped reserves and controls related
sales of production sufficient to supply all of the remaining natural gas
required by those agreements. None of the reserves are dedicated to supply
these agreements.
Natural gas production in both the United States and Canada is currently
sold pursuant to short-term, spot-market and long-term contracts. Approximately
71,360 Mmcf, or 68.1% of Canadian natural gas reserves, are dedicated to long-
term contracts expiring at various times through 2005. In addition to serving
these contracts, the Company intends to concentrate its efforts on natural gas
production in support of the expanding market development objectives.
INDEPENDENT POWER OPERATIONS: Independent power operations develops,
acquires, operates and maintains, and manages facilities and resources to
provide electricity and other energy-related services.
Colstrip 4 Lease Management Division sells the Company's 222 megawatt
share of Colstrip Unit 4 generation principally to the Los Angeles Department
of Water and Power and to Puget Sound Energy, Inc. under contracts with a term
through December 29, 2010. The leasehold interest and its related assets and
liabilities and contract obligations are intended to be sold with the regulated
electric generating facilities and power purchase contracts.
CES develops and invests in power projects, and currently holds
ownership interests in seven operating, natural gas fired projects located in
Texas, New York, Washington and the United Kingdom, one heavy oil-fired
project located in Jamaica and one gas-fired independent power project under
construction in Pakistan. CES, through a wholly-owned subsidiary, is the
managing general partner of a 255 MW project located in Texas. In addition,
CES is participating with others in the development of a coal-fired project in
India and an 800 MW gas-fired project in Texas.
CES holds a 50% interest in North American Energy Services Company,
which provides energy-related support services including the operation and
maintenance of power plants.
TELECOMMUNICATIONS OPERATIONS: Touch America provides long distance,
Internet, private line, and telecommunications equipment sales and services to
customers in Montana, Idaho, Washington, Oregon, Minnesota, Colorado and
Wyoming. Touch America also markets and maintains PBX and key systems, call
accounting systems, computer telephone interface and voice mail systems.
The telecommunications system includes private, dedicated communication
lines throughout Montana on a digital microwave and fiber network. Touch
America has expanded its fiber network, allowing access to markets extending
from Seattle, Washington to St. Paul, Minnesota and from Denver, Colorado to
the Canadian Border. The expanded 3,000 mile fiber optic network was completed
in mid-1997, offering increased private line service and sales options as well
as increased long distance service and Internet efficiencies. The fiber optic
network is being further expanded in 1998 through Touch America's participation
in FTV Communications LLC (FTV), a limited liability company owned equally by
Touch America, Inc., FirstPoint Communications, Inc. (a subsidiary of Enron),
and Vyvx (a subsidiary of Williams Communications Group). FTV will construct
and own a 1,620-mile fiber optic network route from Portland to Los Angeles
through Boise, Salt Lake City and Las Vegas. Touch America is the Construction
Manager for the project. FTV has successfully completed the sale of a portion
of the fiber on the project during 1997 and has also entered into an exchange
agreement on a segment of the route between Las Vegas and Los Angeles. The
project is scheduled to be completed in December 1998.
ENVIRONMENT:
For information on Environment see Part II, Item 7, "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Environmental Issues."
EMPLOYEES:
At December 31, 1997, the Company and its subsidiaries employed
2,903 persons, including 385 employees at the jointly owned Colstrip Units 1-4.
Of the 2,903 persons, 1,038 are members of collective bargaining units
consisting of 16 unions. Current union contracts will expire at various times
during the next 4 years, with 14 contracts expiring in 1998. The Company
expects to complete negotiation of the contracts through the normal course of
business consistent with its successful history of contract renegotiations. It
is expected that approximately 500 employees, union and non-union, may be
directly affected by the sale. See Part II, Item 8, "Financial Statements and
Supplementary Data - Note 4 to the Consolidated Financial Statements" for
further information regarding the sale.
FOREIGN AND DOMESTIC OPERATIONS:
Financial information relating to the segment information for foreign and
domestic operations and export sales are not considered material.
ITEM 2. PROPERTIES
UTILITY OPERATIONS:
The Company's Mortgage and Deed of Trust (Mortgage) imposes a first
mortgage lien on all physical properties owned, exclusive of subsidiary company
assets, and certain property and assets specifically excepted. The Company's
use of the proceeds from the sale of its Montana generating facilities may be
subject to restrictions imposed by the Mortgage.
ELECTRIC PROPERTIES: The Company's Utility electric system extends
through the western two-thirds of Montana. Generating capability is provided
by four coal-fired thermal generation units, with total net capability
available to the Utility of 683,000 kW, and 12 hydroelectric projects and one
storage dam, with total net median water capability of 474,400 kW. See Part
II, Item 8, "Financial Statements and Supplementary Data - Note 4 to the
Consolidated Financial Statements." The thermal units are (1) Colstrip Unit 3,
which has a net capability of 740,000 kW, of which the Company owns 222,000 kW,
(2) Colstrip Units 1 and 2, with a combined net capability of 614,000 kW, of
which the Utility owns 307,000 kW, and (3) the wholly-owned 154,000 kW Corette
Plant. Western supplies all of the Colstrip coal requirements under long-term
contracts. The Corette Plant is supplied under a short-term contract from a
Wyoming mine. Reliability of service is enhanced by the location of
hydroelectric generation on two separate watersheds with different
precipitation characteristics and by various sources of thermal generation.
In addition to the Utility's hydroelectric and thermal resources, it
currently receives electricity through 18 contracts totaling 353,300 kW of firm
winter peak capacity. These contracts vary in type, size, seller and ending
dates. See Part II, Item 8, "Financial Statements and Supplementary Data -
Note 4 to the Consolidated Financial Statements" for more information
concerning the Company's intended sale of its generation assets.
Hydroelectric projects are licensed by the FERC under licenses that
expire on varying dates through 2035. The Company is in the process of
relicensing its nine dams located on the Missouri and Madison rivers. See Part
II, Item 8, "Financial Statements and Supplementary Data - Note 2 to the
Consolidated Financial Statements."
At December 31, 1997, the Utility owned and operated 6,889 miles of
transmission lines and 15,639 miles of distribution lines.
The following table represents average revenues received per kWh by
customer classification for electricity from all sources for the years 1997,
1996 and 1995.
Year Ended December 31
Customer Classification 1997 1996 1995
Residential $0.064 $0.061 $0.059
Commercial 0.059 0.055 0.052
Industrial 0.041 0.041 0.040
Sales for Resale 0.019 0.018 0.021
Government and Municipal 0.085 0.077 0.073
NATURAL GAS PROPERTIES: The Utility currently produces minimal amounts
of natural gas from fields in southern Montana and Wyoming. The Utility
transferred almost all of its natural gas production properties in the United
States and all of its Canadian natural gas production properties to an
unregulated subsidiary on November 1, 1997, as a result of the Company's
natural gas restructuring filing with the PSC. The assets, liabilities, equity
and results of operations of the regulated Utility's Canadian subsidiary,
Canadian-Montana Gas Company, Limited, have also been included in the
unregulated oil and natural gas operations as of that date. Except where
noted, the following disclosures are based on activity for the twelve months of
1997.
All of the Utility's natural gas customers are served from its
transmission system which extends through the western two-thirds of Montana.
System reliability is enhanced by four natural gas storage fields which enable
the Utility to store natural gas in excess of system load requirements during
the summer for delivery during winter periods of peak demand.
At December 31, 1997, the Gas Utility and its subsidiaries owned and
operated 2,104 miles of natural gas transmission lines and 3,451 miles of
distribution mains.
All natural gas volumes are at a pressure base of 14.73 psia at
60 degrees Fahrenheit, except for those volumes used to compute the average
revenues by customer classification.
For information pertaining to the Company's net recoverable utility
natural gas reserves, see Part II, Item 8, "Financial Statements and
Supplementary Data."
In addition to owned reserves of 2,396 Mmcf, the Utility at December 31,
1997, controlled 23,407 Mmcf of proven reserves in the United States and
2,365 Mmcf in Canada under purchase contracts. The Utility also has a contract
with the Nonutility oil and gas operations for the delivery of 47,550 Mmcf of
natural gas over the next five years as the Utility transitions to full
customer choice in mid-2002.
During 1997, the Natural Gas Utility sold properties in the United States
to outside parties, which resulted in reserve revisions of 15,086 Mmcf. The
Utility also transferred 61,642 Mmcf of United States reserves and 107,870 Mmcf
of Canadian reserves to the unregulated oil and natural gas operations.
Utility natural gas reserve estimates have not been filed with any other
federal or any foreign governmental agency during the past twelve months.
Certain lease and well data, with respect only to owned wells, are filed with
the Internal Revenue Service for tax purposes.
Total produced, royalty and purchased natural gas volumes in Mmcf during
the last three years were as follows:
United States Canada
Produced Royalty Purchased Produced Royalty Purchased
1995 5,176 632 7,292 4,650 735 3,031
1996 5,055 230 6,749 4,694 950 4,850
1997 3,764 292 8,290 3,402 679 7,132
The following table presents information as of December 31, 1997,
pertaining to the Utility natural gas wells and the owned or leased properties
in which they are located.
United States
Gross productive wells 11
Net productive wells 11
Gross wells with multiple completions 1
Net wells with multiple completions 1
Gross producing acres 3,545
Net producing acres 3,545
Gross undeveloped acres -
Net undeveloped acres -
These properties are located in Montana and Wyoming.
The following table presents information on Utility natural gas
development wells drilled during 1997, 1996 and 1995. No exploratory wells
were drilled in the periods specified.
United States Canada
1997 1996 1995 1997 1996 1995
Net productive development
wells - 2.00 12.81 - 7.00 4.00
Net dry development wells - - 1.60 - - 4.00
The following table presents average revenues received per Mcf by
customer classification for natural gas from all sources for the years 1997,
1996 and 1995. Revenues per Mcf are computed based on volumes at varying
pressure bases as billed.
Year Ended December 31
Customer Classification 1997 1996 1995
Residential $4.72 $4.72 $4.74
Commercial 4.53 4.54 4.54
Industrial 4.30 4.32 4.33
Other gas utilities 4.04 3.41 3.64
The following table presents the average production cost per Mcf for
produced utility natural gas, in U. S. dollars, for the three years 1997, 1996
and 1995.
United States Canada
1995 $1.10 $0.34
1996 0.94 0.32
1997 * 0.89 0.40
* - Average production costs per Mcf for 1997 were computed based on 10
months of activity since the assets were transferred to the unregulated
operations on November 1, 1997.
NONUTILITY OPERATIONS:
COAL PROPERTIES: Western leases and produces coal from Montana
properties. Northwestern leases and produces lignite from properties in Texas.
Western's subsidiaries, Western SynCoal Company (SynCoal) and Syncoal Inc., own
a patented coal enhancement process. SynCoal and Syncoal Inc. own the Rosebud
SynCoal Partnership, which owns and operates a coal enhancement process
demonstration plant at the Rosebud Mine.
Western has coal mining leases covering approximately 519,000,000 proved
and probable, and recoverable, tons of surface-mineable coal reserves averaging
less than 1.6 pounds of sulfur dioxide per million Btu at Colstrip.
Approximately 228,000,000 tons of these reserves are committed to present
contracts, including requirements of the Colstrip Units.
Northwestern has lignite mining leases in central Texas at the Jewett
Mine covering approximately 162,200,000 proved and probable, and recoverable,
tons of surface-mineable lignite reserves. Northwestern has contracted all of
these reserves to Houston Lighting and Power Company, which owns two electric
generating units located adjacent to the mine.
In addition, Northwestern has proved and probable, and recoverable
reserves totaling approximately 144,800,000 tons located in central Texas.
These reserves are in close proximity to the Jewett Mine.
In the fourth quarter of 1997, Horizon Coal Services, Inc. (Horizon) sold
its non-producing coal property in Wyoming containing approximately 684,000,000
proved and probable, and recoverable tons of compliance quality coal reserves.
The Company, through its wholly owned subsidiary, Basin Resources Inc.
owns approximately 36,000 acres of land in southern Colorado associated with a
former coal mining operation. The improvements have been removed and the land
has been reclaimed. The Company is currently negotiating the sale of this
property.
OIL AND NATURAL GAS PROPERTIES: During 1997 the oil and gas operations
completed two major acquisitions. The Company purchased Vessels Energy's
(Vessels) oil and gas assets in Colorado's Denver-Julesburg (D-J) Basin. With
the completion of this acquisition late in 1997, annual hydrocarbon production
in the D-J Basin is expected to increase from 3,800 Mmcf of natural gas to
approximately 7,300 Mmcf, from 146,000 barrels of oil to 296,000 barrels, and
from 233,000 barrels of natural gas liquids to 1,613,000 barrels. The
Nonutility U.S. properties include more than 565 wells, operating some 470 of
them, and include an 800-mile gas-gathering system, which the Company also
operates. With the Vessels acquisition, the Company also acquired a natural
gas processing and fractionating plant. The plant and gathering system is
being integrated with the Company's existing Fort Lupton plant. This purchase
allows the Company to enter the gathering and fractionated liquids businesses.
The Company, through a Canadian subsidiary, purchased the stock of Questar
Exploration Inc and in January 1998, these assets were merged into the Canadian
subsidiary. This acquisition is expected to increase hydrocarbon production in
Alberta by 6,144 Mmcf and 298,000 barrels of natural gas liquids in 1998.
Oil and gas operations also completed the disposition of non-strategic
oil and natural gas properties in Kansas, Texas, North Dakota, Oklahoma, and
Alberta, Canada. The proceeds from these sales were applied to purchase the
above natural gas acquisitions.
All Nonutility natural gas volumes are at a pressure base of 14.73 psia
at 60 degrees Fahrenheit.
Nonutility oil and natural gas reserve estimates have not been filed with
any other federal or any foreign government agency during the past twelve
months. Certain lease information and well data, only with respect to owned
wells, is filed with the Internal Revenue Service for tax purposes.
The following table presents information on produced oil and natural gas
average sales prices and production costs in U.S. dollars for 1997, 1996 and
1995.
<TABLE>
<CAPTION>
Year Ended December 31
1997 1996 1995
United United United
States Canada States Canada States Canada
<S> <C> <C> <C> <C> <C> <C>
Average sales price:
Per Mcf of natural gas $ 1.94 $ 1.38 $ 1.54 $ 1.10 $ 1.21 $ 0.99
Per barrel of oil 20.42 18.77 19.74 16.88 16.55 15.29
Per barrel of natural gas liquids 10.12 15.64 10.56 14.44 8.17 11.33
Average production cost:
Per barrel of oil equivalent $ 4.13 $ 3.02 $ 3.94 $ 3.10 $ 3.36 $ 2.90
</TABLE>
Natural gas production was converted to barrel of oil equivalents based
on a ratio of 6 Mcf to 1 barrel of oil.
Nonutility oil, natural gas and natural gas liquids production was sold
under short-term and long-term contracts at posted prices or under forward
market arrangements. From 1996 to 1997, Nonutility average sales prices
changed due to fluctuations in the market. Nonutility average production cost
in the U.S. reflects higher lease operating expenses due to non-recurring
environmental and compliance work required on the newly acquired Vessels
properties. As a result of the completion of this non-recurring work in 1997,
future production costs are expected to decrease.
Information on the Nonutility natural gas and oil wells and the owned or
leased acreage in which they are located, as of December 31, 1997, is presented
below.
United
States Canada
Gross productive natural gas wells 1,153 295
Net productive natural gas wells 768.15 242.72
Gross productive oil wells 118 101
Net productive oil wells 117.00 68.32
Gross producing acres 522,234 265,443
Net producing acres 338,911 185,476
Gross undeveloped acres 355,853 252,868
Net undeveloped acres 206,866 177,108
The wells located in Canada include multiple completions of 21 gross
productive natural gas wells or 18.25 net productive gas wells. The U.S. wells
listed above include multiple completions of 181 gross productive natural gas
wells or 131.41 net productive natural gas wells, and 9 gross productive oil
wells or 9 net productive oil wells.
The foregoing acreage located in the United States and Canada are
primarily in the Rocky Mountain states and Alberta.
During 1998, total exploration, acquisition and development expenditures
(expense and capital) are anticipated to be approximately $34,442,000 in the
United States and approximately $22,423,000 in Canada.
The following table presents information on Nonutility oil and natural
gas exploratory and development wells drilled during 1997, 1996 and 1995.
United States Canada
1997 1996 1995 1997 1996 1995
Net productive natural gas
exploratory wells 1.86 0.33 2.99 4.30 0.55 0.50
Net productive oil
exploratory wells 1.00 - 1.00 - 2.23 -
Net productive natural gas
development wells 41.50 2.58 6.23 1.30 1.83 -
Net productive oil
development wells 2.87 - 1.34 15.11 9.78 7.38
Net dry exploratory wells 0.34 1.75 2.50 1.13 0.50 1.69
Net dry development wells 0.25 1.81 4.24 - 0.04 0.50
For information on properties acquired, see Part II, Item 8, "Financial
Statements and Supplementary Data."
INDEPENDENT POWER PROPERTIES: Independent power operations sell power
from the Company's 222 MW Colstrip 4 leased interest and associated common and
transmission facilities. The leasehold interest and its related assets and
liabilities and contract obligations are intended to be sold with the regulated
electric generating facilities and power purchase contracts.
The Company, through its independent power operations, also partially
owns or has contract rights in a number of Nonutility power generation
projects. The interests in these projects are not being offered for sale with
the regulated electric generating facilities:
<TABLE>
<CAPTION>
Projects in Operation:
IPG
Share
of
Rated Rated
Location Capa- Capa-
(Commercial Ownership city city Customer
Project Operation) or Interest MW MW Electricity Thermal
<S> <C> <C> <C> <C> <C> <C>
Encogen One (1) Sweetwater, TX 49.9% 255 128 Texas Utilities U.S. Gypsum
(1989) Electric Co.
Tenaska-Paris(2) Paris, TX 10.0% 223 22 Texas Utilities Campbell
(1989) Electric Co. Soup Co.
Encogen Four Buffalo, NY 49.5% 62 31 Niagara Mohawk Outokumpu
(1992) Power Corp. AmBrass
Lockport(2) Lockport, NY 22.3% 168 37 New York State Harrison
(1993) Electric & Radiator
Gas Corp.
Teesside United Kingdom 3.2%(3) 1,725 56 Various U.K. --
(1993) customers
Tenaska- Ferndale, WA 25.1% 245 61 Puget Sound Tosco Corp.
Ferndale (1994) Energy
Doctor Bird Old Harbour, 17.6% 74 13 Jamaica Public None
Jamaica Service
(1995)
Tenaska- Cleburne, TX 13.4% 258 35 Brazos REA City of
Cleburne (1997) Cleburne
TOTAL IPG SHARE OF RATED CAPACITY MW 383
<FN>
(1) CES is the managing partner of this project.
(2) These co-generation facilities have a long-term contract with NARCO (a Nonutility
subsidiary) to purchase a portion of their natural gas supply.
(3) Interest is the contractual right to utilize one-third of 168 megawatts of
capacity to produce electricity for sale from a 1,725 megawatt natural gas-fired
electric generating facility.
</FN>
</TABLE>
<TABLE>
<CAPTION>
Projects Under Construction:
IPG
Share
of
Location Rated Rated
(Anticipated Capa- Capa-
Commercial Ownership city city Customer
Project Operation) or Interest MW MW Electricity Thermal
<S> <C> <C> <C> <C> <C> <C>
Tenaska- Frederickson, WA 25.3% 248 63 Bonneville None
Frederickson (4) Power Admn
Uch Power Uch Pakistan 3.2% 586 19 Pakistan Water None
Limited (1998) & Power
Department
<FN>
(4) Construction is approximately 50% complete but has been suspended due to a dispute
with the Bonneville Power Administration.
</FN>
<CAPTION>
Projects Under Development:
IPG
Share
of
Rated Rated
Devel- Capa- Capa-
opment city city Customer
Project Location Interest MW MW Electricity Thermal
<S> <C> <C> <C> <C> <C> <C>
India- State of Andhra (5) 500 (5) State of Andhra None
Krishnapatnam Pradesh Pradesh
Tenaska Grimes County, 50% 800 200 Power Team, a None
Frontier Texas division of PECO
(Grimes Energy Company
County)
<FN>
(5) The ownership interest, if any, has not been determined.
</FN>
</TABLE>
TELECOMMUNICATIONS PROPERTIES: Touch America has a 3,000-mile fiber
optic network covering a seven state region extending from Seattle, Washington
to St. Paul, Minnesota and from Denver, Colorado to the Canadian border.
Approximately 600 miles of the network from Denver, Colorado to Billings,
Montana is held through an indefeasible right of use (IRU) which extends
through December 2010 and is subject to two ten year extensions, at Touch
America's option. Approximately 2,000 miles of the network from Seattle,
Washington to St. Paul, Minnesota is held through an IRU extending through
early 2022. Touch America continues to expand its network capacity. The
additional 1,620 miles of fiber network through FTV will widen Touch America's
service territory to 11 states. In January 1997, the Company acquired 12 PCS
licenses in 12 marketing areas between Minneapolis, Minnesota and Seattle,
Washington along the route of the fiber optic network, which presents an
opportunity for wireless telephone service in that region.
ITEM 3. LEGAL PROCEEDINGS
The Company and North American Resources Company (NARCO), a company
subsidiary, are defendants in litigation filed on October 30, 1995 in the
United States District Court for the District of Montana by Paladin Associates,
Inc. (Paladin). Paladin is a natural gas broker transporting natural gas on
the Company's pipeline system. Paladin alleges the Company, NARCO and
Northridge Petroleum Marketing, a Canadian corporation in which a former member
of Entech's Board of Directors was a principal, violated antitrust law by,
among other things, denying Paladin free access to the market for the sale of
natural gas. Paladin also alleges various state law claims for breach of
contractual obligations, interference with business, and negligence arising out
of the Company's offer of interruptible storage service and interruptible off-
system transportation to third parties. Damages claimed by Paladin from the
alleged antitrust violations measure approximately $10,000,000, which would be
trebled if there is liability. Damages Paladin seeks for the alleged state law
violations have not been quantified. Trial of this matter is not scheduled, but
is expected to occur in 1998. While the outcome of this litigation cannot be
predicted, the Company is confident of its defenses and will vigorously pursue
them.
In 1994, the Company entered into a 15-year agreement to purchase up to
98 megawatts of capacity from Basin Electric Power Cooperative (Basin) annually
between November and the following April. Delivery of power was to begin in
November 1996. The Company rescinded the agreement after Basin's refusal to
provide electricity at the delivery points the Company requested under the
terms of the agreement. On November 5, 1996, Basin sued the Company in Federal
District Court in North Dakota seeking specific performance, a stay of the
litigation, and an order compelling the Company to arbitrate the dispute. On
March 20, 1997, the court ordered arbitration of all claims and counterclaims,
except counterclaims against Basin regarding antitrust and wrongful
interference with business or trade. On December 19, 1997, the arbitrator
denied the Company's claims, affirming the Company's obligations to purchase
power under the agreement. In December 1997, the Company recognized $7,400,000
as expense representing all amounts that would have been payable under the
agreement.
Refer to Part II, Item 7, "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Environmental Issues" and to
Part II, Item 8, "Financial Statements and Supplementary Data - Note 2 to the
Consolidated Financial Statements" for further information pertaining to legal
proceedings.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
EXECUTIVE OFFICERS OF THE REGISTRANT
The Montana Power Company Officers:
On December 31, 1997, D. T. Berube, 64, retired as Chairman of the Board.
On July 1, 1997 he retired as Chief Executive Officer.
On January 1, 1998, R. P. Gannon, 53, was elected Chairman of the Board.
He was elected Chief Executive Officer on July 1, 1997. He had previously
served as Vice Chairman of the Board until January 1, 1998, as President since
January 1, 1990 and as Chief Operating Officer - Utility Operations from 1992-
1996.
In 1996, J. P. Pederson, 55, was elected Vice President, Chief Financial
and Information Officer. He had previously served as Vice President and Chief
Financial Officer from 1991-1996.
In 1996, P. K. Merrell, 45, was elected Vice President, Human Resources
and Secretary. She had previously served as Vice President and Secretary from
1993-1996 and as Secretary from 1992-1993.
In 1991, M. E. Zimmerman, 49, was elected Vice President and General
Counsel.
In 1996, D. S. Smith, 54, was elected Controller. He had previously
served as Controller for Entech from 1988-1996.
In 1996, E. M. Senechal, 48, was elected Treasurer. She had previously
served as Vice President and Treasurer for Entech from 1984-1996.
In 1997, W. S. Dee, 57, was elected Vice President, Marketing. He had
previously been employed as policy teacher and consultant with Leo Burnett,
Inc., an advertising agency, from 1993 to 1996. He had also served as Chief
Executive Officer and owner of W. S. Dee - Omega Beverages, a beverage
manufacturing company, from 1991 to 1992.
Energy and Communications Services Division:
In 1996, J. D. Haffey, 52, was elected Executive Vice President and Chief
Operating Officer. He had previously served as Vice President - Administration
and Regulatory Affairs from 1993-1996 and as Vice President - Regulatory
Affairs for the Utility Division from 1987-1993.
In 1996, D. A. Johnson, 52, was elected Vice President, Distribution
Services. He had previously served as Vice President - Utility Services from
1993-1996 and as Vice President - Gas Supply and Transportation for the Utility
Division from 1984-1993.
In 1996, P. J. Cole, 40, was elected Vice President, Business Development
and Regulatory Affairs. He had previously served as Treasurer for the Utility
Division from 1993-1996, as Assistant Treasurer from 1992-1993 and as Manager,
Corporate Financial Planning and Analysis from 1986-1992.
In 1996, M. J. Meldahl, 48, was elected Vice President, Communication
Services. He had previously served as Vice President, Technology Division -
Entech from 1988-1996.
In 1997, W. A. Pascoe, 41, was elected Vice President, Transmission
Services. He had previously served as Assistant Vice President, Transmission
Services from May 1996 to April 1997 and as Manager of Transmission and Power
Transactions from 1990-1996.
Energy Supply Division:
In 1996, R. F. Cromer, 52, was elected Executive Vice President and Chief
Operating Officer. He had previously served as President and Chief Operating
Officer - Continental Energy Services, Inc. from 1992-1996 and as Vice
President and General Manager, Continental Energy Services from 1989-1992.
In 1996, A. K. Neill, 60, was elected Executive Vice President, Energy
Supply. He had previously served as Executive Vice President - Generation and
Transmission 1994-1996 and as Executive Vice President - Utility Services from
1987-1994.
In 1996, M. C. Enterline, 49, was elected Vice President - Colstrip
Project Division for the Energy Supply Division. He had previously served as
Vice President, Colstrip Project Division from 1995-1996, as Manager of
Business and Change Management from 1994-1995 and as Superintendent of Colstrip
Units l and 2 from 1988-1994.
In 1996, R. P. Madison, 60, was elected Vice President, Oil and Gas
Operations, Energy Supply Division. He had previously served as Vice
President, Entech Oil Division from 1988-1996.
In 1996, P. Gatzemeier, 47, was elected Vice President, Coal Operations.
He had previously served as Vice President, Entech Coal Division from 1992-
1996.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
Common Stock Information
The common stock of the Company is listed on the New York and Pacific
Stock Exchanges. The following table presents the high and low sale prices of
the common stock of the Company as well as dividends declared for the years
1997 and 1996. The number of common shareholders of record on December 31,
1997, was 41,868.
Dividends
Declared
per
1997 High Low Share
1st quarter $ 22.625 $ 21.000 $ 0.40
2nd quarter 23.312 21.000 0.40
3rd quarter 26.625 21.000 0.40
4th quarter 32.250 24.125 0.40
Dividends
Declared
per
1996 High Low Share
1st quarter $ 23.000 $ 21.250 $ 0.40
2nd quarter 22.750 21.000 0.40
3rd quarter 22.375 20.625 0.40
4th quarter 22.000 20.750 0.40
<TABLE>
<CAPTION>
ITEM 6. SELECTED FINANCIAL DATA
The Montana Power Company and Subsidiaries
Balance Sheet Items (000)
1997 1996 1995
<S> <C> <C> <C> <C>
Assets:
Utility plant $2,216,198 $2,236,309 $2,156,959
Less accumulated depreciation
and depletion 684,960 705,119 663,216
Net Utility plant 1,531,238 1,531,190 1,493,743
Nonutility property 781,406 666,679 633,079
Less accumulated depreciation
and depletion 260,567 256,489 252,612
Net Nonutility property 520,839 410,190 380,467
Total net plant and property 2,052,077 1,941,380 1,874,210
Other assets 749,619 756,835 711,881
Total Assets $2,801,696 $2,698,215 $2,586,091
Liabilities:
Common shareholders' equity $1,037,534 $ 999,657 $ 976,043
Unallocated stock held by trustee
for retirement savings plan (25,945) (28,360) (30,565)
Preferred stock 57,654 57,654 101,416
Mandatorily redeemable preferred
securities of trust 65,000 65,000
Long-term debt 653,168 633,339 616,574
Other liabilities 1,014,285 970,925 922,623
Total Liabilities $2,801,696 $2,698,215 $2,586,091
</TABLE>
<TABLE>
<CAPTION>
ITEM 6. SELECTED FINANCIAL DATA
The Montana Power Company and Subsidiaries
Balance Sheet Items (000)
1994 1993 1992
<S> <C> <C> <C>
Assets:
Utility plant $2,021,981 $1,891,432 $1,802,987
Less accumulated depreciation
and depletion 619,195 572,141 533,216
Net Utility plant 1,402,786 1,319,291 1,269,771
Nonutility property 600,299 596,769 552,537
Less accumulated depreciation
and depletion 207,486 198,951 178,275
Net Nonutility property 392,813 397,818 374,262
Total net plant and property 1,795,599 1,717,109 1,644,033
Other assets 717,098 668,918 641,389
Total Assets $2,512,697 $2,386,027 $2,285,422
Liabilities:
Common shareholders' equity $ 988,100 $ 945,651 $ 902,989
Unallocated stock held by trustee
for retirement savings plan (32,580) (34,419) (36,098)
Preferred stock 101,416 101,419 51,984
Mandatorily redeemable preferred
securities of trust
Long-term debt 588,876 571,870 581,179
Other liabilities 866,885 801,506 785,368
Total Liabilities $2,512,697 $2,386,027 $2,285,422
</TABLE>
<TABLE>
<CAPTION>
Income Statement Items (000)
1997 1996 1995
<S> <C> <C> <C>
Revenues $1,023,597 $ 973,208 $ 953,224
Expenses:
Operations 415,979 381,550 420,472
Maintenance 75,994 68,181 68,286
Selling, general and administrative 124,244 113,485 104,213
Taxes other than income taxes 96,214 87,903 89,858
Depreciation, depletion and
amortization 94,664 86,403 84,635
Writedowns of long-lived assets (a) 74,297
807,095 737,522 841,761
Income from operations 216,502 235,686 111,463
Interest expense and other income:
Interest 54,667 48,770 43,656
Distributions on mandatorily
redeemable preferred securities
of subsidiary trust 5,492
Other (income) deductions - net (34,159) (4,445) (10,704)
26,000 44,325 32,952
Income taxes 61,870 71,975 21,574
Net income 128,632 119,386 56,937
Dividends on preferred stock 3,690 8,358 7,227
Net income available for common stock $ 124,942 $ 111,028 $ 49,710
Basic earnings per share of common
stock:
Utility operations $ 1.08 $ 1.13 $ 1.22
Nonutility operations 1.21 0.90 (0.30)
$ 2.29 $ 2.03 $ 0.92
Diluted earnings per share of
common stock $ 2.28 $ 2.03 $ 0.92
Dividends declared per share of
common stock $ 1.60 $ 1.60 $ 1.60
Average shares outstanding (000) 54,649 54,634 54,121
Earnings coverage of fixed
charges, SEC Method 2.94x 3.21x 1.96x
<FN>
(a) Refer to Item 8, "Financial Statements and Supplementary Data - Note 1 to
the Consolidated Financial Statements."
</FN>
</TABLE>
<TABLE>
<CAPTION>
Income Statement Items (000)
1994 1993 1992
<S> <C> <C> <C>
Revenues $1,005,970 $1,024,285 $ 943,872
Expenses:
Operations 436,610 476,733 412,387
Maintenance 75,357 70,029 70,525
Selling, general and administrative 109,217 106,765 93,061
Taxes other than income taxes 99,200 92,430 94,328
Depreciation, depletion and
amortization 84,483 80,831 79,901
Writedowns of long-lived assets
804,867 826,788 750,202
Income from operations 201,103 197,497 193,670
Interest expense and other income:
Interest 42,817 48,023 49,166
Other (income) deductions - net (10,532) (11,857) (8,200)
32,285 36,166 40,966
Income taxes 55,226 54,120 45,639
Net income 113,592 107,211 107,065
Dividends on preferred stock 7,227 4,353 3,790
Net income available for common stock $ 106,365 $ 102,858 $ 103,275
Basic earnings per share of common
stock:
Utility operations $ 0.91 $ 1.07 $ 0.97
Nonutility operations 1.09 0.91 1.05
$ 2.00 $ 1.98 $ 2.02
Diluted earnings per share
of common stock $ 2.00 $ 1.97 $ 2.02
Dividends declared per share of
common stock $ 1.60 $ 1.585 $ 1.55
Average shares outstanding (000) 53,125 52,040 51,126
Earnings coverage of fixed
charges, SEC Method 3.05x 2.86x 2.74x
</TABLE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Safe Harbor for Forward-Looking Statements:
The Company is including the following cautionary statements to make
applicable and take advantage of the safe harbor provisions of the Private
Securities Litigation Reform Act of 1995 for any forward-looking statements
made by, or on behalf, of the Company in this Annual Report on Form 10-K.
Forward-looking statements include statements concerning plans, objectives,
goals, strategies, future events or performance and underlying assumptions and
other statements which are other than statements of historical facts. Such
forward-looking statements may be identified, without limitation, by the use
of the words "anticipates", "estimates", "expects", "intends", "believes" and
similar expressions. From time to time, the Company or one of its subsidiaries
individually may publish or otherwise make available forward-looking
statements of this nature. All such forward-looking statements, whether
written or oral, and whether made by or on behalf of the Company or its
subsidiaries, are expressly qualified by these cautionary statements and any
other cautionary statements which may accompany the forward-looking
statements. In addition, the Company disclaims any obligation to update any
forward-looking statements to reflect events or circumstances after the date
hereof.
Forward-looking statements made by the Company are subject to risks and
uncertainties that could cause actual results or events to differ materially
from those expressed in, or implied by, the forward-looking statements. These
forward-looking statements include, among others, statements concerning the
Company's revenue and cost trends, cost recovery, cost-reduction strategies
and anticipated outcomes, pricing strategies, planned capital expenditures,
financing needs, and availability, changes in the utility industry and the
impacts of the year 2000 issue. Investors or other users of the forward-
looking statements are cautioned that such statements are not a guarantee of
future performance by the Company and that such forward-looking statements are
subject to risks and uncertainties that could cause actual results to differ
materially from those expressed in, or implied by, such statements. Some, but
not all, of the risks and uncertainties include general economic and weather
conditions in the areas in which the Company has operations, competitive
factors and the impact of restructuring initiatives in the electric and gas
industry, market prices, environmental laws and policies, federal and state
regulatory and legislative actions, drilling successes in oil and natural gas
operations, changes in foreign trade and monetary policies, laws and
regulations related to foreign operations, tax rates and policies, rates of
interest and changes in accounting principles or the application of such
principles to the Company.
Results of Operations:
The following discussion presents significant events or trends which have
had an effect on the operations of the Company during the years 1995 through
1997 or which are expected to have an impact on operating results in the
future.
In May 1996, the Company was restructured by management into two
divisions: Energy Supply and Energy and Communications Services. Pending
regulatory approvals pertaining to the Company's restructuring, the discussions
and financial information which follow are presented in a Utility and
Nonutility format. Refer to Item 8, "Financial Statements and Supplementary
Data - Note 4 to the Consolidated Financial Statements".
Net Income Per Share of Common Stock:
The Company's net income available for common stock increased to
$124,942,000 in 1997 compared to $111,028,000 and $49,710,000 in 1996 and 1995,
respectively. The following table shows the sources of consolidated net income
on a basic per share basis.
1997 1996 1995
Utility Operations $ 1.08 $ 1.13 $ 1.22
Nonutility Operations 1.21 0.90 (0.30)
Consolidated $ 2.29 $ 2.03 $ 0.92
Consolidated net income for the year ended December 31, 1997 was $2.29
per share, an increase of 26 cents over last year.
Net gains from the sales of non-strategic oil, natural gas and coal
properties and an investment in a Brazilian gold mine contributed significantly
to 1997 Nonutility increased earnings. Also, earnings from telecommunications
operations increased because the Company began receiving revenues from its
expanded fiber optic network late in the third quarter. Increased earnings
from coal operations due to higher sales volumes to Colstrip Units 3 & 4 were
more than offset by price reductions resulting primarily from a settlement with
Puget Sound Energy (Puget). Earnings from independent power operations
decreased primarily due to reduced long-term power sales revenues resulting
from the Puget settlement and the absence of a gain recognized in 1996 on the
sale of a portion of an asset. Nonutility earnings also benefited from the
settlement of a long-standing income tax dispute with the Internal Revenue
Service (IRS).
Utility earnings decreased 5 cents per share in 1997 due to weather
related reductions in general business revenues and higher power supply costs
resulting from increased steam plant maintenance, power purchases from
qualifying facilities and the settlement of a power supply contract dispute.
These negatives were partially offset by higher rates, customer growth, the
expiration in 1996 of two higher-priced power purchase contracts and the
absence of severance costs recorded in the fourth quarter of last year. The
income tax settlement mentioned above also positively impacted the Utility.
Net income for the year ended December 31, 1996 was $2.03 per share,
compared with 92 cents per share in 1995. Included in 1995 consolidated
earnings were charges of 90 cents per share resulting from the adoption of a
new accounting standard, "Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to Be Disposed Of" (SFAS No. 121), the closing of
the Golden Eagle Mine and the outcome of a coal arbitration decision.
Utility earnings for 1996 were positively impacted by higher electric
and natural gas revenues resulting from increased rates, 12% colder weather
than 1995, three percent overall customer growth and reduced power-supply
expenses due to the availability of low-cost regional hydroelectric energy.
The Utility's natural gas revenues alone increased 12% over 1995. After-tax
charges of approximately $3,800,000 were recorded in the fourth quarter of
1996 related to permanent employee reductions and the refinancing of preferred
stock. These charges are expected to result in future cost savings.
Nonutility earnings for 1996 increased primarily due to the closure of
the Golden Eagle Mine, which had sustained operating losses of approximately
18 cents per share in 1995, and growth in earnings from independent power
investments throughout 1996, including a gain on the sale of a portion of an
asset in the fourth quarter of 1996. Partially offsetting these positives were
reduced coal sales to the Colstrip thermal plants due to the availability of
low-cost hydroelectric power. Coal volumes also decreased due to the
expiration of a coal-supply contract with a Midwestern customer at the end of
1995.
Competitive Environment:
The Company's regulated electric and natural gas businesses are
transitioning to competition over the next several years in accordance with
Montana's "Electric Industry Restructuring and Customer Choice Act" and
Montana's "Natural Gas Restructuring and Customer Choice Act" (Acts or Act),
which became law in May 1997. The move to competition provides for customer
choice to wholesale and retail customers for energy commodity and related
services.
In 1997, the Company received 55% of its revenues and 49% of its net
income from regulated utility operations. Other revenue and net income was
provided by its diverse unregulated businesses engaged in coal, oil and natural
gas, independent power and telecommunications operations. A variety of
transition activities, which are detailed below, will help the Company manage
change and position itself for a more competitive future.
REGULATED OPERATIONS:
Electric Utility -
General -- The Act provides for choice of electricity supply for the
Company's large customers by July 1, 1998, for pilot programs for residential
and small commercial customers beginning July 1, 1998, and for all customers
no later than July 1, 2002. Generation assets will be removed from regulated
rate base no later than July 1, 1998. Transmission and distribution services
will remain fully regulated by FERC and/or the Montana Public Service
Commission (PSC). The Act established a rate moratorium on electric rates for
all customers for two years beginning July 1, 1998, and an electric-energy
supply component rate moratorium for an additional two years for smaller
customers. The Act contemplates that rates cannot be increased under the rate
moratorium except under limited circumstances. This moratorium begins after a
2.4% increase, effective January 1, 1998, which will increase revenue
approximately $9,000,000. The legislation authorizes the use of transition
bonds, subject to the approval of a financing order by the PSC, as a method of
financing transition obligations at lower costs. In addition, under the
legislation, if, during the transition period, the earnings of the Electric
Utility fall below a 9.5% return on equity, the Utility's obligation to flow
investment tax credit benefits to ratepayers in future years is reduced. Any
such reduction in the Utility's regulatory obligation provides an economic
benefit to the Company and increases income in that year. The Act also defines
the PSC's role in regulating distribution services, licensing suppliers in the
state, and promulgating rules regarding anti-competitive and abusive
practices.
The legislation requires the payment, through transition charges, of
proven non-mitigatable transition costs, specifically recovery of above-market
generation and qualifying facility power-purchase contract costs and regulatory
assets, and requires for reciprocity between utility companies.
As required by the Act, the Company filed a comprehensive transition plan
with the PSC on July 1, 1997. The filing includes the proposed handling and
resolution of transition costs, and addresses other issues required by the
legislation. The Company expects the PSC to render a decision in June 1998,
subject to the provisions of the legislation.
The restructuring activities of the vertically integrated Electric
Utility are described as follows:
Generation -- The Company announced that it will offer for sale all of
its Montana electric generating facilities. These generating facilities
include 13 dams and four coal-fired plants, its contracts for power purchased
from qualifying facilities and Basin Electric Power Cooperative (Basin), and
its unregulated leased interest in another coal-fired plant.
Regardless of the timing of the sale of the generating assets and power
purchase contracts, the Company is obligated to continue to provide electric
power supply through the transition period to customers in its service
territory who have not had an opportunity to choose to purchase energy from
another power supplier. Such service will require the Company to have
available a power supply sufficient to meet those customers' electric loads.
The Company is evaluating options to meet these needs including a power supply
contract with the purchasers of the generating facilities.
The sale of these assets is expected to occur in 1998. The sale will
expedite the development of competition in Montana's electric-generation
market. Proceeds from the divestiture may be used to repurchase debt and equity
securities, and proceeds up to the book value of the assets sold may be
invested in growth opportunities related to the Company's current regulated and
unregulated business lines. The Company's Mortgage and Deed of Trust imposes a
lien on all physical properties including the generation assets and pollution
control equipment on some of the thermal generating facilities, therefore,
restrictions may exist on the use of proceeds. The sales decision reflects
three major beliefs:
(1) Montana Power will be better positioned if it does not own
generation in a regulatory jurisdiction where it provides
transmission and distribution services. The reduction of regulatory
complexities will allow the Company to react quicker to business
opportunities.
(2) The size and geographic presence necessary to compete successfully
in the dynamic, evolving competitive generation market means that
only the larger companies will have a sustainable competitive
advantage. Exiting its generation activities in Montana allows the
Company to focus more on its core strength of customer service.
(3) Energy prices in the future will be determined by competition and
may be higher or lower than actual costs of generation. The risk
associated with this price competition is better taken by larger
companies who are concentrating on generation.
The divestiture of these generating plants and the sale of contracts for
purchased power from independent qualifying facilities and Basin also will help
to resolve issues associated with the Company's transition costs in the filing
currently before the PSC.
The electric generation assets will be removed from rate base on July 1,
1998. Until the sale is completed, the costs associated with owning and
operating the assets are expected to continue to be recovered through a cost-
based contract between the Company's regulated operations and its non-
regulated Supply Division. Any gains above the Company's book value realized
in the sale of the regulated generating facilities and power purchase
contracts will be utilized to reduce the electric Competitive Transition
Charge (CTC) amounts to be collected from ratepayers. Conversely, any losses
or additional costs to the Company would increase the CTC amounts to be
collected over the approved transition period.
Transmission -- On April 24, 1996, the Federal Energy Regulatory
Commission (FERC) issued Order Nos. 888 and 889 requiring Open-Access Non-
Discriminatory Transmission Services by Public and Transmitting Utilities, and
stating standards of conduct regarding open access. These orders require
public utilities owning transmission lines to file open-access tariffs making
transmission service available to all buyers and sellers of wholesale
electricity; require utilities to use the tariffs for their own wholesale
sales and purchases; and allow utilities to recover wholesale stranded costs,
subject to certain conditions.
The Company's current FERC open-access transmission tariffs became
effective in July 1996. In January 1997, the Company adopted Standards of
Conduct and established an Open-Access Same-Time Information System to comply
with FERC Order No. 889. The Company anticipates updating its FERC tariffs
with a filing in March 1998.
As part of a group of other Pacific Northwest electric utilities, the
Company has been studying the formation of an independent grid operator
(IndeGo) to manage the utilities' high-voltage transmission lines. Work on the
IndeGo proposal has recently been suspended due to lack of regional consensus.
The Company's transmission system serves a majority of the state of
Montana with nearly 7,000 miles of lines. The system integrates generation
located in both the Columbia River and Missouri River drainages and is
directly interconnected with the transmission systems of three investor owned
utilities and two federal power marketing agencies. The Company provides
nondiscriminatory transmission services pursuant to an open access
transmission tariff filed with the FERC.
Distribution -- Distribution service will continue to be regulated by
the PSC and provided by the Company's regulated Distribution Division.
Wholesale -- The Electric Utility currently provides wholesale service
to Central Montana Electric Power Cooperative, Inc. (Central), which manages a
contract for purchases of power from the Electric Utility for a group of
Montana cooperatives. Central has terminated its contract with the Company,
effective June 2000, and will acquire its energy from another supplier
Central's 120 MW load approximates six percent of the Company's system load.
The Company expects to make an application to FERC for recovery of costs which
will be stranded by the termination of this contract, subject to the outcome
of the intended sale of generation assets and power purchase contracts.
Natural Gas Utility --
General -- The restructuring legislation for the Natural Gas Utility
allows utilities to voluntarily offer customers choice of natural gas supply
and authorizes the use of transition bonds, subject to the approval of a
financing order by the PSC, as a method of financing transition obligations at
lower costs. The Act defines the role the PSC will have in regulating
transmission and distribution services, licensing suppliers in the state, and
promulgating rules regarding anti-competitive and abusive practices.
On October 28, 1997, the PSC approved an order giving the Company's
natural gas customers the right to choose their own suppliers based upon
stipulation agreements resulting from the Company's July 1996 Restructuring
Filing. Customers with annual loads greater than 60,000 dekatherms (Dkt) have
been eligible to transport natural gas since November 1, 1991. The October
order provides for a reduction in this load eligibility level to 5,000 Dkt,
annually, effective November 1, 1997, equating to approximately 230 smaller
industrial and larger commercial customers. The order also provides for a pilot
program for small residential and general service customers to commence by the
1998 - 1999 heating season and a transition to full customer choice no later
than mid- 2002.
Almost all of the natural gas production assets of the regulated Utility
were transferred to an unregulated subsidiary on November 1, 1997 at an amount
agreed-to in the natural gas order which was $33,600,000 below the existing
book value. This difference between transfer value and the book value and the
existing $25,400,000 of regulatory assets related to the natural gas
production assets were approved as a CTC and will be recovered from
transmission and distribution customers in rates over a 15-year period. The
assets, liabilities, equity and results of operations of the regulated
Utility's Canadian subsidiary, Canadian-Montana Gas Company, Limited, have
also been included in the unregulated oil and natural gas operations as of
that date. Production from these transferred properties will be sold in the
competitive market in the unregulated operations.
Natural gas transmission, distribution and storage will remain regulated
by the PSC, while eligible customers will be allowed to secure their gas
supply on the open market.
The PSC order reduced annual natural gas revenues by $2,800,000, or
2.3%, and froze base rates for two years. A non-bypassable Universal System
Benefits Charge for public purpose programs was also implemented. The Company
is pursuing the issuance of transition bonds that will refinance the
transition costs at a lower cost of capital. The issuance of these bonds is
expected to result in annual savings of approximately $1,900,000. In November
1997, the Company filed an application with the PSC seeking authorization to
issue up to $65,000,000 of transition bonds.
On January 5, 1998, Enron Capital & Trade Resources Corp. (Enron)
requested court review of the PSC's decision regarding the measure of stranded
costs as well as the level of functional separation of the various segments of
the Company's natural gas business. This appeal is pending before the First
Judicial District Court, Lewis and Clark County. Enron alleges the PSC erred
when it concluded the assets subject to the CTC are stranded and that their
value is $60,000,000.
The Company requested, and expects the district court to provide,
expedited review and decision making regarding this matter. The Company does
not expect the PSC to act upon the Company's application for authority to
issue transition bonds while this appeal is pending at the district court. The
CTC rates assume the cost of capital associated with the transition bond
financing, therefore, the Company is not collecting from customers its full
cost of capital associated with these stranded costs.
The Company does not anticipate a materially negative impact on earnings
due to the reduction in natural gas supply revenues from customers choosing
other suppliers, as the decrease will be offset by reduced supply costs, CTC
charges, transportation and distribution revenues and transition bond financing
savings. The PSC order has been appealed by Enron. Consequently, the timing of
any transition bond issuance is uncertain.
Production -- As discussed above, the Company's unregulated Supply
Division assumed ownership of almost all of the natural gas production assets,
except delivered gas purchase contracts, which have been retained by the
regulated Natural Gas Utility. The assets were transferred at less than book
value. The difference between book value and the agreed-upon transfer value,
and the regulatory assets associated with natural gas production will be
recovered over 15 years from transmission and distribution customers as a
component of CTC charges.
Transmission, Storage and Distribution -- Transmission, storage and
distribution services will remain regulated, and rates for such services will
continue to be subject to approval by the PSC and/or FERC.
UNREGULATED OPERATIONS:
General -- In the fourth quarter of 1997, the Company merged MP Energy
Services, Inc. into MP Energy, Inc. and renamed the entity The Montana Power
Trading & Marketing Company (MPT&MC). The new name better describes the
functions and services that MPT&MC will be providing to customers. The
Company has traditionally sold natural gas, electricity, natural gas liquids
in bulk and other commodities for resale. The structural changes in the
energy markets due to deregulation provides the opportunity for the Company to
extend its traditional wholesale activities to other regions of the nation and
to expand into retail markets as they become deregulated. The Company will
focus its activities in the western half of the United States and the upper
Midwest. MPT&MC targets wholesale and large industrial customers that have
been granted the right, either by state or federal agencies, to pursue other
sources for their electricity and natural gas supplies.
In order to better manage the risks associated with commodity
production, trading and marketing, the Company retained an outside consultant
in 1997 to design a comprehensive Energy Risk Management program. The program
is being implemented in the first half of 1998. In addition, the Company also
established a position, reporting directly to the Company's Chief Financial
Officer, to oversee the risks in MPT&MC. Finally, MPT&MC will be implementing
new systems in 1998 to enable it to more accurately track and manage its
commodity portfolio.
Wholesale -- The Company has a long history of trading in the wholesale
electric market and also has developed trading, and wholesale and large
customer expertise in its unregulated natural gas operations. The Company
believes that this experience allows it to effectively compete in the
competitive environment. Currently, the electricity markets are not as
developed as the natural gas markets. As the electricity market develops,
many of the same financial instruments that are used to control risk and
volatility in the natural gas industry will be used for the electric industry.
The formation of MPT&MC brings together the Company's expertise in the
wholesale trading of all energy commodities.
To serve growing markets, MPT&MC secured firm capacity on Pacific Gas
Transmission's (PGT) interstate pipeline and on Pacific Gas & Electric
Company's intrastate pipeline. The intrastate capacity provides MPT&MC with
the ability to offer firm gas deliveries to California customers and PGT
capacity provides MPT&MC with firm access to Canadian supplies. Trading and
deliveries to customers will begin in 1998. In addition, MPT&MC will begin
trading natural gas in the Upper Midwest once an affiliate's firm
transportation capacity on Northern Border Pipeline is activated. This is
expected to occur in late 1998. This capacity provides access for the
Company's low-cost gas from its Bowdoin production on a firm basis to upper
Midwest markets since this pipeline provides access to several local
distribution companies in the Chicago area.
Retail -- The Company, through MPT&MC, is actively selling retail
energy-related products and services in a competitive marketplace. This
includes energy commodity supplies, assisting customers with utility rate
management; managing power contracts; installing energy-efficient equipment;
and tracking facility energy use, and other services required by customers.
The Montana Power Group (MPG), an energy supply and management alliance,
was exclusively endorsed by the California Manufacturers Association (CMA) to
assist its members with their energy decisions. As a participant in the MPG,
MPT&MC agreed to offer comprehensive energy services, including energy supply,
discounted from the power exchange prices, and energy management products and
services to qualified CMA members. The CMA has agreed to endorse and promote
such products and services to its members. The membership of the CMA is the
target market for MPT&MC in California. The approximate 1,000 members of CMA
represent an estimated 8,000,000 megawatt hours of electric use annually. The
supply program is offered on a limited basis to CMA members capped at
predetermined volumes. The program will be subscribed on a first come, first
serve basis. Once the caps are fully subscribed, MPT&MC will have, at its sole
discretion, the option to extend the offered supply and services to other CMA
members. To date, one contract for energy supply and services has been signed
with a CMA member. MPT&MC is expecting to begin retail deliveries in
California on April 1, 1998, pending the California market opening on that
date. At this time, the Company cannot predict the impact of the CMA agreement
on future earnings, however, due to the limits provided in the agreement, any
potential negative impacts are not expected to have a material impact on the
Company's financial position or results of operations.
MPT&MC is also participating in the Puget Sound Energy customer choice
pilot program in western Washington. The Company has one retail industrial
customer and has been delivering energy under the pilot program since December
1997.
<TABLE>
<CAPTION>
UTILITY OPERATIONS
Year Ended December 31
1997 1996 1995
Thousands of Dollars
<S> <C> <C> <C>
ELECTRIC UTILITY:
REVENUES:
Revenues $ 435,986 $ 430,171 $ 421,999
Intersegment revenues 4,685 5,793 5,813
440,671 435,964 427,812
EXPENSES:
Power supply 142,193 136,817 148,240
Transmission and distribution 31,883 30,263 26,916
Selling, general and administrative 55,934 53,922 43,763
Taxes other than income taxes 47,985 46,191 43,302
Depreciation and amortization 51,674 46,648 40,675
329,669 313,841 302,896
INCOME FROM ELECTRIC OPERATIONS 111,002 122,123 124,916
NATURAL GAS UTILITY:
REVENUES:
Revenues (other than gas supply
cost revenues) 105,220 107,782 93,453
Gas supply cost revenues 17,135 20,746 21,660
Intersegment revenues 588 649 852
122,943 129,177 115,965
EXPENSES:
Gas supply costs 17,135 20,746 21,660
Other production, gathering and exploration 8,128 9,335 9,643
Transmission and distribution 11,353 11,711 10,934
Selling, general and administrative 20,342 19,195 17,671
Taxes other than income taxes 16,052 15,722 14,841
Depreciation, depletion and amortization 11,939 11,638 10,283
84,949 88,347 85,032
INCOME FROM GAS OPERATIONS 37,994 40,830 30,933
INTEREST EXPENSE AND OTHER INCOME:
Interest 52,191 46,663 44,031
Distributions on company obligated
mandatorily redeemable preferred
securities of subsidiary trust 5,492
Other (income) deductions - net (7,128) (402) (5,419)
50,555 46,261 38,612
INCOME BEFORE INCOME TAXES 98,441 116,692 117,237
INCOME TAXES 35,643 46,687 44,047
DIVIDENDS ON PREFERRED STOCK 3,690 8,358 7,227
UTILITY NET INCOME AVAILABLE FOR COMMON STOCK $ 59,108 $ 61,647 $ 65,963
</TABLE>
UTILITY OPERATIONS:
Weather affects the demand for electricity and natural gas, especially
among residential and commercial customers. Very cold winters increase demand,
while mild winter weather reduces demand. The weather's effect is measured
using degree-days. A degree-day is the difference between the average daily
actual temperature and a baseline temperature of 65 degrees. Heating degree-
days result when the average daily actual temperature is less than the
baseline. As measured by heating degree-days, the 1997 temperatures for the
Company's service territory were 10% warmer than 1996 and comparable to the
historic average. Temperatures in 1996 were 12% colder than 1995 and 11%
colder than the historic average.
Weather, streamflow conditions and the wholesale power markets in the
Northwest and California influence the Company's electric wholesale revenues,
power-purchase expenses and output of thermal generation. Regional opportunity
purchased-power prices were higher than last year and consequently, the
Company did not curtail its thermal generation as it had during 1996. Margins
on off-system sales are tightening as competition among suppliers increases.
Accounting for the Effects of Regulation:
For its regulated operations, the Company follows SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation." As a result, the
Company has recorded regulatory assets and liabilities that are intended to be
recognized in expenses and revenues in future periods. Should any portion of
these operations cease to meet the criteria of SFAS No. 71 for various
reasons, including changes in regulation or a change in the competitive
environment for those operations, the Company would discontinue the
application of SFAS No. 71 for that portion of the operations for which the
statement no longer applied. If the Company was to discontinue application of
SFAS No. 71 for all or a portion of its operations, the regulatory assets and
liabilities related to those portions would have to be eliminated from the
balance sheet and included in income in the period when the discontinuation
occurred unless recovery of those costs was provided through rates charged to
those customers in a portion of the business that remains regulated. In
conjunction with the ongoing changes in the electric and natural gas
industries, the Company will continue to evaluate the applicability of this
accounting principal to those businesses.
As a consequence of the issuance by the PSC of the natural gas
restructuring order, the Company's natural gas production assets were removed
from SFAS No. 71 accounting in the fourth quarter of 1997. The timing of the
removal of the electric generating assets from SFAS No. 71 has not yet been
determined. The Financial Accounting Standards Board's (FASB) Emerging Issues
Task Force (EITF) met in July 1997 to discuss issues related to removing the
generation portion of a utility company from SFAS No. 71. Recovery of the
Company's existing regulatory assets related to the natural gas production
assets was provided in the PSC order, therefore the discontinuance of SFAS No.
71 for these assets did not have a material impact on the results of operations
for 1997. Recovery of existing regulatory assets related to electric
generation is provided in the electric restructuring legislation. Based upon
the EITF's conclusions regarding regulatory assets and liabilities and the
Company's anticipated recovery of its regulatory assets, the Company believes
that the discontinuation of regulatory accounting for these generation assets
will not have a material impact on the Company's financial position or results
of operations. See Item 8, "Financial Statements and Supplementary Data -
Notes 1 and 4 to the Consolidated Financial Statements."
<TABLE>
<CAPTION>
Electric Utility:
1997 Compared to 1996
Revenues and
Power Supply Expenses Volumes Customers
(Thousands of Dollars) (Thousands of MWh) (Yearly Average)
1997 1996 1997 1996 1997 1996
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues:
Residential,
Commercial &
Government $ 270,276 $ 257,625 5% 4,342 4,414 (2)% 275,916 271,683 2%
Industrial 107,038 108,156 (1)% 2,580 2,580 0% 3,339 3,257 3%
General Business 377,314 365,781 3% 6,922 6,994 (1)% 279,255 274,940 2%
Sales to Other
Utilities 49,921 52,125 (4)% 2,663 2,761 (4)% 84 79 6%
Other 8,751 12,265 (29)%
Intersegment 4,685 5,793 (19)% 149 332 (55)% 230 230 0%
Total $ 440,671 $435,964 1% 9,734 10,087 (3)% 279,569 275,249 2%
Power Supply
Expenses:
Hydroelectric $ 21,231 $ 19,423 9% 4,126 4,064 2%
Steam 52,801 47,185 12% 4,290 4,272 0%
Purchases
and Other 68,161 70,209 (3)% 2,538 2,557 (1)%
Total Power Supply $ 142,193 $ 136,817 4% 10,954 10,893 1%
Cents Per kWh $ 1.298 $ 1.256
</TABLE>
Revenues from general business customers increased in 1997 primarily due
to higher tariff rates and customer growth. A weather-related reduction in
volumes sold moderated this increase. Reduced sales to other utilities
resulting from the expiration of a high-priced firm sales contract in the
second quarter of 1996 were partially offset by higher prices and greater
volumes sold in the wholesale electric market. An actuarial pension plan
adjustment decreased other revenues as well as selling, general and
administrative (SG&A) expenses.
Steam generation expenses were up in 1997 due to additional maintenance
costs at the Corette plant. Decreases in purchases and other power supply
expenses were mainly related to the expiration of two high-priced firm purchase
contracts in the first half of 1996 and reduced opportunity purchase prices.
Partially offsetting these decreases were higher qualifying facility rates, the
settlement of a supply contract dispute and the absence of a 1996 credit from a
third party who delivers energy to the Company's customers. Increased SG&A
expenses resulted primarily from increased consulting and computer upgrades,
reduced billing to third parties and marketing costs previously classified as
other operating expenses. The pension plan adjustment mentioned above and the
absence of 1996 permanent employee reduction costs moderated the SG&A expense
increase. Depreciation expense increased as a result of greater plant
investment and a mid-1996 change in the PSC-approved depreciation rates.
<TABLE>
<CAPTION>
1996 Compared to 1995
Revenues and
Power Supply Expenses Volumes Customers
(Thousands of Dollars) (Thousands of MWh) (Yearly Average)
1996 1995 1996 1995 1996 1995
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues:
Residential,
Commercial &
Government $ 257,625 $ 232,676 11% 4,414 4,181 6% 271,683 266,497 2%
Industrial 108,156 120,161 (10)% 2,580 2,974 (13)% 3,257 3,166 3%
General Business 365,781 352,837 4% 6,994 7,155 (2)% 274,940 269,663 2%
Sales to Other
Utilities 52,125 58,623 (11)% 2,761 2,751 0% 79 71 11%
Other 12,265 10,539 16%
Intersegment 5,793 5,813 0% 332 299 11% 230 234 (2)%
Total $ 435,964 $ 427,812 2% 10,087 10,205 (1)% 275,249 269,968 2%
Power Supply
Expenses:
Hydroelectric $ 19,423 $ 19,291 1% 4,064 3,480 17%
Steam 47,185 44,010 7% 4,272 4,754 (10)%
Purchases
and Other 70,209 84,939 (17)% 2,557 2,667 (4)%
Total Power Supply $ 136,817 $ 148,240 (8)% 10,893 10,901 0%
Cents Per kWh $ 1.256 $ 1.360
</TABLE>
Revenues from general business customers increased in 1996 due to higher
tariff rates and greater volumes sold as a result of colder weather and
customer growth. These increases were partially offset by reduced revenues
related to a large industrial customer, who was served under a rate that was
lower than the tariff rate, closing operations in December 1995. Sales to
other utilities declined primarily as a result of the expiration of two firm
sales contracts, one in late 1995 and the other in early 1996. This decrease
was partially offset by increased wholesale volumes, moderated by lower
regional energy prices. Other revenues increased due to higher wheeling
rates.
Excluding a 1995 steam expense reduction of $11,300,000 related to a
coal arbitration decision, steam expenses decreased in 1996 when higher cost
thermal generation was displaced as streamflow conditions caused increases in
Utility and regional low-cost hydroelectric generation. Shorter maintenance
periods, improved productivity and permanent employee reductions at the
Colstrip units also decreased steam expenses. Purchased power costs declined
due to the expiration of two high-priced firm purchase contracts in the first
half of 1996 and a credit from a third party who delivers energy to the
Company's customers. This decrease was partially offset by increased
opportunity purchases and additional payments to qualifying facilities.
Transmission and distribution expenses were up as a result of several non-
recurring items. Increases in SG&A expenses were primarily related to
permanent employee reduction costs, reduced billing to third parties and the
absence of insurance proceeds received in 1995. The increase in taxes other
than income taxes was mainly due to higher property taxes related to property
additions and increased mill levies. Depreciation expense increased as a
result of greater plant investment and a mid-1996 change in the PSC-approved
depreciation rate.
<TABLE>
<CAPTION>
Natural Gas Utility:
1997 Compared to 1996
Revenues Volumes Customers
(Thousands of Dollars) (Thousands of Mmcf) (Yearly Average)
1997 1996 1997 1996 1997 1996
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues:
Residential,
Commercial &
Government $105,246 $109,795 (4)% 22,695 23,690 (4)% 141,130 137,222 3%
Industrial 2,659 2,921 (9)% 618 675 (8)% 399 421 (5)%
Subtotal 107,905 112,716 (4)% 23,313 24,365 (4)% 141,529 137,643 3%
Gas Supply Cost
Revenues (GSC) (17,135) (20,746) (17)%
General Business
without GSC 90,770 91,970 (1)% 23,313 24,365 (4)% 141,529 137,643 3%
Sales to Other
Utilities 786 868 (9)% 195 255 (24)% 4 3 33%
Transportation 9,919 9,582 4% 26,020 26,969 (4)% 42 42 0%
Other 3,745 5,362 (30)%
Total $105,220 $107,782 (2)% 49,528 51,589 (4)% 141,575 137,688 3%
</TABLE>
Natural gas revenues, excluding gas supply cost revenues, decreased in
1997 primarily due to a weather related reduction in volumes sold. Slightly
higher tariff rates and customer growth partially moderated the revenue
decrease. An actuarial pension plan adjustment decreased other revenues as
well as selling, general and administrative expenses. This SG&A adjustment,
however, was more than offset by increased consulting and computer upgrades
which were moderated by the absence of 1996 permanent employee reduction
costs.
<TABLE>
<CAPTION>
1996 Compared to 1995
Revenues Volumes Customers
(Thousands of Dollars) (Thousands of Mmcf) (Yearly Average)
1996 1995 1996 1995 1996 1995
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues:
Residential,
Commercial &
Government $109,795 $ 98,350 12% 23,690 21,152 12% 137,222 132,518 4%
Industrial 2,921 2,646 10% 675 611 10% 421 412 2%
Subtotal 112,716 100,996 12% 24,365 21,763 12% 137,643 132,930 4%
Gas Supply Cost
Revenues (GSC) (20,746) (21,660) (4)%
General Business
without GSC 91,970 79,336 16% 24,365 21,763 12% 137,643 132,930 4%
Sales to Other
Utilities 868 762 14% 255 209 22% 3 3 0%
Transportation 9,582 8,563 12% 26,969 27,325 (1)% 42 39 8%
Other 5,362 4,792 12%
Total $107,782 $ 93,453 15% 51,589 49,297 5% 137,688 132,972 4%
</TABLE>
Natural gas revenues, excluding gas supply cost revenues, increased as a
result of higher tariff rates and greater volumes sold due to colder weather
and customer growth. SG&A expense increased primarily due to permanent
employee reduction costs. Depreciation expense increased for the same reasons
mentioned in the Electric Utility discussion.
Other Income and Expense, and Preferred Dividends:
1997 Compared to 1996
Interest expense increased in 1997 due to additional borrowing and
interest accrued on the Kerr Project mitigation liability which was recorded in
the second quarter of 1997. Increases in other income related to the interest
income on the 1997 settlement of a dispute with the IRS and the absence of a
1996 loss on written-off property were partially offset by costs associated
with the Flint Creek Dam transfer to Granite County, Montana in the second
quarter of 1997.
Income tax expense declined in 1997 as a result of lower before-tax net
income, a reduced effective tax rate and decreased tax accruals resulting from
the settlement of a dispute with the IRS.
Preferred dividends decreased in 1997 because the Company repurchased and
retired 139,200 shares of its $6.875 series and redeemed all outstanding shares
of its $2.15 series during the fourth quarter of 1996.
1996 Compared to 1995
Interest expense increased in 1996 as a result of additional borrowing in
the fourth quarter. Other income decreased due to a loss on written-off
property and the absence of interest income received in 1995 related to a coal
arbitration decision. A reduction in capitalized labor added to the interest
expense increase and partially offset the other income decrease.
Income taxes increased due to a corresponding increase in before-tax net
income and a higher 1996 effective tax rate as a result of regulatory
accounting related to deferred income taxes on depreciation.
<TABLE>
<CAPTION>
NONUTILITY OPERATIONS
Year Ended December 31
1997 1996 1995
Thousands of Dollars
<S> <C> <C> <C>
COAL:
REVENUES:
Revenues $ 167,623 $ 163,901 $ 207,451
Intersegment revenues 34,164 31,448 25,659
201,787 195,349 233,110
EXPENSES:
Operations and maintenance 119,086 115,859 155,149
Selling, general and administrative 22,030 21,373 28,211
Taxes other than income taxes 23,455 20,883 27,210
Depreciation, depletion and amortization 8,368 5,653 11,187
Writedowns of long-lived assets 55,103
172,939 163,768 276,860
INCOME (LOSS) FROM COAL OPERATIONS 28,848 31,581 (43,750)
OIL AND NATURAL GAS:
REVENUES:
Revenues: 163,656 124,532 100,030
Intersegment revenues 3,120 293 409
166,776 124,825 100,439
EXPENSES:
Operations and maintenance 118,266 76,975 60,526
Selling, general and administrative 10,723 10,152 9,320
Taxes other than income taxes 4,555 2,931 2,334
Depreciation, depletion and amortization 16,922 17,080 17,569
Writedowns of long-lived assets 19,194
150,466 107,138 108,943
INCOME (LOSS) FROM OIL AND
NATURAL GAS OPERATIONS 16,310 17,687 (8,504)
INDEPENDENT POWER:
REVENUES:
Revenues 70,932 75,322 79,095
Earnings from unconsolidated investments 14,980 21,174 2,622
Intersegment sales 1,820 1,426 796
87,732 97,922 82,513
EXPENSES:
Operations and maintenance 63,837 64,274 68,300
Selling, general and administrative 4,290 5,223 3,557
Taxes other than income taxes 1,868 1,783 1,831
Depreciation and amortization 2,774 3,793 3,176
72,769 75,073 76,864
INCOME FROM INDEPENDENT POWER OPERATIONS $ 14,963 $ 22,849 $ 5,649
</TABLE>
<TABLE>
<CAPTION>
NONUTILITY OPERATIONS
Year Ended December 31
1997 1996 1995
Thousands of Dollars
<S> <C> <C> <C>
TELECOMMUNICATIONS:
REVENUES:
Revenues $ 44,899 $ 27,641 $ 23,247
Intersegment revenues 797 133 377
45,696 27,774 23,624
EXPENSES:
Operations and maintenance 20,911 18,316 15,520
Selling, general and administrative 7,843 5,498 4,688
Taxes other than income taxes 2,293 392 343
Depreciation and amortization 2,455 911 803
33,502 25,117 21,354
INCOME FROM TELECOMMUNICATIONS OPERATIONS. 12,194 2,657 2,270
OTHER OPERATIONS:
REVENUES:
Revenues 2,104 1,201 2,647
Intersegment revenues 3,924 782 699
6,028 1,983 3,346
EXPENSES:
Operations and maintenance 2,394 1,207 1,607
Selling, general and administrative 7,911 2,137 849
Depreciation and amortization 532 679 942
10,837 4,023 3,398
LOSS FROM OTHER OPERATIONS (4,809) (2,040) (52)
INTEREST EXPENSE AND OTHER INCOME:
Interest 6,605 4,829 4,494
Other (income) deductions - net (31,160) (6,764) (10,155)
(24,555) (1,935) (5,661)
INCOME (LOSS) BEFORE INCOME TAXES 92,061 74,669 (38,726)
INCOME TAXES 26,227 25,288 (22,473)
NONUTILITY NET INCOME (LOSS) AVAILABLE FOR
COMMON STOCK $ 65,834 $ 49,381 $ (16,253)
</TABLE>
NONUTILITY OPERATIONS:
Coal Operations:
1997 Compared to 1996
Income from coal operations decreased primarily as a result of price
decreases and increased production costs and legal expenses. Revenues from the
Rosebud and Jewett mines increased $4,100,000 and $2,500,000, respectively. At
the Rosebud Mine, volumes of coal sold to Colstrip Units 3 & 4 increased nearly
37% over 1996 which was adversely impacted by plant curtailments resulting from
an abundance of low-cost hydroelectric power in the region. This increase was
largely offset by price reductions resulting from the Puget settlement and a
short-term contract modification on tons sold to the other Colstrip partners
along with a decrease in tons sold to Colstrip Units 1 & 2 due to plant
maintenance. Volumes of lignite sold at the Jewett Mine increased 8% over
1996.
Operations and maintenance expense increased primarily due to higher
volumes of tons sold and increased overburden costs at the Rosebud Mine and
higher royalty expense at the Jewett Mine associated with mining more lignite
from the customer's leases. Taxes other than income taxes increased as a
result of higher revenues and volumes at the Rosebud Mine. Depreciation,
depletion and amortization also increased due to the higher volumes and changes
in depreciation estimates.
1996 Compared to 1995
Coal operations for 1995 included charges of approximately $91,000,000
relating to the closure of the Golden Eagle Mine, the outcome of a coal
arbitration decision, operating losses at the Golden Eagle Mine prior to
closure, and the adoption of SFAS No. 121.
Excluding a non-recurring charge of approximately $20,700,000 recorded in
1995 as a result of the Colstrip Units 1 & 2 coal arbitration decision, 1996
revenues, including intersegment revenues, decreased by $58,400,000. Rosebud
Mine revenues decreased $17,600,000 due to the expiration of a Midwestern
contract at the end of 1995 and approximately $10,400,000 due primarily to
decreased short-term coal sales, lower transportation fees and the switching
of fuel supplier by the Corette Plant for early compliance with air quality
standards. Rosebud Mine revenues from Colstrip Units 3 & 4 also decreased
$13,400,000 due to a 22% decline in volumes sold resulting from plant
curtailments due to the availability of low-cost hydroelectric generation in
the region. The closure of the Golden Eagle Mine also resulted in a
$16,400,000 decrease in revenues.
The closure of the Golden Eagle Mine resulted in a $22,800,000 decrease
in operation and maintenance, a $4,200,000 decrease in selling, general and
administrative, a $2,200,000 decrease in taxes other than income taxes and a
$2,400,000 decrease in depreciation and depletion. Expenses also decreased as
a result of the loss recorded in 1995 for the closure of the Golden Eagle Mine
and the adoption of SFAS No. 121. Despite a reduction in 1995 royalty expense
and production taxes of approximately $7,000,000 resulting from the coal
arbitration decision, the decrease in volumes sold in 1996 at the Rosebud Mine
reduced operation and maintenance expenses by $16,500,000, taxes other than
income taxes by $3,300,000 and depreciation and depletion by $2,300,000.
Selling, general and administrative expense also decreased $2,600,000
primarily due to the absence of the outside legal costs incurred in 1995
related to the coal arbitration proceeding. Taxes other than income taxes for
the Jewett Mine also decreased $1,000,000 as a result of a refund of Texas
sales taxes.
The Golden Eagle Mine, acquired by the Company in 1991, incurred
significant losses in 1993, 1994 and the first nine months of 1995. With the
commencement in mid-1994 of deliveries under a long-term contract, losses were
expected to end. However, unexpected mining and wash-plant problems caused
production costs to be higher than expected, and market prices continued to be
lower than expected. During the course of 1995, management concluded that, in
view of the outlook for coal prices, production costs could not be reduced
sufficiently to achieve profitable operations in the foreseeable future.
Accordingly, the Company terminated the coal sales agreement and ceased
production at the end of 1995, and wrote down its investment in the mine in
the fourth quarter of 1995. In 1996, the mine was sealed and most of the
salvageable plant and equipment was sold. The disposition of these assets was
charged against the estimated loss provision which was established in 1995.
See Item 8, "Financial Statements and Supplementary Data - Note 1 to the
Consolidated Financial Statements" for further discussion of asset impairment.
Oil and Natural Gas Operations:
The following table shows year-to-year changes for the previous two
years, in millions of dollars, in the various classifications of revenues, and
the related percentage changes in volumes sold and prices received:
1997 1996
Oil -revenue $ (3) $ 3
-volume (20)% 2%
-price/bbl 10% 15%
Natural gas and natural
gas liquids -revenue $ 36 $ 20
-volume 1% 14%
-price/Mcf 35% 10%
Miscellaneous -revenue $ 9 $ 2
1997 Compared to 1996
Oil and natural gas operations experienced a slight decrease in income
primarily due to decreased oil revenues and increased purchased gas costs.
Natural gas revenues increased primarily due to higher market prices, primarily
in the first and fourth quarters of the year and natural gas liquids revenues
from the Vessels plant acquired in 1997. Oil production decreased as a result
of the sale of non-strategic oil properties in accordance with the Company's
focus on natural gas. Miscellaneous revenues increased due principally to
increases in processing and gathering revenues from the Vessels facilities.
Operations and maintenance expense increased $41,300,000 primarily due to
higher prices and increased volumes of purchased natural gas and additional
processing costs at the Vessels plant. Taxes other than income taxes also
increased due to the Vessels plant acquisition and higher production taxes.
1996 Compared to 1995
Excluding the 1995 charge of $19,200,000 resulting from the adoption of
SFAS No. 121, income from oil and natural gas operations improved principally
as a result of higher prices for both oil and natural gas sold and higher
volumes of natural gas sold.
Natural gas revenues for the year increased $11,900,000 due to higher
market prices and scheduled escalations in the price of gas sold under long-
term co-generation supply contracts. Natural gas revenues also increased
$7,400,000, primarily as a result of increased volumes sold in Canada
resulting from intensified marketing efforts, offset by a five percent
decrease in gas produced due to natural declining production in Canadian wells
along with well dispositions. Oil revenues benefited from higher prices in
both the U.S. and Canada, and increased U.S. production. Miscellaneous
revenues increased $1,600,000 primarily as a result of higher volumes and
higher prices on natural gas processed at the Fort Lupton facility.
Operating expenses increased primarily due to higher prices paid for
natural gas in the U.S. and the increase in natural gas volumes purchased for
resale. The increase was more than offset by a decrease resulting from the
adoption of SFAS No. 121 recorded in 1995.
Independent Power Operations:
1997 Compared to 1996
Excluding the 1996 gain on the sale of a portion of an investment,
earnings from unconsolidated investments increased $2,000,000 due to continued
growth in earnings from existing investments and additional earnings from an
investment that became operational in the first quarter of 1997. Offsetting the
increase was a $5,700,000 decrease in revenue resulting from a settlement
reached with Puget.
Operating expenses decreased largely from a $1,800,000 reduction in
purchase power expense combined with a $1,000,000 decrease in project
development expenses. The decrease was offset by a $1,700,000 increase in fuel
expense. During 1997, the Colstrip plant generated more energy than in 1996
due to less displacement of thermal generation. Depreciation expense decreased
$1,500,000 as a result of decreased amortization of independent power
investments due to a change in accounting method.
1996 Compared to 1995
The 1996 net income from independent power operations increased primarily
as the result of an $8,700,000 increase in earnings from unconsolidated
investments due to continued growth in earnings from power investments
throughout the year. In addition, a gain on the sale of a portion of an
investment contributed to the increase. The absence in 1996 of a $1,900,000
loss on the withdrawal from a power service business in 1995 also contributed
to the increase. Partially offsetting the increase was a $2,000,000 decrease
in long-term power sales revenue resulting from a decrease in volumes sold.
Independent power operating and maintenance expenses decreased $4,000,000
due primarily to a $3,200,000 reduction in power supply costs and a $1,900,000
decrease in transmission expense. This decrease was partially offset by a
$1,300,000 increase in purchase power expense. Power supply costs decreased as
a result of the displacement of higher cost thermal generation with lower cost
hydroelectric generation and the availability of less expensive market energy.
The decrease in transmission expense was a direct result of the decrease in
volumes sold under long-term power sales contracts.
Telecommunications Operations:
1997 Compared to 1996
Earnings from telecommunications operations increased because the Company
began receiving revenues from its expanded fiber optic network late in the
third quarter and due to a 31% increase in long-distance minutes sold.
Operations and maintenance, taxes other than income and depreciation
increased $2,600,000, $1,900,000 and $1,500,000, respectively, as a result of
the operation of the expanded network. Selling, general and administrative
expenses increased primarily due to increased marketing efforts and advertising
costs.
1996 Compared to 1995
Earnings from telecommunications operations improved primarily as a
result of increased long-distance sales and increased equipment sales.
Long-distance service revenues increased 20% due to a 33% increase in minutes
sold resulting from increased marketing efforts and expansion into new markets
in Washington, Idaho and Oregon. Equipment sales earnings increased as a
result of completion of projects in these three states as well as Montana.
Other Operations:
1997 Compared to 1996
Revenue and expense increases in other operations relate primarily to the
Company's new electric, natural gas and oil marketing company, The Montana
Power Trading and Marketing Company (MPT&MC).
Other Income and Expense:
1997 Compared to 1996
Interest expense increased primarily due to increases in the amount of
outstanding borrowings to provide short-term financing for the Company's
expansion of telecommunication and oil and natural gas operations.
Other income - net increased due to the gains of approximately
$23,000,000 on the sales of non-strategic oil and natural gas properties, a
$10,300,000 gain on the sale of the investment in the Brazilian gold mine,
increased earnings from the gold mine and interest income associated with the
like-kind exchange transaction and the settlement with the IRS. These
increases were partially offset by the loss on the sale of non-strategic
Wyoming coal properties and costs associated with a discontinued SynCoal
project.
The increase in income tax expense resulting from higher pre-tax net
income was mostly offset by the tax adjustment associated with the settlement
with the IRS.
1996 Compared to 1995
The changes in interest expense from 1996 to 1995 were a result of
increases in the amount of outstanding borrowings and the interest paid
pursuant to the 1995 coal arbitration decision.
Changes in other income in 1996 and 1995 are primarily the result of a
non-recurring gain and non-recurring interest income in 1995.
LIQUIDITY AND CAPITAL RESOURCES:
Operating Activities --
Net cash provided by operating activities was $201,091,000 in 1997
compared to $219,077,000 in 1996 and $268,890,000 in 1995. The current year
decrease of $18,000,000 was due primarily to a decrease in income from
operations resulting from weather related impacts on the Utility, increased
power supply costs and decreased revenue from independent power. This was
partially offset by increased revenue from the expansion of the fiber optic
network by the telecommunications operations.
Cash from operating activities less dividends paid provided 58% of net
cash used for investing activities in 1997, 64% in 1996 and 80% in 1995.
Investing Activities --
Net cash used for investing activities was $188,808,000 in 1997 compared
to $194,946,000 in 1996 and $219,740,000 in 1995. The current year decrease of
$6,100,000 was due primarily to a cash flow increase of $108,300,000 from the
sale of non-strategic oil and gas properties in the U.S. and Canada, the sale
of a Brazilian gold mine investment and a $38,700,000 decrease in cash invested
into the reclamation fund. These were mostly offset by an increase in capital
expenditures of $134,700,000 and an increase in other investments of
approximately $6,000,000. Capital expenditures for 1997 were focused on the
Company's efforts to expand its natural gas operations. As a result, the
Company's Nonutility oil and gas operations purchased properties in the Denver
area and the stock of a small Canadian company for approximately $85,000,000
and $26,500,000, respectively. In addition, the Company capitalized
$57,000,000 for the Kerr Project license and mitigation plan in accordance with
a 1997 FERC ruling.
Capital expenditures during the prior three years and forecasted capital
expenditures for 1998 are as follows:
Forecasted Actual
1998 1997 1996 1995
Thousands of Dollars
Utility $ 77,000 $ 138,382 $ 107,085 $ 163,238
Nonutility 99,000 155,390 51,992 67,849
Total $ 176,000 $ 293,772 $ 159,077 $ 231,087
Of the Utility capital expenditures for 1997, 1996 and 1995, generation
accounted for $74,428,000, $19,307,000 and $34,951,000, respectively.
Generation is expected to account for $8,514,000 of the 1998 forecasted
Utility expenditures. The majority of the Utility's capital expenditures
during 1998 are expected to be spent on rehabilitation of steam and
hydroelectric projects, refurbishing electric and natural gas transmission
lines, extending and maintaining electric and natural gas distribution lines
and conservation programs. The majority of the Nonutility's capital
expenditures during 1998 are expected to be spent on development drilling,
facilities and production enhancements of natural gas properties along with
the development of local access phone service and expansion of fiber optic
network in the telecommunications operations.
For 1998, the Company estimates that, by business unit, internally
generated funds will average 87% of its Utility construction program and 64% of
Nonutility capital expenditures. Any remaining capital expenditure balances,
as well as the repayment of maturing long-term debt, will be financed with
short- and long-term debt and with sales of equity securities, the timing and
amounts of which will depend upon future market conditions. The Company
anticipates that it will have adequate sources of external capital to meet its
financing needs.
Financing Activities --
Dividends paid on common and preferred stock were $91,112,000 in 1997,
$95,284,000 in 1996, and $93,600,000 in 1995. During 1997, the regular
quarterly dividend level of 40 cents per share of outstanding stock or $1.60
per share on an annual basis was maintained. The Company's Common Dividend
Policy states that, over time, dividends should reflect long-term growth in
corporate earnings and cash flows, as well as a target payout ratio of 70% of
earnings, provided such dividend levels are sustainable. The declaration of
future dividends is at the discretion of the Board of Directors.
In April 1997, the Company entered into a Revolving Credit Agreement for
certain of its Nonutility operations. Including this facility, the Company's
consolidated borrowing ability under its Revolving Credit and Term Loan
Agreements (Agreements) is $220,000,000, of which $190,000,000 was unused at
December 31, 1997. Under terms of the new agreement, the amount of the
facility decreases on March 31, 1998, reducing the consolidated borrowing
ability under the Agreements to $160,000,000. One agreement terms on
October 27, 1998 and all outstanding borrowing must be repaid at that time. The
Company also has short-term borrowing facilities with commercial banks that
provide both committed and uncommitted lines of credit, and the ability to sell
commercial paper. See Item 8, "Financial Statements and Supplementary Data -
Notes 9 and 10 to the Consolidated Financial Statements for further
information."
In December 1997, Roan Resources Ltd. (Roan), a wholly owned Canadian
subsidiary, purchased the stock of a small Canadian company with oil and gas
properties, for approximately $26,500,000 in U.S. dollars. Financing for the
purchase was provided through an Extendible Revolving Term Credit Agreement
between Roan and the Royal Bank of Canada. The maximum amount of credit
available under this Agreement is $37,800,000 in Canadian dollars which was
reduced to $28,000,000 in Canadian dollars, or $19,627,000 in U.S. dollars, on
January 8, 1998. At December 31, 1997, the amount outstanding under the
agreement was $15,715,000 in U.S. dollars.
The Company's long-term debt as a percentage of capitalization was 37%,
37% and 37% in 1997, 1996 and 1995, respectively. The Company also has entered
into long-term lease arrangements and other long-term contracts for sales and
purchases that are not reflected on its balance sheet. See Item 8, "Financial
Statements and Supplementary Data - Note 3 to the Consolidated Financial
Statements" for additional information.
In addition, $82,000,000 of long-term debt will mature during the year
1998. See Item 8 "Financial Statements and Supplementary Data - Note 9 to the
Consolidated Financial Statements" for details on maturities of long-term debt.
The Company's Mortgage and Deed of Trust contains certain restrictions
upon the issuance of additional First Mortgage Bonds. The Company anticipates
that these restrictions would not preclude it from issuing sufficient First
Mortgage Bonds to meet its bonded debt requirements during 1998, however the
Company does not expect to issue additional First Mortgage Bonds in 1998. There
are no restrictions upon issuance of short-term debt or preferred stock in the
Company's Restated Articles of Incorporation, its Mortgage and Deed of Trust or
its Sinking Fund Debenture Agreement.
As discussed in Item 8, "Financial Statements and Supplementary Data -
Note 4 to the Consolidated Financial Statements", the Company has offered its
electric generation assets for sale along with its power purchase contracts
from qualifying facilities and Basin Electric Power Cooperative. The Company
is evaluating numerous possible uses for the proceeds realized from the sale
including reducing outstanding debt, buying back Company common or preferred
shares of stock or investing in the Company's existing business segments or
new ventures. The Company's Mortgage and Deed of Trust imposes a lien on all
physical properties including the generation assets and pollution control
equipment on some of the thermal generating facilities, therefore,
restrictions may exist on the use of proceeds.
A filing requesting authorization to issue up to $65,000,000 in
transition bonds related to the natural gas transition costs and bond issuance
costs was made to the PSC in November 1997. Issuance of similar bonds was
provided in the electric restructuring legislation, subject to PSC approval. At
this time, due to the uncertainties related to the electric restructuring
filing before the PSC and the expected sale of the electric generation assets
and power purchase contracts, the Company can not determine either the amount
or the timing of the issuance of transition bonds related to electric
transition costs. The Company is evaluating possible uses of proceeds from
potential natural gas and electric transition bond issuances.
SEC RATIO OF EARNINGS TO FIXED CHARGES:
For the twelve months ended December 31, 1997, the Company's ratio of
earnings to fixed charges was 2.94 times. Fixed charges include interest, the
implicit interest of Unit 4 rentals and one-third of all other rental payments.
INFLATION:
Capital intensive businesses, such as the Company's electric and natural
gas utility operations, are significantly and adversely affected by long-term
inflation as neither depreciation nor the ratemaking process reflect the
replacement cost of utility plant. Although prices for natural gas may
fluctuate, earnings of the gas utility operations are not impacted because a
gas cost tracking procedure annually balances gas costs collected from
customers with the costs of supplying gas. As the Company's utility operations
transition to a more competitive environment and considering the intended sale
of the electric generating facilities and power purchase contracts, it is
anticipated that the Company will be less capital intensive in the future and
therefore, impacted less by inflation.
The Nonutility's long-term coal and co-generation natural gas supply
contracts and long-term power sales contracts provide for the adjustment of
prices either through indices, fixed escalations and/or direct pass-through of
costs.
The Company believes that the effects of inflation, at currently
anticipated levels, will not significantly affect results of operations.
YEAR 2000 COMPLIANCE:
As the year 2000 approaches, most companies will face a potentially
serious problem resulting from the possible failure of computer software
programs and other operational electronic systems to recognize calendar dates
beyond the year 1999. This failure could force computers and other electronic
equipment to shut down or create erroneous results.
The Company is currently addressing this "Year 2000" issue to ensure the
availability and integrity of its financial systems. The Company has
established a project team within its central Information Services Department
to ensure that all of its information services software and hardware will be
year 2000 compliant before 2000. The project team reports on a regular basis
to the Company's Board of Directors. At this time, the Company does not
expect the costs of year 2000 compliance for its information services function
to have a material impact on its future results of operations.
The Company is also in the process of identifying the other operational
systems which have embedded electronic microprocessors that could be affected
by this issue. The officers of the various business units have been given the
responsibility for addressing these operational/process control issues as they
relate to the year 2000. Although it is not currently possible to estimate the
overall cost of the required modifications, the Company presently believes
that the ultimate cost of this work will not have a material effect on the
Company's current financial position, liquidity or results of operations.
The year 2000 issue may also impact other entities with which the
Company transacts business or with which the Company's electric and natural
systems are interconnected. The Company cannot estimate the potentially
adverse consequences, if any, which could result from such entities failure to
adequately address the year 2000 issue.
NEW ACCOUNTING PRONOUNCEMENTS:
During June 1997, the FASB released SFAS No. 130, "Reporting
Comprehensive Income". SFAS No. 130 requires the reporting in the financial
statements of all items recognized as components of comprehensive income which
is defined as changes in equity during the period from transactions, events or
circumstances from non-owner sources. The statement is effective for fiscal
years beginning after December 15, 1997.
Also during June 1997, the FASB released SFAS No. 131, "Disclosures
about Segments of an Enterprise and Related Information". SFAS No. 131
requires the disclosure of certain operating information in complete financial
statements as well as condensed statements for interim periods issued to
shareholders. The statement is effective for financial statements for periods
beginning after December 15, 1997.
The Company is evaluating SFAS No. 130 and SFAS No. 131 at this time to
determine the effects on the financial statements and related disclosures.
Although the statements will affect the presentation of the information, they
are not expected to materially affect the Company's financial position or
results of operations.
ENVIRONMENTAL ISSUES:
The Company is committed to do its part to protect, maintain and enhance
the environment. The diversity of the Company's business activities subjects
it to numerous federal, state and local environmental laws and regulations
relating to pollution control and prevention, and environmental remediation.
The primary federal environmental laws and regulations affecting the Company
are: the Clean Air Act; the Clean Water Act; the Comprehensive Environmental
Response, Compensation and Liability Act (CERCLA); the Resource Conservation
and Recovery Act; the Oil Pollution Prevention Act; the Safe Drinking Water
Act; the Toxic Substances Control Act; the Hazardous Materials Transportation
Act; the Emergency Planning and Community Right to Know Act; the Surface
Mining Control and Reclamation Act; and the National Environment Policy Act.
The Company has established reserves for its minimum estimated costs
associated with reasonably foreseeable potential environmental clean-up costs;
it does not expect these costs to materially impact the results of its
operations.
CERCLA, and some of its state counterparts, give rise to loss
contingencies for future site remediation because they may require the Company
to remove or mitigate the adverse environmental effects resulting from the
disposal or release of certain substances at previously owned or present
Company sites, or at sites where these substances were disposed. The total
amount of costs associated with current site remediation efforts and future
remediation is unknown both because (1) the Company may not know of all sites
for which it is responsible and (2) it cannot currently predict with any
degree of certainty the total costs for those sites it has identified. Current
indications are that the known costs will not have a materially adverse effect
on the Company or its operations.
Under CERCLA, the Company has been named a potentially responsible
party (PRP) at the Silver Bow Creek/Butte Area Superfund Site. The PRPs have
cooperated to identify the extent of groundwater and soil contamination due
principally to decades of copper mining. The Company has spent $538,000 to
investigate contamination attributed to its ownership of property. Consultants
employed by the PRPs have made preliminary estimates indicating that clean-up
costs could range from $20,000,000 to $60,000,000. While the Company denies
any responsibility greater than a "diminimis" contributor for costs associated
with this contamination, if the Company is found to have a greater
responsibility, it would have to share a portion of the costs ultimately
related to the handling of the contamination proportionate to its
contribution. Other contamination at this site involves petroleum
hydrocarbons, low level concentrations of polychlorinated biphenyls (PCB's)
and arsenic. Clean up of this contamination will be accomplished by the
Company as an issue apart from its involvement with this superfund site at a
cost which is not expected to be material.
The Thompson Falls Reservoir has been identified by the Montana
Department of Environmental Quality (MDEQ) as a CECRA site which is the state
equivalent of a National Priority List site (Superfund). Elevated levels of
copper, zinc and possibly arsenic were found in the bottom sediments by
researchers in 1985-1986. EPA declared the site a "No Further Action" site
under CERCLA. MDEQ identified the site as a Low Priority Site because of low
direct contact hazard and the lack of evidence of migration to groundwater
supplies. There has been no attempt to quantify the cost to clean up the
sediments.
The Company or its predecessors owned and operated manufactured gas
plants on three sites, one in each of Helena, Butte and Missoula, Montana.
Voluntary work to assess and clean up these sites has been undertaken.
All of the Company's coal-fired units have been designated as Phase II
Units under Title IV (Acid Rain) of the Clean Air Act Amendments of 1990 (Act)
which imposes certain sulfur dioxide and nitrogen oxide requirements. All of
the Company's coal-fired plants comply with the sulfur dioxide requirements.
The nitrogen oxide standard for Phase II Units, effective in the year
2000, is more stringent than the standard imposed upon Phase I Units. However,
the Act provides Phase II Units with the option to comply, beginning January 1,
1997, with the Phase I standards and defer, until 2008, compliance with the
more stringent Phase II standards. Because the Company had determined that the
Colstrip Units could meet the Phase I nitrogen oxide standards by January 1,
1997, it exercised this option for the Colstrip plants. For calendar year 1997,
the Colstrip plants met the early election standard. The Company did not
exercise this option for its Corette Plant. However, in 1997 the Company
installed a low nitrogen oxide burner system on the Corette boiler. The cost
of the system and installation was approximately $1,000,000. Since the system
has been in place it has performed well within the Phase II standards. The
costs associated with any modifications that ultimately may be required to
comply with Phase II nitrogen oxide standards have not been determined.
Impacts to groundwater and Armells' Creek have been documented from the
Colstrip Project's process water disposal system or process water spills.
Study and mitigation efforts are underway in consultation with the MDEQ to
address the impacts. Estimated annual expenses to manage this issue are
estimated to be $50,000. One-time capital expenditures are estimated to range
from $100,000 to $4,000,000, depending upon the design ultimately determined
necessary to remedy the problem.
The Company's Canadian subsidiaries are involved in an ongoing cleanup of
old flare pits, and abandoned wells and production sites. Approximately 50
sites are under active reclamation. Cleanup of 30 sites has been completed, and
25 sites are either waiting for final certification from Alberta Environmental,
or are in the final monitoring of vegetation growth prior to applying for
cleanup certification. Since 1995, the Company has spent approximately
$630,000 (Canadian) for cleanup of the completed sites. Cleanup activity will
continue for the next five to ten years under the direction of Alberta
Environmental. Approximately 20 shut-in or abandoned wells do not have any
appreciable environmental damage, and clean up activity is not expected at
these sites.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA
Page
Management's Responsibility for Financial Statements 56
Report of Independent Accountants 57
Consolidated Financial Statements:
Consolidated Statements of Income for the Years Ended
December 31, 1997, 1996 and 1995 58
Consolidated Balance Sheets as of December 31, 1997 and 1996 59-60
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1997, 1996 and 1995 61
Consolidated Statements of Common Shareholders' Equity for the
Years Ended December 31, 1997, 1996 and 1995 62
Notes to Consolidated Financial Statements 63-95
Supplementary Data (Unaudited) 96-103
Financial Statement Schedules for the Years Ended December 31,
1997, 1996 and 1995:
Schedule II - Valuation and Qualifying Accounts and Reserves 109
Financial statement schedules not included in this Form 10-K Annual Report have
been omitted because they are not applicable or the required information is
shown in the Consolidated Financial Statements or notes thereto.
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS
The management of The Montana Power Company is responsible for the
preparation and integrity of the consolidated financial statements of the
Company. These financial statements have been prepared in accordance with
generally accepted accounting principles which are consistently applied, and
appropriate in the circumstances. In preparing the financial statements,
management makes appropriate estimates and judgments based upon available
information. Management also prepared the other financial information in the
annual report and is responsible for its accuracy and consistency with the
financial statements.
Management maintains systems of internal accounting control which are
adequate to provide reasonable assurance that the financial statements are
accurate, in all material respects. The concept of reasonable assurance
recognizes that there are inherent limitations in all systems of internal
control in that the costs of such systems should not exceed the benefits to be
derived. Management believes the Company's systems provide this appropriate
balance.
The Company maintains an internal audit function that independently
assesses the effectiveness of the systems and recommends possible improvements.
Price Waterhouse LLP, the Company's independent accountants, also considered
the systems in connection with its audit. Management has considered the
internal auditors' and Price Waterhouse LLP's recommendations concerning the
systems and has taken cost-effective actions to respond appropriately to these
recommendations.
The Board of Directors, acting through an Audit Committee composed
entirely of directors who are not employees of the Company, is responsible for
determining that management fulfills its responsibilities in the preparation of
the financial statements. The Audit Committee recommends, and the Board of
Directors appoints, the independent accountants. The independent accountants
and internal auditors are assured of full and free access to the Audit
Committee and meet with it to discuss their audit work, the Company's internal
controls, financial reporting and other matters. The Committee is also
responsible for determining that there is adherence to the Company's Code of
Business Conduct (Code). The Code addresses, among other things, potential
conflicts of interests and compliance with laws, including those relating to
financial disclosure and the confidentiality of proprietary information.
The financial statements have been audited by Price Waterhouse LLP, which
is responsible for conducting its examination in accordance with generally
accepted auditing standards.
/s/ Robert P. Gannon /s/ J. P. Pederson
R. P. Gannon J. P. Pederson
Chairman of the Board and Vice President and Chief
Chief Executive Officer Financial and Information
Officer
Report of Independent Accountants
February 5, 1998
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, 1997
and 1996, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 1997, in conformity with
generally accepted accounting principles. These financial statements are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with generally accepted auditing
standards which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management,
and evaluating the overall financial statement presentation. We believe that
our audits provide a reasonable basis for the opinion expressed above.
As discussed in Note 1 to the consolidated financial statements, the Company
changed its method of accounting for impairments of long-lived assets beginning
in 1995.
/s/ PRICE WATERHOUSE LLP
Portland, Oregon
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENT OF INCOME
The Montana Power Company and Subsidiaries
Year Ended December 31
1997 1996 1995
Thousands of Dollars
<S> <C> <C> <C>
REVENUES $1,023,597 $ 973,208 $ 953,224
EXPENSES:
Operations 415,979 381,550 420,472
Maintenance 75,994 68,181 68,286
Selling, general and administrative 124,244 113,485 104,213
Taxes other than income taxes 96,214 87,903 89,858
Depreciation, depletion and amortization 94,664 86,403 84,635
Writedowns of long-lived assets 74,297
807,095 737,522 841,761
INCOME FROM OPERATIONS 216,502 235,686 111,463
INTEREST EXPENSE AND OTHER INCOME:
Interest 54,667 48,770 43,656
Distributions on mandatorily redeemable
preferred securities of subsidiary
trust 5,492
Other (income) deductions - net (34,159) (4,445) (10,704)
26,000 44,325 32,952
INCOME TAXES 61,870 71,975 21,574
NET INCOME 128,632 119,386 56,937
DIVIDENDS ON PREFERRED STOCK 3,690 8,358 7,227
NET INCOME AVAILABLE FOR COMMON STOCK $ 124,942 $ 111,028 $ 49,710
AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING (000) 54,649 54,634 54,121
BASIC EARNINGS PER SHARE OF COMMON STOCK $ 2.29 $ 2.03 $ 0.92
DILUTED EARNINGS PER SHARE OF COMMON
STOCK $ 2.28 $ 2.03 $ 0.92
The accompanying notes are an integral part of these statements.
</TABLE>
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEET
The Montana Power Company and Subsidiaries
ASSETS
December 31
1997 1996
Thousands of Dollars
<S> < C> <C>
PLANT AND PROPERTY IN SERVICE:
Utility plant $2,216,198 $2,236,309
Less - accumulated depreciation and depletion 684,960 705,119
1,531,238 1,531,190
Nonutility property 781,406 666,679
Less - accumulated depreciation and depletion 260,567 256,489
520,839 410,190
2,052,077 1,941,380
MISCELLANEOUS INVESTMENTS:
Independent power investments 51,534 53,035
Reclamation fund 47,312 43,001
Other 35,619 39,531
134,465 135,567
CURRENT ASSETS:
Cash and temporary cash investments 16,706 32,404
Accounts receivable 126,787 142,347
Materials and supplies (principally at average cost) 39,471 39,322
Prepayments and other assets 49,673 49,041
Deferred income taxes 10,539 11,095
243,176 274,209
DEFERRED CHARGES:
Advanced coal royalties 16,698 19,298
Regulatory assets related to income taxes 122,903 149,150
Regulatory assets - other 158,573 109,141
Other deferred charges 73,804 69,470
371,978 347,059
$2,801,696 $ 2,698,215
The accompanying notes are an integral part of these statements.
</TABLE>
<TABLE>
<CAPTION>
LIABILITIES
December 31
1997 1996
Thousands of Dollars
<S> <C> <C>
CAPITALIZATION:
Common shareholders' equity:
Common stock (120,000,000 shares without par
value authorized; 54,728,709 and 54,630,994
shares issued) $ 694,561 $ 691,853
Retained earnings and other shareholders' equity 342,973 307,804
Unallocated stock held by trustee for Retirement
Savings Plan (25,945) (28,360)
1,011,589 971,297
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 653,168 633,339
1,787,411 1,727,290
CURRENT LIABILITIES:
Short-term borrowings 133,958 104,702
Long-term debt-portion due within one year 81,659 69,268
Dividends payable 22,684 22,707
Income taxes 3,803 11,083
Other taxes 47,818 41,667
Accounts payable 77,821 62,218
Interest accrued 13,836 11,909
Other current liabilities 35,158 41,155
416,737 364,709
DEFERRED CREDITS:
Deferred income taxes 340,251 332,861
Investment tax credits 35,182 44,467
Accrued mining reclamation costs 131,108 129,878
Other deferred credits 91,007 99,010
597,548 606,216
CONTINGENCIES AND COMMITMENTS (Notes 2 and 3)
$2,801,696 $2,698,215
The accompanying notes are an integral part of these statements.
</TABLE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENT OF CASH FLOWS
The Montana Power Company and Subsidiaries
Year Ended December 31
1997 1996 1995
Thousands of Dollars
<S> <C> <C> <C>
NET CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 128,632 $ 119,386 $ 56,937
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation, depletion and amortization 94,664 88,744 86,976
Writedowns of long-lived assets 74,297
Deferred income taxes 10,677 15,430 (11,819)
Noncash earnings from unconsolidated
independent power investments (14,016) (11,505) (2,314)
Reclamation expenses and payments - net 1,230 7,870 7,411
Deferred stripping expenses and
payments - net (696) (787) 1,239
Losses (gains) on sales of property and
investments (33,849) 2,532 (1,736)
Other - net 24,145 15,240 10,866
Changes in current assets and liabilities:
Accounts receivable 15,560 10,039 7,589
Materials and supplies (149) 2,872 5,743
Accounts payable 15,603 (1,702) 13,132
Other assets and liabilities (40,710) (29,042) 20,569
Net cash provided by operating activities 201,091 219,077 268,890
NET CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (293,772) (159,077) (231,087)
Reclamation funding (4,311) (43,001)
Sales of property and investments 117,663 9,387 13,987
Additional investments (8,388) (2,255) (2,640)
Net cash used for investing activities (188,808) (194,946) (219,740)
NET CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends paid (91,112) (95,284) (93,600)
Sales of common stock 2,201 798 23,465
Redemption of preferred stock (44,415)
Issuance of long-term debt 103,375 82,890 50,758
Retirement of long-term debt (71,634) (22,236) (18,155)
Issuance of mandatorily redeemable preferred
securities (67) 62,625
Net change in short-term borrowing 29,256 8,354 (17,641)
Net cash used for financing activities (27,981) (7,268) (55,173)
CHANGE IN CASH FLOWS (15,698) 16,863 (6,023)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR 32,404 15,541 21,564
CASH AND CASH EQUIVALENTS, END OF YEAR $ 16,706 $ 32,404 $ 15,541
SUPPLEMENTAL DISCLOSURES OF CASH FLOW:
Cash paid during the year for:
Income taxes, net of refunds $ 50,797 $ 52,470 $ 33,087
Interest 59,681 49,962 46,141
The accompanying notes are an integral part of these statements.
</TABLE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENT OF COMMON SHAREHOLDERS' EQUITY
The Montana Power Company and Subsidiaries
Year Ended December 31
1997 1996 1995
Thousands of Dollars
<S> <C> <C> <C>
COMMON STOCK:
Balance at beginning of year $ 691,853 $ 691,043 $ 667,344
Issuances (97,715; 16,513;
and 1,034,744 shares) 2,708 810 23,699
Balance at end of year 694,561 691,853 691,043
RETAINED EARNINGS AND OTHER SHAREHOLDERS'
EQUITY:
Balance at beginning of year 307,804 285,000 320,756
Net income 128,632 119,386 56,937
Dividends on common stock ($1.60
per share each year) (87,494) (87,432) (86,791)
Dividends on preferred stock (3,690) (7,705) (7,227)
Other (2,279) (1,445) 1,325
Balance at end of year 342,973 307,804 285,000
UNALLOCATED STOCK HELD BY TRUSTEE FOR
RETIREMENT SAVINGS:
Balance at beginning of year (28,360) (30,565) (32,580)
Distributions 2,415 2,205 2,015
Balance at end of year (25,945) (28,360) (30,565)
TOTAL COMMON SHAREHOLDERS' EQUITY AT
END OF YEAR $1,011,589 $ 971,297 $ 945,478
The accompanying notes are an integral part of these statements.
</TABLE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - Summary of significant accounting policies:
Basis of accounting:
The Company's accounting policies conform to generally accepted
accounting principles. With respect to utility operations, such policies are
in accordance with the accounting requirements and ratemaking practices of the
regulatory authorities having jurisdiction.
Use of estimates:
Preparing financial statements requires the use of estimates. Management
makes appropriate estimates and judgments based upon available information.
Actual results may differ from accounting estimates as new events occur or
additional information is obtained.
Consolidation principles:
The Consolidated Financial Statements include the accounts of the Company
and its subsidiaries, all of which are wholly-owned. Significant intercompany
balances and transactions have been eliminated. Independent power investments
are accounted for using either the cost or equity method depending on the
Company's ability to exercise control over the operations of the particular
investment.
Plant, property, depreciation and amortization:
The cost of additions to and replacement of plant, including an allowance
for funds used during construction of utility plant (AFUDC), is capitalized.
The rate used to compute AFUDC is determined in accordance with a formula
established by the Federal Energy Regulatory Commission (FERC) and was an
average of 8.0% for 1997, 7.2% for 1996 and 8.1% for 1995. Costs of utility
depreciable units of property retired plus costs of removal less salvage are
charged to accumulated depreciation. Gain or loss is recognized upon the sale
or other disposition of Nonutility property. Maintenance and repairs of plant
and property as well as replacements and renewals of items determined to be
less than established units of plant are charged to operating expenses.
The year-end balances of the major classifications of property, plant and
equipment are detailed in the following table:
December 31
1997 1996
Thousands of Dollars
Utility plant:
Electric:
Generation (including
jointly-owned) $ 718,504 $ 704,057
Transmission 364,638 352,993
Distribution 520,213 487,937
Other 216,925 175,728
Natural Gas:
Production and storage 70,337 193,432
Transmission 148,295 146,072
Distribution 138,676 128,877
Other 38,610 47,213
Total Utility 2,216,198 2,236,309
Nonutility plant:
Coal 241,835 255,788
Oil and natural gas 363,193 274,880
Technology 86,617 48,069
Electric generation 75,585 75,298
Other 14,176 12,644
Total Nonutility 781,406 666,679
Total Plant $2,997,604 $2,902,988
Included in the plant classifications are Utility plant under
construction in the amounts of $39,425,000 and $52,125,000 for 1997 and 1996,
respectively and Nonutility plant under construction in the amounts of
$17,259,000 and $39,252,000 for 1997 and 1996, respectively.
The Company's open-access and reorganization plan for the natural gas
utility was approved for implementation, effective November 1, 1997. Under
the approved plan, almost all of the natural gas production assets of the
Utility, including those of its subsidiary, Canadian Montana Gas, were
transferred to an unregulated affiliate as of that date. For further
information, see "Financial Statements and Supplementary Data - Note 4 to the
Consolidated Financial Statements".
Provisions for depreciation and depletion are recorded at amounts
substantially equivalent to calculations made on straight-line and
unit-of-production methods by application of various rates based on useful
lives of properties determined from engineering studies. The provisions for
Utility depreciation and depletion approximated 3.0% for 1997, 2.9% for 1996
and 2.7% for 1995 of the depreciable and depletable Utility plant at the
beginning of the year.
The Company's Nonutility oil and natural gas operations use the
successful efforts method of accounting for exploration and development costs.
Jointly owned electric plant:
The Company is a joint-owner of Colstrip Units 1, 2 and 3 and of
transmission facilities serving these Units. At December 31, 1997, the
Company's joint ownership percentage and investment in these Units and
transmission facilities were:
Units Transmission
1 & 2 Unit 3 Facilities
Thousands of Dollars
Ownership 50% 30% 30%*
Plant in service $ 184,943 $ 286,122 $ 45,229
Plant under construction 507 66 7
Accumulated depreciation 96,206 106,290 13,076
*This is an approximate ownership percentage based on capacity rights
on the various segments of the transmission system.
The Company also owns $42,251,000 and $33,341,000 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. This plant had related accumulated depreciation of
$16,727,000 and $7,748,000, respectively.
Each joint-owner provides its own financing. The Company's share of
direct expenses associated with the operation and maintenance of these joint
facilities is included in the corresponding operating expenses in the
Consolidated Statement of Income.
Reclamation fund:
As a result of a 1996 coal arbitration decision, the Company established
a reclamation fund, representing restricted cash equal to a portion of its
accumulated reclamation liability plus interest. The fund increases as
reclamation expenses are collected from customers and all proceeds are invested
until reclamation is performed. At December 31, 1997, the fund was invested
entirely in a money market account. The Company regularly accrues an expense
and an offsetting liability associated with its reclamation obligation.
Establishment of the reclamation fund had no effect on the Company's
accumulated liability.
Utility revenue and expense recognition:
Operating revenues are recorded on the basis of service rendered. In
order to match revenues with associated expenses, the Company accrues unbilled
revenues for electric and natural gas services delivered to customers but not
yet billed at month-end.
Regulatory assets and liabilities:
For its regulated operations, the Company follows SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation." Pursuant to this
pronouncement, certain expenses and credits, normally reflected in income as
incurred, are recognized when included in rates and recovered from or refunded
to the customers. As such, the Company has recorded the following regulatory
assets and liabilities that will be recognized in expenses and revenues in
future periods when the matching revenues are collected.
1997 1996
Assets Liabilities Assets Liabilities
Thousands of Dollars
Income taxes $ 119,643 $ 146,736
Colstrip Unit 3
carrying charge 42,156 43,987
Conservation programs 33,965 41,372
Competitive transition
charges 58,983
Investment tax credits $ 35,182 $ 44,467
Other 42,344 8,743 49,174 12,206
Subtotal 297,091 43,925 281,269 56,673
Less:
Current portions 15,615 2,522 22,978 3,194
Total $ 281,476 $ 41,403 $ 258,291 $ 53,479
Income taxes reflect the impacts of temporary differences that will be
recovered in rates in future periods. The Montana Public Service Commission
(PSC) provided in its August 1985 order a carrying charge and recovery of
depreciation that were deferred and are being amortized to income over the
remaining 23-year life of Colstrip Unit 3 to compensate the Company for
unrecovered costs of its investment for the period the plant was in service
from January 10, 1984 to August 29, 1985. Conservation programs represent the
Company's Demand Side Management (DSM) programs that are in rate base and are
being amortized to income over a ten-year period. The competitive transition
charges, which relate to natural gas properties that were removed from
regulation on November 1, 1997, are being recovered through rates over 15
years. Investment tax credits and account balances included in Other are either
being amortized currently or are those items subject to regulatory confirmation
in future regulatory proceedings.
Changes in regulation or changes in the competitive environment could
cause recovery of these costs through rates to become uncertain, resulting in
the Company not meeting the criteria of SFAS No. 71. If the Company were to
discontinue application of SFAS No. 71 for some or all of its operations, the
regulatory assets and liabilities related to those portions would have to be
eliminated from the balance sheet and included in income in the period when
the discontinuation occurred unless recovery of those costs was provided
through rates charged to those customers in a portion of the business that
remains regulated. In conjunction with the ongoing changes in the electric
and natural gas industries, the Company will continue to evaluate the
applicability of this accounting principal to those businesses.
As a consequence of the issuance by the PSC of the natural gas
restructuring order, the Company's natural gas production assets were removed
from SFAS No. 71 accounting in the fourth quarter of 1997. The timing of the
removal of the electric generating assets from SFAS No. 71 has not yet been
determined. Recovery of Company's existing regulatory assets related to the
natural gas production assets was provided in the order and recovery of
existing regulatory assets related to electric generation is provided in the
electric restructuring legislation.
Cash and cash equivalents:
The Company considers all liquid investments with original maturities of
three months or less to be cash equivalents.
Storm damage and environmental remediation costs:
The estimated costs of storm damage and environmental remediation
obligations for Utility operations are charged against established, regulator
approved operating reserves when such losses are probable and reasonably
estimable. The reserves are adequate to provide for all known obligations and
may be increased, if appropriate, by adjusting the annual accrual rate. The
reserves' balances at December 31, 1997 and 1996 were approximately $2,600,000
and $3,600,000, respectively, and are included in current liabilities on the
Consolidated Balance Sheet.
Income taxes:
The Company and its U.S. subsidiaries file a consolidated U.S. income tax
return. Consolidated U.S. income taxes are allocated to Utility and Nonutility
operations as if separate U.S. income tax returns were filed. Deferred income
taxes are provided for the temporary differences between the financial
reporting basis and the tax basis of the Company's assets and liabilities.
Net income per share of common stock:
Basic net income per share of common stock is computed for each year
based upon the weighted average number of common shares outstanding. In
accordance with Statement of Financial Accounting Standards No. 128, "Earnings
per Share", diluted net income per share of common stock reflects the potential
dilution that could occur if securities or other contracts to issue common
stock were exercised or converted into common stock or resulted in the issuance
of common stock that shared in the earnings of the Company.
Change in accounting method:
At December 31, 1996, the Company, through one of its Nonutility
subsidiaries, changed its ownership interest in one of its independent power
investments which had been accounted for on the cost basis method of
accounting. As a result of this change, the Company may now exercise
significant influence over the operations of the investment and therefore has
elected to change to the equity basis method of accounting for the investment
at December 31, 1996. The accounting change did not effect previously reported
net income or earnings per share.
Asset impairment:
Effective October 1, 1995, the Company adopted Statement of Financial
Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to Be Disposed Of" (SFAS No. 121). Under
SFAS No. 121, a test is required to determine whether the carrying amount of
long-lived and certain intangible assets may be recoverable through future
undiscounted cash flows. In 1995, the Company recorded a before tax charge
against income of $74,300,000. The impairment included a $46,500,000 before
tax charge to record the writedown of the assets and to recognize the closure
liabilities of the Company's subsidiary, Basin Resources, Inc. The Company
performs quarterly reviews for SFAS No. 121 impairments. The Company has had
no other significant writedowns under SFAS No. 121.
Derivative financial instruments:
The Company has a formal policy regarding the execution, recording, and
reporting of derivative instruments. The purpose of the policy is to manage a
portion of the price risk associated with its Nonutility producing assets and
firm-supply commitments. The Company uses derivatives as hedging instruments
to achieve revenue targets, reduce earnings volatility, and provide stable
cash flow. When fluctuations in natural gas and crude oil market prices result
in the Company realizing gains on the price swap agreements into which it has
entered, the Company is exposed to credit risk relating to the nonperformance
by counterparties of their obligation to make payments under the agreements.
Such risk to the Company is mitigated by the fact that the counterparties, or
the parent companies of such counterparties, are investment grade financial
institutions. The Company does not anticipate any material impact to its
financial position, results of operations or cash flow as a result of
nonperformance by counterparties.
To manage a portion of Nonutility price risk, the Company uses a variety
of derivative instruments including crude oil and natural gas swap, collar,
and cap agreements to hedge revenue from anticipated production of crude oil
and natural gas reserves and supply costs to its firm markets. Under swap
agreements, the Company receives or makes payments based on the differential
between a specified price and a variable price of oil or natural gas when the
hedged transaction is settled. The variable price is either a crude oil or
natural gas price quoted on the New York Mercantile Exchange or a quoted
natural gas price in Inside FERC's Gas Market Report or other recognized
industry index. These variable prices are highly correlated with the market
prices received by the Company for its natural gas and crude oil production.
Under collar agreements, the Company makes or receives monthly payments at the
settlement date when the actual price of oil or natural gas exceeds the
ceiling or drops below the floor established in the agreement. Under cap
agreements, the Company makes or receives monthly payments at the settlement
date based on the differential between the actual price of oil or natural gas
and the cap established in the agreement depending on whether the Company
sells or buys a cap. At December 31, 1997, the Company had no hedge
agreements on crude oil. The Company had cap and swap agreements on
approximately 1.7 Bcf of Nonutility natural gas; or 14% of its expected
production from proved, developed and producing Nonutility natural gas
reserves through November 1998. In addition, the Company had swap and collar
agreements to hedge approximately 1.8 Bcf of Nonutility natural gas, or 19% of
its expected delivery obligations under long-term natural gas sales contracts
through September 1998.
The Company accounts for derivative transactions through hedge
accounting. The Company designates all its derivatives as fair value hedges.
A fair value hedge is based on the following criteria:
? The hedged item is specifically identified as a recognized asset or an
anticipated commitment.
? The hedged item is a single asset or a portfolio of similar assets.
? The hedged item presents an exposure to changes in fair value for the
hedged risk that could affect earnings.
? The hedged item is not an asset or liability that is measured at fair value
with changes in fair value attributable to the hedged risk reported
currently in earnings.
Gains or losses from these price swap agreements are reflected in
operating revenues on the Consolidated Statement of Income at the time of
settlement with the other parties. The Company uses the accrual method to
record its gains or losses. If the Company terminates a price swap agreement
prior to the date of the anticipated natural gas or crude oil production, the
gain or loss from the agreement is deferred in the Consolidated Balance Sheet
at the termination date. When the anticipated natural gas or crude oil
production occurs, the gain or loss from the price swap agreement is
recognized in the Consolidated Statement of Income. If the Company determines
that a portion of its anticipated natural gas or crude oil production will not
occur, thus creating a matching problem between the price swap agreements and
the anticipated production, any such unmatched price swap agreements are
marked-to-market and any unrealized gain or loss is recorded in the
Consolidated Statement of Income. At December 31, 1997, the Company had no
material deferred gains or losses related to these transactions.
The Company also has investments in independent power partnerships, some
of which have entered into derivative financial instruments to hedge against
interest rate exposure on floating rate debt and foreign currency and natural
gas price fluctuations. At December 31, 1997, the Company believes it would not
experience any materially adverse impacts from the risks inherent in these
instruments.
Fair value of financial instruments:
1997 1996
Carrying Fair Carrying Fair
Amount Value Amount Value
Thousands of Dollars
Assets:
Investments in independent
power projects (cost basis
only) $ 5,584 $ 9,063 $ 6,090 $ 10,300
Reclamation fund 47,312 47,312 43,001 43,001
Other significant investments 34,704 34,704 35,449 39,837
Liabilities:
Mandatorily redeemable preferred
securities $ 65,000 $ 70,850 $ 65,000 $ 67,600
Long-term debt(including due
within one year) 734,827 743,713 702,607 717,504
The following methods and assumptions were used to estimate fair value:
Investments in independent power projects - The fair value represents the
Company's assessment of the present value of net future cash flows embodied in
these investments, discounted to reflect current market rates of return.
Reclamation fund and other investments - The carrying value of most of
the investments approximates fair value as the investments have short
maturities or the carrying value equals their cash surrender value. Fair value
for the remainder of the investments was estimated based on the discounted
value of the future cash flows expected to be received using a rate of return
expected on similar current investments.
Mandatorily redeemable preferred securities and long-term debt - The fair
value was estimated using quoted market rates for the same or similar
instruments. Where quotes were not available, fair value was estimated by
discounting expected future cash flows using year-end incremental borrowing
rates.
NOTE 2 - Contingencies:
In July 1985, the Federal Energy Regulatory Commission (FERC) issued to
the Company a new license for the 180 megawatt Kerr Project (Project) and
required the subsequent adoption of conditions to mitigate the impact of
Project operations on fish, wildlife, and habitat. The Company proposed a
consensus plan in June 1990 that was agreed to by the Confederated Salish and
Kootenai Tribes (Tribes) and other state and federal resource agencies. In
November 1995, the United States Department of Interior (Department) submitted
alternative conditions to those stated in the Company's plan.
On June 25, 1997, FERC approved a mitigation plan, substantially adopting
the Department's conditions. The mitigation plan calls for payments totaling
approximately $135,000,000 over the 35-year term of the license. The net
present value of the total amount, using an assumed discount rate of 9.5%, is
approximately $57,000,000, which the Company recognized as license costs in
plant and long-term debt in the Consolidated Balance Sheet during the second
quarter of 1997.
The Company, the Tribes and the Department requested rehearing of FERC's
June 25, 1997 order. The Company asserted that the Department's conditions are
unreasonable and that FERC should modify them. In the event FERC does not
modify the mitigation plan it ordered, the Company expects to seek judicial
review.
In November 1992, the Company applied to FERC to relicense nine Madison
and Missouri River hydroelectric projects, with generating capacity of 292
megawatts. On September 26, 1997, FERC Staff issued its draft environmental
impact statement, recommending acceptance of most of the measures proposed by
the Company in its application. FERC Staff recommended adoption of limited
additional measures. The Company is analyzing the recommendations to prepare
comments. Preliminary analysis suggests that the FERC Staff's recommendations
do not materially change the cost of relicensing and proposed environmental
mitigation, previously estimated to be approximately $158,000,000 on a net
present value basis. The Company expects to receive a license order in late
1998 or early 1999.
Western Energy Company (Western), a subsidiary of the Company, is a
party in a dispute concerning the Coal Supply Agreement for Colstrip Units 3
and 4 with the non-operating owners (NOOs), other than Puget Sound Energy
(Puget). Puget withdrew from this dispute as part of a settlement concerning
a power sales agreement between Puget and the Company. During the spring of
1996, the Consumer Price Index (CPI) doubled when compared to the CPI level at
the time that the Coal Supply Agreement was executed. Under the terms of the
Coal Supply Agreement, this change in the CPI allows any party to seek a
modification of the coal price if that party can demonstrate an "unusual
condition" causing a "gross inequity." These NOOs are asserting that a number
of "unusual conditions" have occurred, including (i) the deregulation of
various aspects of the electric utility industry, (ii) increased scrutiny of
electric utilities by their public utility commissions, and (iii) changes in
economic conditions not anticipated at the time of execution of the Coal
Supply Agreement. These NOOs claim these "unusual conditions" have created a
"gross inequity" that must be remedied by a reduction in the coal price.
Western does not believe that under the terms of the contract any "unusual
condition" or "gross inequity" has occurred.
Western, the Company and these NOOs are seeking to resolve this dispute
as part of an on-going mediation to restructure the relationship of the NOOs,
including Puget, the Company and Western at the Colstrip Project. The outcome
of this dispute or the restructuring mediation is uncertain.
Houston Lighting & Power (HL&P), the purchaser of lignite produced by
Northwestern Resources Co. (Northwestern), a Company subsidiary, filed
litigation on October 5, 1995 in the District Court of the 157th Judicial
District, Harris County, Texas, seeking, among other remedies, a declaratory
judgment that changed conditions required a renegotiation of management and
dedication fees paid to Northwestern under the terms of the Lignite Supply
Agreement (LSA) between it and Northwestern. The LSA governs the delivery of
approximately 9,000,000 tons of lignite per year and is effective until
July 29, 2015. Under the terms of the LSA, Northwestern realizes approximately
$25,000,000 per year from these fees. HL&P alleged Northwestern failed to
renegotiate these fees in good faith. HL&P sought a reduction exceeding 60% in
the LSA fees. It alleged that the reduction should be retroactive to
September 1, 1995. Additionally, HL&P sought a declaration that it may
substitute other fuels for lignite without violating the LSA.
Trial concluded in December 1997 with the jury denying all of HL&P's
claims regarding changed circumstances and Northwestern's alleged obligations
to negotiate reduced fees. Thus, current pricing under the terms of the LSA is
unchanged. In a pretrial summary judgment, the trial court concluded other
fuel may be substituted for lignite at the Limestone Plant. The court has not
entered judgment and the time for filing appeals has not begun to run.
Northwestern believes it will maintain a price for lignite that is competitive
with alternate fuels.
The Company and its subsidiaries are party to various other legal
claims, actions and complaints arising in the ordinary course of business.
Management does not expect disposition of these matters to have a material
adverse effect on the Company's consolidated financial position or its
consolidated results of operations.
NOTE 3 - Commitments:
Purchase commitments:
In 1994, the Company entered into a contract to purchase 98 megawatts of
seasonal capacity from Basin Electric Power Cooperative (Basin). The rate for
the contract year beginning in November 1997 will be approximately 3.2 cents
per kWh and will increase each subsequent year to approximately 6.9 cents per
kWh in the final contract year, which begins in November 2009. In conjunction
with the Company's proposed sale of electric generating facilities, the
Company also intends to sell or reassign this contract. Although not
specifically named in the restructuring legislation, costs associated with
disposal and reassignment of this contract are also expected to be collected
through the Competitive Transition Charges (CTC).
The Company also has long-term purchase contracts with certain qualifying
facilities (QF's) and natural gas producers. The purchased power contracts
provide for capacity payments subject to a facility meeting certain operating
standards, and payments based on energy received. The Company currently has 15
QF contracts, with expiration terms ranging from 2000 through 2031. Three
contracts account for 96% of the 101 MWs of capacity provided by these
facilities. These QF contracts are also intended to be sold or reassigned in
conjunction with the Company's proposed sale of electric generating
facilities. In accordance with the restructuring legislation, costs associated
with disposal and reassignment of these contracts are also expected to be
collected through the CTC.
The purchased gas contracts provide for take-or-pay payments. The
Nonutility oil and natural gas operations have various take-or-pay contracts
with terms that expire beginning in 1998 and natural gas transportation
contracts which begin expiring in 2000.
Total payments under all of these contracts for the prior three years
were as follows:
Thousands of Dollars
Utility Nonutility Total
Electric Natural Gas
1995 $ 21,830 $ 9,873 $ 2,980 $ 34,683
1996 30,751 8,100 3,283 42,134
1997 44,153 7,554 3,532 55,239
The present value of future minimum payments, at an assumed discount rate
of 8%, under the above agreements are estimated as follows:
Thousands of Dollars
Utility Nonutility Total
Electric Natural Gas
1998 $ 13,935 $ 2,590 $ 2,826 $ 19,351
1999 13,550 2,206 5,268 21,024
2000 13,207 1,879 4,845 19,931
2001 12,864 1,376 2,791 17,031
2002 12,593 1,172 1,899 15,664
Remainder 134,894 318 10,370 145,582
$ 201,043 $ 9,541 $ 27,999 $ 238,583
A Nonutility lignite lease purchase agreement requires minimum annual
payments, beginning in 1991 in the amount of $1,125,000 escalated quarterly by
the Gross National Product implicit price deflator. The payments will continue
until the equivalent of $18,750,000, in 1986 dollars, has been paid. At
December 31, 1997, the remaining payments under this agreement were $7,331,000.
Under current mine plans, these payments should be recovered through lignite
sales.
FTV Communications LLC, a limited liability company owned equally by
Touch America (a subsidiary of the Company), Williams Communications Group,
Inc. (a subsidiary of Williams Companies) and FirstPoint Communications, Inc.
(a subsidiary of Enron) will construct, operate and maintain a 1,620 mile
fiber-optic cable network linking Portland, Oregon and Los Angeles,
California. The project, which is scheduled to be completed in December 1998,
is expected to cost in excess of $100,000,000. The Company's investment in
the project is expected to be funded through existing credit facilities,
internally generated funds and the sale of fiber to other firms.
In January 1998, a Nonutility subsidiary of the Company entered into a
firm natural gas transportation agreement which begins March 1,1998 and expires
October 31, 2001. The agreement requires the Company to pay an annual fixed
charge of $982,000 for capacity, plus a commodity fee for transported volumes.
Sales commitments:
The Nonutility oil and natural gas operations have agreed to supply
approximately 107 Bcf of natural gas to four co-generation facilities. These
contracts begin expiring in 2005. Oil operations has sufficient proven,
developed and undeveloped reserves, and controls related sales of production
sufficient to supply all of the remaining natural gas required by these
contracts.
The Montana Power Group (MPG), an energy supply and management alliance,
was exclusively endorsed by the California Manufacturers Association (CMA) to
assist its members with their energy decisions. As a participant in the MPG,
MPT&MC a Nonutility subsidiary of the Company has agreed to offer energy
supply, discounted from the power exchange prices, and energy management
products and services to members of the CMA. The supply program is offered on
a limited basis and is capped at predetermined volumes. Once the caps are
fully subscribed, the Company will have, at its sole discretion, the option to
extend the offered supply and services to other CMA members. At December 31,
1997, one contract had been signed by the Company for electric supply for the
next two years. At this time, the Company cannot predict the impact of the CMA
agreement on future earnings, however, due to the limits provided in the
agreement, any potential negative impacts are not expected to have a material
impact on the Company's financial position or results of operations.
The Company is also participating in a pilot program which allows
participants to supply one-third of the particular customer's electric needs.
At December 31, 1997, one contract had been signed by the Company under this
program for electric supply for the next two years.
Lease commitments:
On December 30, 1985, the Company sold its 30% share of Colstrip Unit 4
and is leasing back this share under a net lease. The transaction has been
accounted for as an operating lease with annual lease payments of approximately
$32,000,000 over the remaining term of the 25-year lease. The unregulated
leasehold interest and its related assets and liabilities and contract
obligations are intended to be sold with the regulated electric generating
facilities and power purchase contracts. There are no other material minimum
operating lease payments. Capitalized leases are not material and are included
in other long-term debt.
Rental expense for the prior three years, including Colstrip Unit 4, was
$56,613,000, $55,500,000 and $55,958,000 for 1997, 1996 and 1995, respectively.
Note 4 - Deregulation and asset divestiture:
Natural Gas
The electric and natural gas utility businesses are in transition to
competition to provide energy commodity and related services to wholesale and
retail customers. In Montana, the "Natural Gas Restructuring and Customer
Choice Act" was passed by the Montana Legislature and signed into law in May
1997. This legislation allowed for natural gas utilities to open their systems
to full customer choice for gas supply and authorized the issuance of
transition bonds to lower transition costs. In response to the Company's July
1996 open-access and natural gas restructuring filing, in October 1997, the PSC
approved an order giving the Company's natural gas customers the right to
choose their own suppliers based upon stipulation agreements agreed-to by the
Company and many of the contesting parties to the filing. Natural gas
transmission, distribution and storage will remain regulated by the PSC. The
decision allows approximately 230 smaller industrial and larger commercial
customers using 5,000 dekatherms or more of natural gas annually, to have
choice beginning in November 1997. The 230 customers represent an additional 5%
of the Company's pre-transportation load that may choose their own supplier.
Natural gas customers who use 60,000 or more dekatherms of natural gas
annually, which included 23 industrial customers who represented 49% of the
Company's pre-transportation load, have had choice since 1991. The Company's
remaining 140,000 customers will have choice no later than July 1, 2002. A
pilot program allowing approximately 3,500 residential and small commercial
customers to choose their own supplier, beginning with the 1998-99 heating
season, will also be implemented.
Under the approved plan, almost all of the Utility natural gas
production assets were transferred to an unregulated affiliate at an amount
agreed-to in the natural gas order which was $33,600,000 below the existing
book value. This difference between transfer value and the book value and the
existing $25,400,000 of regulatory assets related to the natural gas
production assets were approved as a CTC and will be recovered from
transmission and distribution customers in rates over a 15-year period. The
transition plan also includes a supply contract between the unregulated gas
supply division and the regulated distribution division through 2002. This
contract includes fixed prices and declining volumes for expected reductions
in regulated loads that will occur as customers choose unregulated suppliers.
A filing requesting authorization to issue up to $65,000,000 in
transition bonds related to the natural gas transition costs and bond issuance
costs was made to the PSC in November 1997. The issuance of transition bonds,
often referred to as securitization, involves the issuance of a debt instrument
which is repaid through future revenues of the Utility. The legislation
authorizing the financing earmarks these future revenues to bond repayment,
thereby reducing the credit risk of the securities. As such, the bonds carry a
relatively low interest rate and allow the Company to carry higher debt levels
in relation to equity than would otherwise be desirable. This higher leverage
results in a lower cost of capital. The issuance of these bonds is expected to
result in annual savings of approximately $1,900,000.
On January 5, 1998, Enron requested court review of the PSC's decision
regarding the measure of stranded costs as well as the level of functional
separation of the various segments of the Company's natural gas business. This
appeal is pending before the First Judicial District Court, Lewis and Clark
County. Enron alleges the PSC erred when it concluded the assets subject to
the CTC are stranded and that their value is $60,000,000.
The Company requested, and expects the district court to provide,
expedited review and decision making regarding this matter. The Company does
not expect the PSC to act upon the Company's application for authority to
issue transition bonds while this appeal is pending at the district court. The
CTC rates assume the cost of capital associated with the transition bond
financing, therefore, the Company is currently not collecting from customers
its full cost of capital associated with these stranded costs.
Electric
Montana's "Electric Industry Restructuring and Customer Choice Act", was
also passed by the Montana Legislature and signed into law by the Governor in
May 1997.
This legislation provides for choice of electricity supplier for the
Company's large customers by July 1, 1998, for pilot programs for residential
and small commercial customers by July 1, 1998 and for all customers no later
than July 1, 2002. Transmission and distribution services will remain fully
regulated by FERC and the PSC. Generation assets will be removed from rate
base no later than July 1, 1998 and costs will be recoverable in utility
operations through a cost-based contract between the Company's regulated
operations and its unregulated Supply Division through July 1, 2002 for those
customers that do not have choice or have not selected a competitive based
supplier. The Company's Supply Division will compete for customers that have
choice during and after the transition period is complete. The legislation
established a rate moratorium on electric rates for all customers for two
years beginning July 1, 1998, and an electric-energy supply component rate
moratorium for an additional two years for smaller customers. The legislation
provides that rates cannot be increased under the rate moratorium except under
limited circumstances. As in the natural gas legislation, the issuance of
transition bonds was approved to lower transition costs. During the
transition period, savings related to these financings are available to the
Company to offset cost increases that would not be reflected in rates due to
the rate moratorium. In addition, under the legislation, if, during the
transition period, the earnings of the electric utility fall below a 9.5%
return on equity, the utility's obligation to flow investment tax credit
benefits to ratepayers in future years is reduced. Any such reduction in the
utility's regulatory obligation provides an economic benefit to the Company
and increases income in that year.
The legislation provides for the recovery of non-mitigatable transition
costs, specifically recovery of above-market qualifying facility power-
purchase contract costs and regulatory assets associated with the generation
business, and recovery for utility-owned above-market generation costs over
the transition period of up to four years. The legislation authorizes the use
of transition bonds, subject to the approval of a financing order by the PSC,
as a method of financing transition obligations at lower costs. The
legislation also defines the role the PSC will have in regulating distribution
services, licensing electricity suppliers in the state, and promulgating rules
regarding anti-competitive and abusive practices. Finally, the legislation
provides for reciprocity between utility companies.
As required by the legislation, the Company filed a comprehensive
transition plan with the PSC on July 1, 1997. The filing contains the
Company's transition plan, including the proposed handling and resolution of
transition costs, and addresses other issues required by the legislation. The
Company expects the PSC to render a decision before July 1998, subject to the
above-mentioned legislative guidelines, on the amount of transition costs that
will be recoverable. The PSC will consider the Company's efforts to mitigate
transition costs in making its determination.
In a related strategic decision, the Company announced, in December 1997,
that it will offer for sale all of its electric generating facilities in
Montana, consisting of 1,217 megawatts of capacity from 13 hydroelectric
projects and its interests in four coal-fired thermal generating units. In
addition, the Company will offer for sale its 222 megawatt leasehold interest
in Colstrip Unit 4, its power purchase contracts with qualifying facilities and
Basin Electric Power Cooperative (Basin), and two power exchange agreements.
The total book value of the electric generating facilities owned by the
Company to be offered is approximately $550,000,000 including approximately
$10,000,000 of fuel, materials and supplies. The leasehold interest is
accounted for as an operating lease with annual lease payments of approximately
$32,000,000 over the remaining term of the lease.
If the Company continued to own the generating facilities, the above-
market generation costs on these facilities for the four-year transition
period is estimated by the Company to be approximately $160,000,000. The
qualifying facility contracts, which the Company was required to enter by the
Public Utility Regulatory Policy Act of 1978, involve approximately 101
megawatts of purchased power extending through 2031 and could result in
$300,000,000 to $500,000,000 in out-of-market costs throughout their duration.
In testimony from intervenors in the electric restructuring case, the amount
of out-of-market costs on both the generating assets and the QF, Basin and
exchange contracts have been disputed. Disposal of the generation assets and
the contracts is expected to resolve the disputes. The total amount of
transition costs will not be determined until the sale process is complete,
which is expected to occur after the time of the PSC decision on the
restructuring filing.
Divestiture of these contracts could take the form of a buy-down, buy-
out or a restructuring of the contract. The lowest cost option with the most
favorable terms will be selected in this process. Owners of the QF contracts
must, by contract, approve any reassignment of the contract and FERC approval
may also be necessary.
In the process of selling these generating facilities and power purchase
contracts, any gains above the Company's book value will be utilized to reduce
the electric CTC amounts to be collected from ratepayers. Conversely, any
losses or additional costs to the Company would increase the CTC amounts to be
collected over the approved transition period. Although not specifically
named in the legislation, costs associated with disposal and reassignment of
the Basin contract are also expected to be collected through the CTC. Any gain
or loss realized from the disposition of the unregulated leasehold interest,
and its related assets and liabilities, will be reflected in the Consolidated
Statement of Income and will not be passed on to ratepayers.
The costs of completion of these potential transactions include legal,
accounting and consulting fees, employee related costs, asset relocation costs
and other expenses. Total transaction costs may exceed $50,000,000 and will
reduce the proceeds realized from the sale. There may also be income taxes
associated with the transactions.
Regardless of the timing of the sale of the generating assets and power
purchase contracts, the Company is obligated to continue to provide electric
power supply through the transition period to customers in its service
territory who have not had an opportunity to choose to purchase energy from
another power supplier. Such service will require the Company to have
available a power supply sufficient to meet those customers' electric loads.
The Company is evaluating options to meet these needs including market
purchases or a power supply contract with the purchasers of the generating
facilities.
The sale process is expected to begin in 1998 with offering memorandums
being sent to 30 to 50 expected potential buyers. In April, the Company
expects to receive non-binding preliminary bids from potential buyers. The
top bidders, expected to number less than ten, will be short-listed for
further negotiations and binding bids. The winning bidder is expected to be
selected in mid-summer and financial closing will occur as soon as all
required legal and regulatory approvals are complete, possibly three months to
two years after July 1998. It is the intention of the Company to proceed with
the sale process as tentatively scheduled, however, this divestiture is not a
requirement of the restructuring bill as is the case in other states with
deregulation legislation and the Company may at any time cease to continue
this option should it appear to not meet its expected benefits to ratepayers
and shareholders.
The Company is evaluating numerous possible uses for the proceeds
realized from the sale. Proceeds could be used to reduce outstanding debt,
buy back a number of the Company's outstanding common or preferred shares of
stock or proceeds up to the book value of the assets sold may be invested in
any of the Company's existing business segments or new ventures. The
Company's Mortgage and Deed of Trust imposes a lien on all physical properties
including the generation assets and pollution control equipment on some of the
thermal generating facilities, therefore, restrictions may exist on the use of
proceeds.
As discussed in Note 1 to the financial statements, the Colstrip
generating facilities are jointly owned by the Company and others. The sale
process of any of the particular plants may also be affected by rights of
first refusal of any of the partners. The Company, through one of its wholly
owned subsidiaries, supplies fuel to the Colstrip facilities. The sale of
these facilities is not expected to impact the fuel supply contracts. However,
the Company and the other owners are currently engaged in discussions intended
to result in a broad-based restructuring of the contractual arrangements
between the owners of all of the Colstrip plants and the Company's subsidiary
as fuel supplier. It is unknown at this time what impact the potential sale
may have on these discussions.
This divestiture is expected to be a complex process involving many
factors. The Company may have little or no direct control over some of these
factors, therefore, it can give no assurance as to the successful
implementation. If the Company is unsuccessful in implementing any elements of
the deregulation process, the potential exists for writeoff of regulatory
assets and the recording of effects of adverse purchase power contracts. The
restructuring legislation does, however, provide for, and management is
expecting, full recovery of all regulatory assets and other transition costs.
<TABLE>
<CAPTION>
NOTE 5 - Income tax expense:
Income before income taxes was as follows:
1997 1996 1995
Thousands of Dollars
<S> <C> <C> <C>
United States $ 177,114 $ 181,393 $ 75,458
Canada 12,780 7,706 111
Other countries 608 2,262 2,942
$ 190,502 $ 191,361 $ 78,511
The provision for income taxes differs from the amount of income tax that
would be expected by applying the applicable U.S. statutory federal income tax
rate to pretax income as a result of the following differences:
1997 1996 1995
Thousands of Dollars
Computed "expected" income tax expense $ 66,675 $ 66,976 $ 27,479
Adjustments for tax effects of:
Statutory depletion (2,891) (2,317) (6,508)
Tax credits (11,645) (5,286) (5,331)
State income tax, net 7,147 5,772 3,327
Reversal of utility book/tax
depreciation 5,636 4,054 2,552
Other (3,052) 2,776 55
Actual income tax expense $ 61,870 $ 71,975 $ 21,574
Income tax expense as shown in the Consolidated Statement of Income
consists of the following components:
1997 1996 1995
Thousands of Dollars
Current:
United States $ 36,680 $ 44,304 $ 25,119
Canada 994 3,309 1,510
Other countries 3,684 445 548
State 9,835 8,487 6,216
51,193 56,545 33,393
Deferred:
United States 6,491 15,590 (8,648)
Canada 2,802 135 (1,124)
State 1,384 (295) (2,047)
10,677 15,430 (11,819)
$ 61,870 $ 71,975 $ 21,574
</TABLE>
<TABLE>
<CAPTION>
Deferred tax liabilities (assets) are comprised of the following:
December 31
1997 1996
Thousands of Dollars
<S> <C> <C>
Plant related $ 390,776 $ 388,973
Investment in Nonutility generation projects 25,530 26,785
Other 41,499 33,508
Gross deferred tax liabilities 457,805 449,266
Coal reclamation (46,820) (45,252)
Amortization of gain on sale/leaseback (13,860) (14,898)
Investment tax credit amortization (22,862) (28,895)
Other (44,551) (38,455)
Gross deferred tax assets (128,093) (127,500)
Net deferred tax liabilities 329,712 321,766
Less current deferred tax assets-net (10,539) (11,095)
Total noncurrent deferred tax liabilities $ 340,251 $ 332,861
The change in net deferred tax liabilities differs from current year
deferred tax expense as a result of the following:
Thousands of
Dollars
Change in noncurrent deferred tax $ 7,390
Regulatory assets related to income taxes 26,247
Current deferred tax assets-net 556
Amortization of investment tax credits (7,817)
Transfer of natural gas production balances (16,677)
Other 978
Deferred tax expense $ 10,677
</TABLE>
NOTE 6 - Common stock:
The Company has a Shareholder Protection Rights Plan that provides one
preferred share purchase right (Right) on each outstanding common share of the
Company. Each Right entitles the registered holder, upon the occurrence of
certain events, to purchase from the Company one one-hundredth of a share of
Participating Preferred Shares, A Series, without par value. If it should
become exercisable, each Right would have economic terms similar to one share
of common stock of the Company. The Rights trade with the underlying shares
and will, except under certain circumstances described in the Plan, expire on
June 6, 1999, unless redeemed earlier or exchanged by the Company.
The Company's Dividend Reinvestment and Stock Purchase Plan permits
participants to: (a) acquire additional shares of common stock through the
reinvestment of dividends on all or any specified number of common and/or
preferred shares registered in their own names, or through optional cash
payments of up to $60,000 per year, (b) deposit common and preferred stock
certificates into their Plan accounts for safekeeping; and allows for other
interested investors (residents of certain states) to make initial purchases
of common shares with a minimum of $100 and a maximum of $60,000 per year.
The Company has a Retirement Savings Plan (Plan) that covers all regular
eligible employees. The Company, on behalf of the employee, contributes a
matching percentage of the amount contributed to the Plan by the employee. In
1990, the Company borrowed $40,000,000 at an interest rate of 9.2% to be repaid
in equal annual installments over 15 years. The proceeds of the loan were lent
on similar terms to the Plan Trustee, which purchased 1,922,297 shares of
Company common stock. The loan, which is reflected as long-term debt, is
offset by a similar amount in common shareholders' equity as unallocated stock.
Company contributions plus the dividends on the shares held under the Plan are
used to meet principal and interest payments on the loan. Shares acquired with
loan proceeds are allocated to Plan participants. As principal payments on the
loan are made, long-term debt and the offset in common shareholders' equity are
both reduced. At December 31, 1997, 994,355 shares had been allocated to the
participants' accounts. Expense for the Plan is recognized using the Shares
Allocated Method, and the pre-tax expense was $5,194,000, $6,046,000 and
$5,610,000 for 1997, 1996 and 1995, respectively.
Under the Long-Term Incentive Plan, options have been issued to Company
employees. Options issued to employees are not reflected in balance sheet
accounts until exercised, at which time (i) authorized, but unissued shares are
issued to the employee, (ii) the capital stock account is credited with the
proceeds and (iii) no charges or credits to income are made. Options issued to
Nonutility employees under the Key Employee Incentive Stock Option Plan are not
reflected in balance sheet accounts. Options were granted at the average of the
high and low prices as reported on the New York Stock Exchange composite tape
on the date granted, and expire ten years from that date. Options granted
prior to January 1, 1987 must be exercised in the order granted.
In 1995 and 1994, restricted stock awards of 2,100 and 64,235,
respectively, were issued to certain Nonutility employees under the Long-Term
Incentive Plan. Upon the achievement of performance and passage of time
constraints, restrictions will be lifted and participants will retain, at no
cost, the unrestricted shares. As they are earned, the awards are reflected as
common stock and compensation expense on the Consolidated Balance Sheet and
Consolidated Statement of Income, respectively. At December 31, 1997 there
were 9,643 shares of restricted stock remaining.
<TABLE>
<CAPTION>
Option activity is summarized below:
1997 1996 1995
<S> <C> <C> <C>
Options outstanding
@ 1/1 694,804 569,982 480,986
(Price range) ($17.25 - $26.50) ($17.25 - $26.50) ($17.25 - $26.50)
Options granted 164,400 116,730
(Price range) ($21.625) ($21.125 - $22.50)
Options exercised 125,753 11,578 19,034
(Price range) ($17.25 - $22.625) ($17.25 - $22.125) ($17.25 - $26.50)
Options canceled 27,886 28,000 8,700
(Price range) ($17.6875 - $22.50) ($22.125 - $22.625) ($22.125 - $22.625)
Options outstanding
@ 12/31 541,165 694,804 569,982
</TABLE>
There were 436,560 options exercisable at December 31, 1997.
As permitted by SFAS No. 123, "Accounting for Stock-Based Compensation,"
the Company has elected to follow Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees" (APB 25) and related
interpretations in accounting for its employee stock options. Under APB 25,
because the exercise price of the Company's employee stock options equals the
market price of the underlying stock on the date of grant, no compensation
expense is recognized. Disclosure of pro-forma information regarding net
income and earnings per share is required by SFAS No. 123. This information
has been determined as if the Company had accounted for its employee stock
options under the fair value method of that statement. The fair value of
options granted in 1996 and 1995 was $1.93 and $1.60 per share, respectively.
The fair value of each option grant was estimated on the date of grant using
the binomial option-pricing model with the following assumptions used for
grants in 1996 and 1995, respectively: risk-free interest rate of 7.05% and
5.67%; expected life of ten years for both years; expected volatility of
10.46% and 10.05% and a dividend yield of 6.83% and 6.33%. Had the Company
used SFAS No. 123, earnings per share would be unaffected as compensation
expense would have increased only $195,000, $108,000 and $37,000 for 1997,
1996 and 1995, respectively.
NOTE 7 - Preferred stock:
The number of authorized shares of preferred stock is 5,000,000. No
dividends may be declared or paid on common stock while cumulative dividends
have not either been declared and set apart or paid on any of the preferred
stock.
Preferred stock is in four series as detailed in the following table:
<TABLE>
<CAPTION>
Stated and
Liquidation Shares Issued and Outstanding Thousands of Dollars
Series Price* 1997 1996 1995 1997 1996 1995
<S> <C> <C> <C> <C> <C> <C>
$6.875 $100 360,800 360,800 500,000 $ 36,080 $ 36,080 $ 50,000
6.00 100 159,589 159,589 159,589 15,959 15,959 15,959
4.20 100 60,000 60,000 60,000 6,025 6,025 6,025
2.15 25 1,200,000 30,000
Discount (410) (410) (568)
580,389 580,389 1,919,589 $ 57,654 $ 57,654 $101,416
<FN>
* Plus accumulated dividends.
</FN>
</TABLE>
The preferred stock is redeemable at the option of the Company upon the
written consent or affirmative vote of the holders of a majority of the common
shares on thirty days notice at $110 per share for the $6.00 series and
$103 per share for the $4.20 series, plus accumulated dividends. The $6.875
series is redeemable in whole or in part, at anytime on or after November 1,
2003 for a price beginning at $103.438 per share with annual decrements through
October 2013, after which the redemption price is $100 per share.
In October 1996, the Company repurchased and retired 139,200 shares of
the $6.875 series at prices ranging from $101.50 to $103.00. In December 1996,
the Company redeemed all outstanding shares of the $2.15 series at the
redemption price of $25.25. The total premium of approximately $650,000
resulting from these transactions was included in preferred dividends in the
Consolidated Statement of Income.
NOTE 8 - Company obligated mandatorily redeemable preferred securities of
subsidiary trust:
Montana Power Capital I (Trust) was established as a wholly owned
business trust of the Company for the purpose of issuing common and preferred
securities (Trust Securities) and holding Junior Subordinated Deferrable
Interest Debentures (Subordinated Debentures) issued by the Company. At
December 31, 1997 and 1996 the Trust held 2,600,000 units of 8.45% 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% of
the liquidation preference value of $25 per security. The sole asset of the
Trust is $67,000,000 of Subordinated Debentures, 8.45% Series due 2036, issued
by the Company. The Trust will use interest payments received on the
Subordinated Debentures it holds to make the quarterly cash distributions on
the QUIPS.
The Trust Securities are subject to mandatory redemption upon repayment
of the Subordinated Debentures at maturity or redemption. The Company has the
option at any time on or after November 6, 2001, to redeem the Subordinated
Debentures, in whole or in part. The Company also has the option, upon the
occurrence of certain events, to redeem the Subordinated Debentures, in whole
but not in part, which would result in the redemption of all the Trust
Securities. The Company has the right to terminate the Trust at any time and
cause the pro rata distribution of the Subordinated Debentures to the holders
of the Trust Securities.
In addition to the Company's obligations under the Subordinated
Debentures, the Company has guaranteed, on a subordinated basis, payment of
distributions on the Trust Securities, to the extent the Trust has funds
available to pay such distributions and has agreed to pay all of the expenses
of the Trust (such additional obligations collectively, the Back-up
Undertakings). Considered together with the Subordinated Debentures, the Back-
up Undertakings constitute a full and unconditional guarantee by the Company
of the Trust's obligations under the QUIPS. The Company is the owner of all
the common securities of the Trust, which constitute 3% of the aggregate
liquidation amount of all the Trust Securities.
NOTE 9 - Long-term debt:
The Company's Mortgage and Deed of Trust (the Mortgage) imposes a first
mortgage lien on all physical properties owned, exclusive of subsidiary company
assets, and certain property and assets specifically excepted. The obligations
collateralized are First Mortgage Bonds, including those First Mortgage Bonds
designated as Secured Medium-Term Notes and those securing Pollution Control
Revenue Bonds. The Mortgage may impose some restrictions on the use of
proceeds realized from the sale of the electric generating assets and power
purchase contracts.
Long-term debt consists of the following:
December 31
1997 1996
Thousands of Dollars
First Mortgage Bonds:
7.7% series, due 1999 $ 55,000 $ 55,000
7 1/2% series, due 2001 25,000 25,000
7% series, due 2005 50,000 50,000
8 1/4% series, due 2007 55,000 55,000
8.95% series, due 2022 50,000 50,000
Secured Medium-Term Notes -
maturing 1998-2025 5.90%-8.11% 108,000 128,000
Pollution Control Revenue Bonds:
City of Forsyth, Montana
6 1/8% series, due 2023 90,205 90,205
5.9% series, due 2023 80,000 80,000
Sinking Fund Debentures -7 1/2%, due 1998 15,500 16,000
ESOP Notes Payable - 9.2%, due 2004 25,104 27,587
Unsecured Medium-Term Notes:
Series A - maturing 1998-2022 8.68%-8.9% 22,000 29,500
Series B - maturing 2006-2026 7.07%-7.96% 55,000 55,000
Revolving Credit Agreements 45,715 35,000
Other 62,269 10,536
Unamortized Discount and Premium (3,966) (4,221)
734,827 702,607
Less: Portion due within one year 81,659 69,268
$ 653,168 $ 633,339
In June 1997, in response to FERC's decision regarding the Kerr
mitigation plan discussed in Item 8, "Financial Statements and Supplementary
Data - Note 2 to the Consolidated Financial Statements", the Company
recognized long-term debt of approximately $57,000,000 which is included in
"Other" in the table above. In August 1997, the Company paid approximately
$4,200,000 into a fish and wildlife fund reducing the amount owed.
Approximately, $36,000,000 is classified as due within one year in the
Consolidated Balance Sheet at December 31, 1997.
In December 1997, Roan Resources Ltd., a wholly owned Canadian subsidiary
purchased the stock of a small Canadian company, for approximately $26,500,000
in U.S. dollars. Financing for the purchase was provided through an Extendible
Revolving Term Credit Agreement between Roan Resources and the Royal Bank of
Canada. The maximum amount of credit available under this Agreement is
$37,800,000 in Canadian dollars which was reduced to $28,000,000 in Canadian
dollars, or $19,627,000 in U.S. dollars, on January 8, 1998. At December 31,
1997, the amount outstanding under the agreement was $15,715,000 in U.S.
dollars, which is included in "Revolving Credit Agreements" in the table above.
In April 1997, the Company entered into a Revolving Credit Agreement for
certain of its Nonutility operations. Including this facility, the Company's
consolidated borrowing ability under its Revolving Credit and Term Loan
Agreements (Agreements) is $220,000,000, of which $190,000,000 was unused at
December 31, 1997. Under terms of the new agreement, the amount of the
facility decreases on March 31, 1998, reducing the consolidated borrowing
ability under the Agreements to $160,000,000. These agreements term on
October 27, 1998 and April 4, 2000, and all outstanding borrowings must be
repaid on those dates. Fixed or variable interest rate options are available
under the facilities with facility fees or commitment fees on the unused
portions.
The sinking fund requirements and maturities for the five years ending
December 31, 2002, on the long-term debt outstanding at December 31, 1997,
amount to: $82,000,000 in 1998; $63,000,000 in 1999; $65,000,000 in 2000;
$30,000,000 in 2001 and $6,000,000 in 2002.
NOTE 10 - Short-term borrowing:
The Company has short-term borrowing facilities with commercial banks
that provide both committed, as well as uncommitted lines of credit, and the
ability to sell commercial paper. Bank borrowings either bear interest at the
lender's floating base rate and may be repaid at any time, or have fixed rates
of interest and maturities. Commercial paper has fixed rates of interest and
maturities.
At December 31, 1997, the Company had lines of credit consisting of
$70,000,000 committed and $85,000,000 uncommitted. There are facility fees or
commitment fees on the committed lines of credit which are not significant. The
Company has the ability to issue up to $165,000,000 of commercial paper based
on the total of unused committed lines of credit and revolving credit
agreements.
Short-term borrowings and average interest rates were as follows:
December 31
1997 1996
Amount Rate Amount Rate
Thousands of Dollars
Notes payable to banks $ 89,100 6.82% $ 70,500 7.17%
Commercial paper 44,858 6.46% 34,202 5.79%
$133,958 $104,702
NOTE 11 - Retirement plans:
The Company maintains trusteed, noncontributory retirement plans covering
substantially all employees. Retirement benefits are based on salary, years of
service and social security integration levels.
In 1997, funding for pension costs exceeded SFAS No. 87 pension expense
by $5,441,000. In 1996 and 1995, pension costs funded were less than SFAS
No. 87 pension expense by $188,000, and $1,501,000, respectively. The
differences were deferred for recognition in future periods as funding is
reflected in rates. At December 31, 1997, the regulatory liability was
$2,344,000.
The assets of the plans consist primarily of domestic and foreign
corporate stocks, domestic corporate bonds and U.S. Government securities.
The Company also has an unfunded, nonqualified benefit plan for senior
management executives and directors. Life insurance payable to the Company is
carried on plan participants as an investment. The plan costs are not included
in rates.
Net pension and benefit expense includes the following components:
December 31
1997 1996 1995
Thousands of Dollars
Service cost on benefits earned $ 7,585 $ 7,991 $ 6,165
Interest cost on projected benefit
obligation 16,370 15,861 14,524
Actual return on plan assets (38,280) (30,331) (13,009)
Net amortization and deferral 18,185 15,270 1,719
Net pension and benefit expense $ 3,860 $ 8,791 $ 9,399
The funded status of the pension and benefit plans is as follows:
December 31
1997 1996
Thousands of Dollars
Actuarial present value of benefit obligation:
Vested $ 180,662 $ 152,115
Nonvested 21,177 19,029
Accumulated benefit obligation 201,839 171,144
Effect of projected future compensation levels 46,902 51,125
Projected benefit obligation 248,741 222,269
Plan assets at fair value 259,837 223,686
Plan assets greater than projected
benefit obligation 11,096 1,417
Unrecognized net gain (40,704) (34,793)
Unrecognized prior service cost 8,691 10,088
Unrecognized initial obligation 1,905 2,491
Accrued benefits expense $ (19,012) $ (20,797)
The following assumptions were used in the determination of actuarial
present values of the projected benefit obligations:
December 31
1997 1996
Assumed discount rates 7.00% 7.50%
Long-term rate of average compensation
increase 4.50%-7.50% 4.50%-5.00%
Long-term rate on plan assets 9.00% 8.50%
In addition to providing pension benefits, the Company and its
subsidiaries provide certain health care and life insurance benefits for
eligible retired employees. In 1994, the Company established a pre-funding plan
for postretirement benefits for Utility employees retiring after January 1,
1993. The assets of the plan consist primarily of domestic and foreign
corporate stocks, domestic corporate bonds and U.S. Government securities. The
PSC allows the Company to include in rates all Utility OPEB cost on the accrual
basis provided by SFAS No. 106.
Postretirement benefit costs for the years ended December 31, 1997, 1996
and 1995, portions of which have been deferred or capitalized, include the
following components:
December 31
1997 1996 1995
Thousands of Dollars
Service cost on benefits earned $ 803 $ 1,074 $ 1,221
Interest cost on projected benefit 2,020 2,092 2,482
Actual return on plan assets (993) (876) (219)
Net amortizations 1,266 1,577 1,299
Total postretirement benefit cost $ 3,096 $ 3,867 $ 4,783
The funded status of the postretirement benefit plans other than pensions
is as follows:
December 31
1997 1996
Thousands of Dollars
Accumulated benefit obligation:
Fully eligible active employees $ 1,599 $ 3,267
Other active employees 14,796 16,267
Retirees 13,859 10,330
Accumulated benefit obligation 30,254 29,864
Plan assets at fair value 8,168 5,740
Plan assets less than projected
benefit obligation (22,086) (24,124)
Unrecognized net transition obligation 18,194 20,012
Unrecognized net gain (8,930) (8,064)
Accrued benefits expense $(12,822) $(12,176)
The assumed 1997 health care cost trend rates used to measure the
expected cost of benefits covered by the plans is 8.50%. The trend rate
decreases through 2004 to 5%. The effect of a 1% increase in each future
year's assumed health care cost trend rates increases the service and interest
cost from $2,823,000 to $3,032,000 and the accumulated postretirement benefit
obligation from $30,000,000 to $32,000,000.
NOTE 12 - Information on industry segments:
The Montana Power Company (the Company) and its subsidiaries engage in a
number of diversified energy and communication related businesses. The
Company's principal business is the regulated Utility operations involving the
generation, purchase, transmission and distribution of electricity and the
purchase, transportation and distribution of natural gas. The Company's
Nonutility operations principally involve the mining and sale of coal and
lignite, exploration for, and the development, production, processing and sale,
of oil and natural gas, and the sale of telecommunication equipment and
services. It also conducts trading and marketing of electricity and natural
gas. In addition, the Company manages long-term power sales, and develops and
invests in Nonutility power projects and other energy-related businesses.
The Company's open-access and reorganization plan for its regulated
Natural Gas Utility was approved for implementation by the PSC, effective
November 1, 1997. Under the approved plan, almost all of the regulated
Utility's natural gas production assets, including those of its Canadian
subsidiary, were transferred to its unregulated oil and natural gas operations
as of that date.
<TABLE>
<CAPTION>
Operations Information:
Year Ended
December 31, 1997
Thousands of Dollars
UTILITY Electric Natural Gas
<S> <C> <C>
Sales to unaffiliated customers $ 435,986 $ 122,355
Intersegment sales 4,685 588
Pre-tax operating income 111,002 37,994
Depreciation, depletion and amortization 51,674 11,939
Capital expenditures 122,639 15,679
Identifiable assets 1,560,055 390,463
<CAPTION>
NONUTILITY
Oil and Independent
Coal* Natural Gas Power**
<S> <C> <C> <C>
Sales to unaffiliated customers $ 169,825 $ 163,656 $ 70,932
Intersegment sales 34,164 3,120 1,820
Pre-tax operating income 31,050 16,310 (17)
Earnings (loss) from unconsolidated
investments (2,202) 14,980
Depreciation, depletion and amortization 8,368 16,922 2,774
Capital expenditures 4,588 140,437 (15,140)
Identifiable assets 247,981 290,110 156,282
<CAPTION>
NONUTILITY (continued)
Tele-
Communications** Other
<S> <C> <C>
Sales to unaffiliated customers $ 44,464 $ 2,104
Intersegment sales 797 3,924
Pre-tax operating income (loss) 11,759 (4,809)
Earnings from unconsolidated
investments 435
Depreciation, depletion and amortization 2,455 532
Capital expenditures 25,422 53
Identifiable assets 101,581 7,987
<CAPTION>
CORPORATE
<S> <C>
Capital expenditures $ 94
Identifiable assets 47,237
<FN>
* Sales under one coal contract with Houston Light and Power Company amounted to
$104,668,000.
** The Telecommunications and Independent Power segments are dependent on a single
customer and two customers, respectively, the losses of which would have a
material adverse effect on the segments.
</FN>
</TABLE>
<TABLE>
<CAPTION>
Operations Information:
Year Ended
December 31, 1996
Thousands of Dollars
UTILITY Electric Natural Gas
<S> <C> <C>
Sales to unaffiliated customers $ 430,171 $ 128,528
Intersegment sales 5,793 649
Pre-tax operating income 122,123 40,830
Depreciation, depletion and amortization 46,648 11,638
Capital expenditures 74,930 31,060
Identifiable assets 1,526,197 421,955
<CAPTION>
NONUTILITY
Oil and Independent
Coal* Natural Gas Power**
<S> <C> <C> <C>
Sales to unaffiliated customers $ 166,678 $ 124,532 $ 75,322
Intersegment sales 31,448 293 1,426
Pre-tax operating income 34,358 17,687 1,675
Earnings (loss) from unconsolidated
investments (2,777) 21,174
Depreciation, depletion and amortization 5,653 17,080 3,793
Capital expenditures 8,386 25,021 (9,406)
Identifiable assets 268,297 184,512 156,044
<CAPTION>
NONUTILITY (continued)
Tele-
communications Other
<S> <C> <C>
Sales to unaffiliated customers $ 27,575 $ 1,201
Intersegment sales 133 782
Pre-tax operating income (loss) 2,591 (2,040)
Earnings from unconsolidated
investments 66
Depreciation, depletion and amortization 911 679
Capital expenditures 27,902 6
Identifiable assets 52,139 17,954
<CAPTION>
CORPORATE
<S> <C>
Capital expenditures $ 1,178
Identifiable assets 71,117
<FN>
* Sales under one coal contract with Houston Light and Power Company amounted to
$102,181,000.
** The Independent Power segment is dependent on two customers, the losses of which
would have a material adverse effect on the segment.
</FN>
</TABLE>
<TABLE>
<CAPTION>
Operations Information:
Year Ended
December 31, 1995
Thousands of Dollars
UTILITY Electric Natural Gas
<S> <C> <C>
Sales to unaffiliated customers $ 421,999 $ 115,113
Intersegment sales 5,813 852
Pre-tax operating income 124,916 30,933
Depreciation, depletion and amortization 40,675 10,283
Capital expenditures 127,917 35,091
Identifiable assets 1,503,619 410,267
<CAPTION>
NONUTILITY
Oil and Independent
Coal* Natural Gas Power**
<S> <C> <C> <C>
Sales to unaffiliated customers $ 210,200 $ 100,030 $ 79,095
Intersegment sales 25,659 409 796
Writedown of long-lived assets 55,103 19,194
Pre-tax operating income (loss) (41,001) (8,504) 3,027
Earnings (loss) from unconsolidated
investments (2,749) 2,622
Depreciation, depletion and amortization 11,187 17,569 3,176
Capital expenditures 19,230 34,780 4,168
Identifiable assets 250,132 177,744 161,602
<CAPTION>
NONUTILITY (continued)
Tele-
communications Other
<S> <C> <C>
Sales to unaffiliated customers $ 23,177 $ 2,647
Intersegment sales 377 699
Pre-tax operating income (loss) 2,200 (52)
Earnings from unconsolidated
investments 70
Depreciation, depletion and amortization 803 942
Capital expenditures 8,633 48
Identifiable assets 22,592 17,032
<CAPTION>
CORPORATE
<S> <C>
Capital expenditures $ 1,220
Identifiable assets 43,103
<FN>
* Sales under one coal contract with Houston Light and Power Company amounted to
$102,844,000.
** The Independent Power segment is dependent on two customers, the losses of which
would have a material adverse effect on the segment.
</FN>
</TABLE>
SUPPLEMENTARY DATA
OIL AND NATURAL GAS PRODUCING ACTIVITIES
For the years ended December 31, 1997, 1996 and 1995 net recoverable oil
and natural gas reserves, excluding royalty volumes and volumes controlled
under purchase contract, of the Utility and Nonutility operations were
estimated as follows:
<TABLE>
<CAPTION>
1997
U.S. CANADA STORAGE
PROVED DEVELOPED AND UNDEVELOPED RESERVES:
<S> <C> <C> <C>
UTILITY OPERATIONS:
Natural Gas (Mmcf):
Beginning Balance 71,952 94,445 55,624
Production (3,764) (3,401)
Additions 1,216
(Sales) and Purchases of Reserves in Place (13,082)
Transfers Out (53,711) (91,044)
Revisions - Other 702
Revisions - Price
Ending Balance 2,097 0 56,840
NONUTILITY OPERATIONS:
Natural Gas (Mmcf):
Beginning Balance 160,174 53,011
Production (11,427) (6,529)
Additions 14,920 8,569
(Sales) and Purchases of Reserves in Place 6,039 5,914
Transfers In 53,711 91,044
Revisions - Other (31,918) (26,501)
Revisions - Price (249) (373)
Ending Balance 191,250 125,135
Natural Gas
Liquids (Bbls):
Beginning Balance 3,491,100 3,089,300
Production (473,139) (225,715)
Additions 118,500 184,000
(Sales) and Purchases of Reserves in Place 2,717,377 582,000
Revisions - Other 2,392,716 (1,082,000)
Revisions - Price (5,000)
Ending Balance 8,246,554 2,542,585
Oil (Bbls):
Beginning Balance 6,458,000 3,204,235
Production (746,380) (322,164)
Additions 339,110 2,445,000
(Sales) and Purchases of Reserves in Place (1,145,648) (2,851,000)
Revisions - Other (28,792) 228,000
Revisions - Price 149,100 (4,000)
Ending Balance 5,025,390 2,700,071
1997
U.S. CANADA
PROVED DEVELOPED RESERVES:
UTILITY OPERATIONS:
Natural Gas (Mmcf):
Ending Balance 2,097 0
NONUTILITY OPERATIONS:
Natural Gas (Mmcf):
Ending Balance 139,802 104,799
Natural Gas Liquids (Bbls):
Ending Balance 8,246,554 2,298,585
Oil (Bbls):
Ending Balance 3,474,602 2,079,071
</TABLE>
<TABLE>
<CAPTION>
1996
U.S. CANADA STORAGE
PROVED DEVELOPED AND UNDEVELOPED RESERVES:
<S> <C> <C> <C>
UTILITY OPERATIONS:
Natural Gas (Mmcf):
Beginning Balance 75,461 103,475 56,745
Production (5,055) (4,694)
Additions (1,121)
(Sales) and Purchases of Reserves in Place
Revisions - Other 1,546 (4,336)
Revisions - Price
Ending Balance 71,952 94,445 55,624
NONUTILITY OPERATIONS:
Natural Gas (Mmcf):
Beginning Balance 136,660 62,474
Production (8,915) (6,924)
Additions 813 1,702
(Sales) and Purchases of Reserves in Place 19,240 12
Revisions - Other (1,098) (14,847)
Revisions - Price 13,474 10,594
Ending Balance 160,174 53,011
Natural Gas
Liquids (Bbls):
Beginning Balance 3,615,400 3,680,132
Production (232,600) (271,241)
Additions 17,700
(Sales) and Purchases of Reserves in Place (200)
Revisions - Other (43,414) (440,607)
Revisions - Price 151,914 103,316
Ending Balance 3,491,100 3,089,300
Oil (Bbls):
Beginning Balance 5,999,400 4,429,496
Production (539,288) (676,640)
Additions 19,600 118,814
(Sales) and Purchases of Reserves in Place 702,347 58,800
Revisions - Other (130,360) (1,027,636)
Revisions - Price 406,301 301,401
Ending Balance 6,458,000 3,204,235
<CAPTION>
1996
U.S. CANADA
PROVED DEVELOPED RESERVES:
<S> <C> <C>
UTILITY OPERATIONS:
Natural Gas (Mmcf):
Ending Balance 71,121 94,445
NONUTILITY OPERATIONS:
Natural Gas (Mmcf):
Ending Balance 100,067 53,011
Natural Gas Liquids (Bbls):
Ending Balance 3,486,700 3,089,300
Oil (Bbls):
Ending Balance 6,369,000 3,204,235
</TABLE>
<TABLE>
<CAPTION>
1995
U.S. CANADA STORAGE
PROVED DEVELOPED AND UNDEVELOPED RESERVES:
<S> <C> <C> <C>
UTILITY OPERATIONS:
Natural Gas (Mmcf):
Beginning Balance 80,562 96,571 56,548
Production (5,176) (4,651)
Additions 2,840 197
(Sales) and Purchases of Reserves in Place
Revisions - Other 75 8,715
Revisions - Price
Ending Balance 75,461 103,475 56,745
NONUTILITY OPERATIONS:
Natural Gas (Mmcf):
Beginning Balance 153,162 79,283
Production (8,605) (6,703)
Additions 5,035 6,528
(Sales) and Purchases of Reserves in Place 47 (8,053)
Revisions - Other (7,426) (3,594)
Revisions - Price (5,553) (4,987)
Ending Balance 136,660 62,474
Natural Gas
Liquids (Bbls):
Beginning Balance 3,110,300 1,999,500
Production (258,112) (183,856)
Additions 12,200 299,300
(Sales) and Purchases of Reserves in Place (141,400)
Revisions - Other 929,732 1,714,808
Revisions - Price (178,720) (8,220)
Ending Balance 3,615,400 3,680,132
Oil (Bbls):
Beginning Balance 6,079,700 4,935,000
Production (479,952) (601,051)
Additions 117,392 66,400
(Sales) and Purchases of Reserves in Place 392,436 173,392
Revisions - Other (38,862) 152,418
Revisions - Price (71,314) (296,663)
Ending Balance 5,999,400 4,429,496
<CAPTION>
1995
U.S. CANADA
PROVED DEVELOPED RESERVES:
<S> <C> <C>
UTILITY OPERATIONS:
Natural Gas (Mmcf):
Ending Balance 74,630 103,475
NONUTILITY OPERATIONS:
Natural Gas (Mmcf):
Ending Balance 78,637 55,947
Natural Gas Liquids (Bbls):
Ending Balance 2,943,900 3,380,832
Oil (Bbls):
Ending Balance 4,488,900 3,421,596
</TABLE>
SUPPLEMENTARY DATA
Oil and Natural Gas Producing Activities (Cont.)
As determined by engineers, Utility natural gas reserves were revised
during 1997, 1996 and 1995 due to changes in projected performance or changes
in the Company's ownership interest in specific fields.
In 1997, the PSC approved the deregulation of the Utility's natural gas
production properties. As a result, all of the Canadian and almost all of the
U.S. natural gas reserves were transferred to the Nonutility effective November
1, 1997.
Nonutility U.S. natural gas and natural gas liquid reserves increased in
1997 because of the acquisition of reserves in place (Vessels), 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 (Questar), 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.
The Utility reserves that were transferred to the Nonutility in 1997
were determined by petroleum engineers following Utility business guidelines
to be those reserves that are mechanically recoverable using reasonable
production methods. After deregulation and transfer, the same natural gas
reserve volumes are estimated to be those which are mechanically recoverable
under market price conditions. The inclusion of economic limits into the
estimates has resulted in downward revisions of U.S. and Canadian natural gas
reserves.
In 1996, the Nonutility U.S. natural gas and oil reserves increased as a
result of higher market prices and the acquisition of reserves in place.
Natural gas reserves were added through the purchase of interests in 250 wells
in northeastern Montana (Bowdoin Field). Oil reserves were added with the
purchase of additional interest in an existing Montana field (Reagan). The
Canadian natural gas and oil reserves decreased primarily as a result of
downward revisions of engineering estimates for undeveloped reserves.
In 1995, the Nonutility U.S. natural gas reserves decreased as a result
of lower gas market prices and higher liquid recoveries at the Fort Lupton,
Colorado gas processing plant. The higher liquid recoveries resulted in an
increase in natural gas liquid reserves. Reserve additions through
participation in the drilling of 29 development wells and five exploratory
wells in Oklahoma, Colorado and Montana offset Nonutility production. The
Canadian companies participated in 18 development wells and 12 exploratory
wells. Of these, 17 were oil wells in the Sounding Lake and Manyberries areas
of Alberta.
The following table presents information for 1997, 1996 and 1995 on the
capitalized costs relating to Utility natural gas producing activities, costs
incurred in Utility natural gas property acquisition, exploration and
development activities and certain Utility natural gas production costs
reflected in results of operations. As a regulated public utility, the Company
is authorized to earn a rate of return on its Utility natural gas plant rate
base. The Company's cost of acquiring Utility natural gas reserves and the net
cost of natural gas in underground storage are included in the natural gas
plant which is a part of the Utility rate base. Due to the commingling of
produced natural gas with purchased and royalty natural gas for sale to Utility
customers and application of the ratemaking process to the Utility natural gas
producing activities, the Company is unable to identify revenues resulting
solely from Utility natural gas producing activities. Accordingly, the
information on revenues, income taxes, results of operations and estimated
future net cash flows and changes therein relating to proved Utility natural
gas reserves are not presented for the Company's Utility natural gas producing
activities.
<TABLE>
<CAPTION>
1997 1996 1995
U.S. Canada U.S. Canada U.S. Canada
UTILITY OPERATIONS Thousands of Dollars
At December 31:
<S> <C> <C> <C> <C> <C> <C>
Capitalized costs relating
to natural gas producing
activities $ 2,023 $ 0 $ 87,363 $ 38,551 $ 89,520 $ 37,683
Accumulated depreciation,
depletion and valuation
allowances 1,833 0 46,881 20,102 50,377 19,812
Net capitalized costs $ 190 $ 0 $ 40,482 $ 18,449 $ 39,143 $ 17,871
For the year ended
December 31:
Costs incurred in natural
gas property acquisition,
exploration and
development activities:
Acquisition of
properties $ 474 $ 49 $ 48 $ 170
Exploration $ 35 $ 168 54 191 70 198
Development 1 66 501 1,230 1,753 1,240
Costs reflected in results
of operations:
Production costs $ 3,361 $ 1,359 $ 4,773 $ 1,510 $ 5,710 $ 1,592
Exploration expenses 35 168 54 191 70 198
Development expenses 0 66 22 113 165 416
Depreciation, depletion
and valuation
provisions 2,072 686 2,667 711 2,716 586
</TABLE>
The following table presents information for 1997, 1996 and 1995 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>
1997 1996 1995
U.S. Canada U.S. Canada U.S. Canada
NONUTILITY OPERATIONS Thousands of Dollars
At December 31:
<S> <C> <C> <C> <C> <C> <C>
Capitalized costs relating
to oil and natural gas
producing activities $240,436 $113,165 $182,339 $ 87,529 $171,795 $ 83,457
Accumulated depreciation,
depletion and valuation
allowances 49,167 46,131 65,401 44,770 60,329 39,834
Net capitalized costs $191,269 $67,034 $116,938 $ 42,759 $111,466 $ 43,623
For the year ended
December 31:
Costs incurred in oil and
natural gas property
acquisition, exploration
and development
activities:
Acquisition of
properties $85,606 $22,762 $ 4,667 $ 3,722 $ 13,024 $ 4,407
Exploration 4,589 6,036 1,780 2,157 4,592 1,642
Development 21,050 8,535 10,651 3,345 11,244 4,298
Results of operations for
oil and natural gas
producing activities:
Revenues $ 34,182 $ 14,821 $ 26,872 $ 19,789 $ 20,461 $ 19,022
Production costs 10,232 5,041 8,901 6,547 7,298 6,812
Exploration expenses 3,233 2,905 1,670 1,747 2,460 1,517
Depreciation, depletion
and valuation
provisions 12,037 3,781 10,019 6,133 21,079 15,371
8,680 3,094 6,282 5,362 (10,376) (4,678)
Income tax expenses 416 1,380 946 2,393 (5,708) (2,087)
Results of operations from
producing activities
(excluding corporate
overhead and interest
cost) $ 8,264 $ 1,714 $ 5,336 $ 2,969 $ (4,668) $ (2,591)
</TABLE>
SUPPLEMENTARY DATA
Oil and Natural Gas Producing Activities (Cont.)
Estimated future cash flows are computed by applying year-end prices and
contract prices, when appropriate, of oil and natural gas to year-end
quantities of proved reserves. Estimated future development and production
costs are determined by estimating the expenditures to be incurred in
developing and producing the proved oil and natural gas reserves at the end of
the year, based on year-end costs. Estimated future income tax expenses are
calculated by applying year-end statutory tax rates to estimated future pre-tax
net cash flows related to proved oil and natural gas reserves, less the tax
basis of the properties involved. The future income tax expenses give effect
to permanent differences, tax credits and deferred taxes relating to proved oil
and natural gas reserves.
These estimates are furnished and calculated in accordance with
requirements of the Financial Accounting Standards Board and the Securities and
Exchange Commission (SEC). Management believes the usefulness of these
projections is limited because of the unpredictable variances in expenses,
capital forecasts and crude oil and natural gas prices. Estimates of future
net cash flows presented do not represent management's assessment of future
profitability or future cash flow to the Company. Management's investment and
operating decisions are based upon reserve estimates that include proved
reserves prescribed by the SEC as well as probable reserves, and upon different
price and cost assumptions from those used here.
<TABLE>
<CAPTION>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS AND CHANGES THEREIN RELATING TO
PROVED OIL AND NATURAL GAS RESERVES
December 31
1997 1996
U.S. Canada U.S. Canada
Thousands of Dollars
<S> <C> <C> <C> <C>
Future cash inflows $ 876,733 $ 303,780 $ 684,709 $ 185,988
Future production and
development costs 467,270 151,201 261,432 68,921
Future income tax expenses 94,162 36,253 129,091 27,876
Future net cash flows 315,301 116,326 294,186 89,191
10% annual discount for
estimated timing
of cash flows 122,469 35,008 135,285 23,407
Standardized measure of
discounted future net
cash flows $ 192,832 $ 81,318 $ 158,901 $ 65,784
The following are the principal sources of change in the standardized measure of
discounted future net cash flows:
Sales and transfers of oil and
gas produced, net of
production costs $ (23,620) $ (9,780) $ (22,466) $ (13,242)
Net changes in prices,
development and production
costs (30,047) (12,687) 16,095 30,948
Extensions, discoveries, and
improved recovery, less
related costs 60,863 42,699 19,823 2,597
Revisions of previous quantity
estimates (20,953) (11,929) 14,012 (11,395)
Accretion of discount 20,503 7,480 16,939 6,150
Net change in income taxes 25,584 968 (14,670) (4,005)
Other 1,601 (1,217) (8,765) (1,758)
</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 1997 and 1996, the amount described as other is primarily the result
of changes in the timing of production.
QUARTERLY FINANCIAL DATA
Operating revenues, operating income and net income in thousands of
dollars and net income per common share for the four quarters of 1997 and 1996
are shown in the tables below. Operating revenues and income include
intersegment sales and expenses. Due to the seasonal nature of the utility
business, the annual amounts are not generated evenly by quarter during the
year.
<TABLE>
<CAPTION>
Quarter Ended
Dec. 31, Sept. 30, June 30, Mar. 31,
1997 1997 1997 1997
<S> <C> <C> <C> <C>
Utility Operating Revenues $152,498 $120,914 $119,862 $170,340
Utility Operating Income 44,140 22,047 20,925 61,884
Utility Net Income 25,557 3,012 2,543 27,996
Nonutility Operating Revenues 155,610 125,253 105,567 121,589
Nonutility Operating Income 21,095 14,744 10,183 21,484
Nonutility Net Income 24,955 12,306 11,287 17,286
Consolidated Net Income 50,512 15,318 13,830 45,282
Basic Earnings Per Share of
Common Stock $ 0.93 $ 0.28 $ 0.25 $ 0.83
Diluted Earnings Per Share of
Common Stock $ 0.92 $ 0.28 $ 0.25 $ 0.83
<CAPTION>
Quarter Ended
Dec. 31, Sept. 30, June 30, Mar. 31,
1996 1996 1996 1996
<S> <C> <C> <C> <C>
Utility Operating Revenues $169,257 $115,533 $110,265 $170,086
Utility Operating Income 57,036 22,738 23,899 59,280
Utility Net Income 24,593 3,837 6,016 27,201
Nonutility Operating Revenues 137,437 110,926 94,560 104,930
Nonutility Operating Income 31,719 16,547 8,385 16,083
Nonutility Net Income 19,026 12,585 6,463 11,307
Consolidated Net Income 43,619 16,422 12,479 38,508
Basic Earnings Per Share of
Common Stock $ 0.80 $ 0.30 $ 0.23 $ 0.70
Diluted Earnings Per Share of
Common Stock $ 0.80 $ 0.30 $ 0.23 $ 0.70
</TABLE>
ITEM 9. DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
See Part 1, "Executive Officers of the Registrant."
Information on The Montana Power Company Directors is incorporated by
reference from the Company's Notice of 1998 Annual Meeting of Shareholders and
Proxy Statement, pages 1-3.
ITEM 11. EXECUTIVE COMPENSATION
Incorporated by reference from Notice of 1998 Annual Meeting of
Shareholders and Proxy Statement, pages 6-12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Incorporated by reference from Notice of 1998 Annual Meeting of
Shareholders and Proxy Statement, pages 4-5.
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) The Company filed the following reports on Form 8-K:
Date Subject
October 23, 1997 Item 5. Other Events. Discussion of Third
Quarter Net Income.
Item 7 Exhibits. Consolidated Statements of
Income for the Quarters Ended September 30,
1997 and 1996, Nine Months Ended September 30,
1997 and 1996, and for the Twelve Months Ended
September 30, 1997 and 1996. Utility
Operations Schedule of Revenues and Expenses
for the Quarters Ended September 30, 1997 and
1996, Nine Months Ended September 30, 1997 and
1996 and for the Twelve Months Ended
September 30, 1997 and 1996. Nonutility
Operations Schedule of Revenues and Expenses
for the Quarters Ended September 30, 1997 and
1996, Nine Months Ended September 30, 1997 and
1996 and for the Twelve Months Ended
September 30, 1997 and 1996.
December 9, 1997 Item 5. Other Events. Montana Power Company
Offers to Sell its Montana Generation.
December 12, 1997 Item 5. Other Events. Texas Jury Finds for
Northwestern Resources in Coal Dispute.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
3. Exhibits Incorporation by Reference
Previous
Previous Exhibit
Filing Designation
3(a) Restated Articles of Incorporation,
as amended 33-56739 3(a)
3(a)(1) Articles of Amendment to the Restated
Articles of Incorporation 1-4566 3(a)(1)
3(a)(2) Articles of Amendment to the Restated
Articles of Incorporation
3(b) By-laws, as adopted dated August 22,
1996 1-4566 3(b)
3(b)(1) Amendment to By-laws dated August 27,
1996 1-4566 3(b)
3(b)(2) Amendment to By-laws dated May 12,
1997 1-4566 3(b)
3(b)(3) Amendment to By-laws dated December 9,
1997
4(a) Mortgage and Deed Trust 2-5927 7(e)
4(b) First Supplemental Indenture 2-10834 4(e)
4(c) Second Supplemental Indenture 2-14237 4(d)
4(d) Third Supplemental Indenture 2-27121 2(a)-5
4(e) Fourth Supplemental Indenture 2-36246 2(a)-6
4(f) Fifth Supplemental Indenture 2-39536 2(a)-7
4(g) Sixth Supplemental Indenture 2-49884 2(a)-8(a)
4(h) Seventh Supplemental Indenture 2-52268 2(a)-9
4(i) Eighth Supplemental Indenture 2-53940 2(a)-10
4(j) Ninth Supplemental Indenture 2-55036 2(a)-11
4(k) Tenth Supplemental Indenture 2-63264 2(a)-12
4(l) Eleventh Supplemental Indenture 2-86500 2(a)-13
4(m) Twelfth Supplemental Indenture 33-42882 4(c)
4(n) Thirteenth Supplemental Indenture 33-55816 4(a)-14
4(o) Fourteenth Supplemental Indenture 33-64576 4(c)
4(p) Fifteenth Supplemental Indenture 33-64576 4(d)
4(q) Sixteenth Supplemental Indenture 33-50235 99(a)
4(r) Seventeenth Supplemental Indenture 33-56739 99(a)
4(s) Eighteenth Supplemental Indenture 33-56739 99(b)
Instruments defining the rights of holders of long-term debt
which are not required to be filed with the Commission will be
furnished to the Commission upon request.
Incorporation by Reference
Previous
Previous Exhibit
Filing Designation
4(t) Rights Agreement dated as of 33-42882 4(d)
June 6, 1989, between The
Montana Power Company and First
Chicago Trust Company of New
York, as Rights Agent
10(a)(i) Benefit Restoration Plan for 33-42882 10(a)(i)
Senior Management Executives
and Board of Directors
10(a)(ii) Deferred Compensation Plan for 33-42882 10(a)(ii)
Non-Employee Directors
10(a)(iii) Long-Term Incentive Stock 1-4566 10(a)(iii)
Ownership Plan 1992
Form 10-K
10(a)(iv) The Montana Power Company 33-28096 4(c)
Employee Stock Ownership Plan
(Revised)
10(a)(v) Termination Compensation
Agreements with Senior
Management Executives
10(c) Participation Agreements among 33-42882 10(c)
United States Trust Company
of New York, Burnham Leasing
Corporation, and SGE (New York)
Associates, Certain Institutions,
The Montana Power Company and
Bankers Trust Company
12 Statement Re Computation of Ratio
of Earnings to Fixed Charges
21 Subsidiaries of the Registrant
23 Consent of Independent Accountants
27 Financial Data Schedule
<TABLE>
<CAPTION>
THE MONTANA POWER COMPANY AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Thousands of Dollars
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
Balance Additions
at Charged to Charged to Balance
beginning costs and other at close
Description of period expenses accounts Deductions of period
<S> <C> <C> <C> <C> <C>
(Note a)
Year Ended:
December 31, 1997
Reserves deducted
in balance sheet
from assets to
which they apply:
Doubtful accounts
Utility $ 924 $ 2,349 $ 2,289 $ 984
Nonutility 636 229 $ 6 44 827
Total $ 1,560 $ 2,578 $ 6 $ 2,333 $ 1,811
December 31, 1996
Reserves deducted
in balance sheet
from assets to
which they apply:
Doubtful accounts
Utility $ 868 $ 1,767 $ 1,711 $ 924
Nonutility 601 236 $ (37) 164 636
Total $ 1,469 $ 2,003 $ (37) $ 1,875 $ 1,560
December 31, 1995
Reserves deducted
in balance sheet
from assets to
which they apply:
Doubtful accounts
Utility $ 808 $ 1,065 $ 1,005 $ 868
Nonutility 616 206 $ 62 283 601
Total $ 1,424 $ 1,271 $ 62 $ 1,288 $ 1,469
<FN>
NOTES:
(a) Deductions are of the nature for which the reserves were created. In the
case of the reserve for doubtful accounts, deductions from this reserve are
reduced by recoveries of amounts previously written off.
<FN>
</TABLE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
THE MONTANA POWER COMPANY
By/s/ Robert P. Gannon
Robert P. Gannon
(Chairman of the Board)
Date: March 25, 1998
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title Date
/s/ Robert P. Gannon Principal Executive
Robert P. Gannon Officer and Director March 25, 1998
(Chief Executive Officer)
/s/ J. P. Pederson Principal Financial
J. P. Pederson and Accounting Officer
(Vice President and Chief and Director March 25, 1998
Financial and Information
Officer)
/s/ Tucker Hart Adams Director March 25, 1998
Tucker Hart Adams
/s/ Alan F. Cain Director March 25, 1998
Alan F. Cain
/s/ John G. Connors Director March 25, 1998
John G. Connors
/s/ R. D. Corette Director March 25, 1998
R. D. Corette
/s/ Kay Foster Director March 25, 1998
Kay Foster
/s/ Beverly D. Harris Director March 25, 1998
Beverly D. Harris
/s/ Chase T. Hibbard Director March 25, 1998
Chase T. Hibbard
/s/ John R. Jester Director March 25, 1998
John R. Jester
/s/ Carl Lehrkind, III Director March 25, 1998
Carl Lehrkind, III
/s/ Arthur K. Neill Director March 25, 1998
Arthur K. Neill
/s/ N. E. Vosburg Director March 25, 1998
N. E. Vosburg
EXHIBIT INDEX
Exhibit 3(b)(3)
Amendment to By-laws dated December 9, 1997
Exhibit 12
Statement Re Computation of Ratio Earnings to Fixed Charges
Exhibit 21
Subsidiaries of the Registrant
Exhibit 23
Consent of Independent Accountants
Exhibit 27
Financial Data Schedule
SIGNATURES (Continued)
3(b)(3)
BYLAWS
OF
THE MONTANA POWER COMPANY
Adopted on : August 22, 1995
As Amended on : December 9, 1997, August 27, 1996 & May 12, 1997
THE MONTANA POWER COMPANY
AMENDED BYLAWS
Article Amendment Date of Amendment
11 The affairs of the Corporation shall be managed by December 9, 1997
a Board of thirteen (13) Directors.
THE MONTANA POWER COMPANY
CERTIFICATION OF RESOLUTION
I, R. M. Ralph, Assistant Secretary of The Montana Power Company, a
corporation, hereby certify that the following is a full, true and correct
copy of Resolution duly adopted by the Board of Directors of The Montana
Power Company at a meeting duly called and held December 9, 1997 and that
said Resolution is in full force and effect as of the date of this
certificate.
RESOLVED, that the first sentence of Section 11 of The Montana
Power Company Bylaws is hereby amended to reduce the number of Directors
from fourteen (14) to thirteen (13) as follows:
SECTION 11. The affairs of the Corporation shall be managed
by a Board of thirteen (13) Directors.
IN WITNESS WHEREOF, I have hereunto set my hand and the Seal of said
Corporation this 10th day of December 1997.
/s/R. M. Ralph
R. M. Ralph, Assistant Secretary
(SEAL)
Exhibit 12
THE MONTANA POWER COMPANY
Computation of Ratio of Earnings to Fixed Charges
(Dollars in Thousands)
Twelve Months Ended
December 31,
1997 1996 1995
Net Income $ 127,985 $ 119,147 $ 59,053
Income Taxes 61,870 72,813 21,573
$ 189,855 $ 191,960 $ 80,626
Fixed Charges:
Interest $ 61,720 50,937 47,330
Amortization of Debt Discount,
Expense and Premium 1,538 1,610 1,567
Rentals 34,671 34,470 35,300
$ 97,929 $ 87,017 $ 84,197
Earnings Before Income Taxes
and Fixed Charges $ 287,784 $ 278,977 $ 164,823
Ratio of Earning to Fixed Charges 2.94 x 3.21 x 1.96 x
Exhibit 12
THE MONTANA POWER COMPANY
Computation of Ratio of Earnings to Fixed Charges
(Dollars in Thousands)
Twelve Months Ended
December 31,
1994 1993 1992
Net Income $ 115,963 $ 107,196 $ 107,065
Income Taxes 53,152 54,120 45,639
$ 169,115 $ 161,316 $ 152,704
Fixed Charges:
Interest $ 44,096 $ 48,142 $ 48,810
Amortization of Debt Discount,
Expense and Premium 1,666 1,768 1,878
Rentals 36,586 36,631 36,905
$ 82,348 $ 86,541 $ 87,593
Earnings Before Income Taxes
and Fixed Charges $ 251,463 $ 247,857 $ 240,297
Ratio of Earning to Fixed Charges 3.05 x 2.86 x 2.74 x
Canadian-Montana Gas Company Limited
An Alberta Corporation 100
Canadian-Montana Pipe Line Company
An Alberta Corporation 100
Glacier Gas Company
A Montana Corporation 100
Colstrip Community Services Company
A Montana Corporation 100
Montana Power Services Company
A Montana Corporation 100
Continental Energy Services, Inc.
A Montana Corporation 100
EMPECO, Inc.
A Montana Corporation
(A wholly-owned subsidiary of Continental
Energy Services, Inc.) 100
EMPECO II, Inc.
A Montana Corporation
(A wholly-owned subsidiary of Continental
Energy Services, Inc.) 100
EMPECO III, Inc.
A Montana Corporation
(A wholly-owned subsidiary of Continental
Energy Services, Inc.) 100
EMPECO IV, Inc.
A Montana Corporation
(A wholly-owned subsidiary of Continental
Energy Services, Inc.) 100
EMPECO V, Inc.
A Montana Corporation
(A wholly-owned subsidiary of Continental
Energy Services, Inc.) 100
EMPECO VI - TE, Inc.
A Montana Corporation
(A wholly-owned subsidiary of Continental
Energy Services, Inc.) 100
EMPECO VII - TX3, Inc.
A Montana Corporation
(A wholly-owned subsidiary of Continental
Energy Services, Inc.) 100
Montana Energy Inc.
A Montana Corporation
(A wholly-owned subsidiary of Continental
Energy Services, Inc.) 100
CES International, Inc.
A Cayman Islands Corporation
(A wholly-owned subsidiary of Continental
Energy Services, Inc.) 100
Barge Energy, LLC
A Cayman Islands Limited Life Corporation
(A wholly-owned subsidiary of CES International,
Inc., except 1% held by EMPECO VI - TE, Inc.) 100
PAK Energy, LLC
A Cayman Islands Limited Life Corporation
(A wholly-owned subsidiary of CES International,
Inc., except 1% held by Montana Energy, Inc.) 100
North American Energy Services Company
A Washington Corporation
(A 50%-owned subsidiary of Continental
Energy Services, Inc.) 50
North American Contract Employee Services
A Washington Corporation
(A wholly-owned subsidiary of North
American Energy Services Company) 50
ECI Energy, Ltd.
A Delaware Corporation
Investment in English Partnership in a
Gas-fired Cogeneration Project
(A 47.5% owned subsidiary of Continental
Energy Services, Inc.) 50
Enserch Development Corporation One, Inc.
A Delaware Corporation
(A wholly owned subsidiary of Continental
Energy Services, Inc.) 100
Montana Grimes County, Inc.
A Montana Corporation
(A wholly owned subsidiary of Continental
Energy Services, Inc.) 100
Montana Grimes Frontier, Inc.
A Montana Corporation
(A wholly owned subsidiary of Continental
Energy Services, Inc.) 100
Entech, Inc.
A Montana Corporation 100
Western Energy Company
A Montana Corporation 100
Western Syncoal Company
A Montana Corporation
(A wholly-owned subsidiary of Western
Energy Company) 100
Montana Energy Development Participacoes, Ltd.
A Brazilian Corporation
(99.99% owned by Entech, Inc., .01% owned by Western
Energy Company) 100
Financiera Ulken Sociedad Anonima (SA)
A Uruguayan Corporation
(A wholly-owned subsidiary of Montana
Energy Development Participacoes, Ltd.) 100
Northwestern Resources Co.
A Montana Corporation 100
Altana Exploration Company
A Montana Corporation 100
Entech Altamont, Inc.
A Montana Corporation 100
Roan Resources, Ltd.
An Alberta Corporation 100
North American Resources Company
A Montana Corporation 100
Tetragenics Company
A Montana Corporation 100
Touch America, Inc.
A Montana Corporation 100
The Montana Power Trading & Marketing Company
A Montana Corporation 100
Basin Resources, Inc.
A Colorado Corporation 100
Horizon Coal Services, Inc.
A Montana Corporation 100
North Central Energy Company
A Colorado Corporation 100
Entech Gas Ventures, Inc.
A Montana Corporation 100
The Montana Power Gas Company
A Montana Corporation 100
Syncoal, Inc.
A Montana Corporation 100
Note: The above listed companies are included in the Consolidated Financial
Statements of the registrant.
SUBSIDIARIES OF REGISTRANT Exhibit 21
Percentage of Voting
Securities Owned
by Registrant
- -116-
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. 333-58403, to the incorporation by
reference in the Prospectus constituting part of the Registration Statement on
Form S-3 No. 33-64576, to the incorporation by reference in the Registration
Statement on Form S-8 No. 33-24952, to the incorporation by reference in the
Registration Statement on Form S-8 No. 33-28096, to the incorporation by
reference in the Prospectus constituting part of the Registration Statement on
Form S-3 No. 33-32275, to the incorporation by reference in the Prospectus
constituting part of the Registration Statement on Form S-3 No. 33-55816, to
the incorporation by reference in the Prospectus constituting part of the
Registration Statement on Form S-3 No. 33-56739, to the incorporation by
reference in the Prospectus constituting part of the Registration Statement on
Form S-3 No. 333-14369, to the incorporation by reference in the Prospectus
constituting part of the Registration Statement on Form S-3 No. 333-14369-01,
to the incorporation by reference in the Prospectus constituting part of the
Registration Statement on Form S-3 No. 333-17181, of our report dated
February 5, 1998, appearing on page 57 of The Montana Power Company's Annual
Report on Form 10-K for the year ended December 31, 1997.
/s/ Price Waterhouse LLP
PRICE WATERHOUSE LLP
Portland, Oregon
March 25, 1998
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS STATEMENT CONTAINS SUMMARY INFORMATION EXTRACTED FROM THE CONSOLIDATED
BALANCE SHEET AT 12/31/97, THE CONSOLIDATED INCOME STATEMENT AND CONSOLIDATED
STATEMENT OF CASH FLOWS FOR THE TWELVE MONTHS ENDED 12/31/97 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-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> DEC-31-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,531,238
<OTHER-PROPERTY-AND-INVEST> 655,304
<TOTAL-CURRENT-ASSETS> 243,176
<TOTAL-DEFERRED-CHARGES> 371,978
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,801,696
<COMMON> 694,561
<CAPITAL-SURPLUS-PAID-IN> 2,106
<RETAINED-EARNINGS> 314,922
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,011,589
65,000
57,654
<LONG-TERM-DEBT-NET> 652,256
<SHORT-TERM-NOTES> 133,958
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 80,869
0
<CAPITAL-LEASE-OBLIGATIONS> 912
<LEASES-CURRENT> 790
<OTHER-ITEMS-CAPITAL-AND-LIAB> 798,668
<TOT-CAPITALIZATION-AND-LIAB> 2,801,696
<GROSS-OPERATING-REVENUE> 1,023,597
<INCOME-TAX-EXPENSE> 61,870
<OTHER-OPERATING-EXPENSES> 807,095
<TOTAL-OPERATING-EXPENSES> 868,965
<OPERATING-INCOME-LOSS> 154,632
<OTHER-INCOME-NET> 34,159
<INCOME-BEFORE-INTEREST-EXPEN> 188,791
<TOTAL-INTEREST-EXPENSE> 60,159
<NET-INCOME> 128,632
3,690
<EARNINGS-AVAILABLE-FOR-COMM> 124,942
<COMMON-STOCK-DIVIDENDS> 87,494
<TOTAL-INTEREST-ON-BONDS> 45,332
<CASH-FLOW-OPERATIONS> 201,091
<EPS-PRIMARY> 2.29
<EPS-DILUTED> 2.28
</TABLE>
