March 26, 1997
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 Gentlemen:
The accounting principles and practices and the method of applying such
principles and practices relflected in the financial statements included in the
1996 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, 1996
-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 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 $1,236,916,381 at March 13, 1997.
On March 13, 1997, the Company had 54,634,994 shares of common stock
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
(1) Notice of 1997 Annual Meeting of Shareholders and Proxy Statement, pages 1-
15, 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 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", 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 production, purchase, transportation and distribution of
natural gas. The Company's nonutility operations engage in a number of
diversified operations principally involving the mining and sale of coal and
exploration for, and the development, production, processing and sale, of oil
and natural gas and the sale of telecommunication equipment and services. In
addition, the Company manages long-term power sales, and develops and invests
in nonutility power projects and other energy-related businesses. See Item 8,
"Financial Statements and Supplementary Data - Note 11 to the Consolidated
Financial Statements" for further information. A group of officers and
employees of the Company constitute the Office of the Corporation, which
provides strategic direction and policy, approves the allocation of capital and
provides financial, legal and other services to all of the operating units. The
Company was incorporated in 1961 under the laws of the State of Montana, where
its principal business is conducted, as the successor to a New Jersey
corporation incorporated in 1912.
In May 1996, the Company began managing itself as a restructured company
with 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 wholesale business
development. The Energy and Communications Services Division is responsible for
the transmission and distribution of electricity and natural gas as well as
telecommunications, energy management services and retail business development.
Pending regulatory decisions and legislation 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
596,000 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 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 three
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 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 Montana Public Service Commission (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 filed a motion requesting a waiver of the
filing requirements for a 1997 Plan and proposing 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 Company is expecting
approval of the waiver.
Also refer to Item 7, "Management's Discussion and Analysis of Financial
Conditions and Results of Operations - Summary of Significant Regulatory
Matters."
ELECTRIC UTILITY: The maximum demand on the resources in 1996 was
1,415,000 kW on February 2, 1996. Total firm capability of the Utility's
electric system at December 31, 1996 was 1,606,000 kW. Of this capability,
1,197,000 kW was provided by the Utility's generating facilities, and
409,000 kW was provided by firm Electric Utility power purchase and exchange
arrangements. The Electric Utility's reserve margin on February 2, 1996, as a
percentage of maximum demand, was 14%. Also refer to Item 8, "Financial
Statements and Supplementary Data - Note 3 to the Consolidated Financial
Statements" for further discussion of power purchases.
The Company's future need for electric resources will be to meet winter
peak requirements. Future power needs could change depending on wholesale
wheeling, changes in the number of customers, and changes that retail wheeling
would cause, if it occurs. In 1996, two purchase power contracts totaling
approximately 150,000 kW expired and will not be renewed. Deliveries under a
long-term contract with a 450 kW qualifying facility began in October 1996.
Local-area integrated resource planning (LIRP) uses integrated resource
planning principles to solve reliability and/or load growth problems for a
specific area through a balance of resources and/or transmission and
distribution facilities additions. As a part of the Company's planning process,
LIRP is being used in the Helena area to determine the least cost solution to a
transmission reliability problem under certain line outage conditions.
Included in this process is an RFP to discover possible solutions that may
replace or augment known transmission facility alternatives. The need for
additional winter peak resource will be addressed annually and any need will be
met through market purchases.
During the year ended December 31, 1996, the sources of the Utility
Operations electric supply were: hydro, 38%; coal, 40%; and purchased power,
22%. The cost of coal burned has been as follows:
Year Ended December 31
1996 1995 1994
Average cost per million Btu's $ 0.59 $ 0.56 $ 0.66
Average cost per ton (delivered) 10.06 9.67 11.24
Reduced coal volumes burned due to thermal displacement with low-cost
hydroelectric power and the switching of fuel suppliers by the Corette Plant
caused the average cost of coal to increase in 1996 as fixed costs were spread
over fewer tons. The decline in the 1995 average cost per ton is primarily due
to the Colstrip Units 1 and 2 Coal Supply Agreement arbitration decision.
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 also is a party to the Pacific Northwest Coordination Agreement which
integrates electric and hydroelectric operations of the 18 parties associated
with generating facilities in the Columbia River Basin; is a member of the
Western Systems Coordinating Council, organized by 77 member systems and
20 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 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 1996 totaled
22,642 Mmcf, of which 12,269 Mmcf were from Montana and 10,373 Mmcf from
Canada. The Gas Utility produced 45% of the Montana natural gas and its
Canadian subsidiaries produced 53% of the Canadian natural gas.
The Natural Gas Utility transports gas supplies for all customers meeting
a 60,000 Mmcf annual transportation threshold. However, substantially all of
these customers obtain their supplies directly from other sources. Total
volumes of natural gas transported were 27,200 Mmcf, 26,700 Mmcf and
23,700 Mmcf for 1996, 1995 and 1994, respectively.
Total 1997 natural gas requirements, estimated to be 23,123 Mmcf, are
anticipated to be supplied from existing reserves and purchase contracts.
Approximately 11,650 Mmcf of these requirements are expected to be obtained in
the United States and 11,473 Mmcf from Canada. The Natural Gas Utility expects
to produce 47% of the Montana natural gas and 48% of the Canadian natural gas.
The 1997 transportation volumes are anticipated to be 27,889 Mmcf. The 1997
estimates do not reflect changes which may occur as a result of the Company's
natural gas restructuring filing with the PSC.
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 subsidiary, Western SynCoal Company (SynCoal), owns 75% of a
patented coal enhancement process, a subsidiary of Northern States Power owns
the rest, and each owns 50% of the Rosebud SynCoal Partnership, which owns and
operates a coal enhancement process demonstration plant at the Rosebud Mine.
Northwestern Resources Company (Northwestern) holds leases on lignite
properties in Texas and operates the Jewett Mine. Horizon Coal Services, Inc.
(Horizon) holds leases and rights on coal properties in Wyoming. Basin
Resources, Inc. (Basin) operated the Golden Eagle Mine in Colorado. In
December 1995, Basin terminated all coal sales agreements and ceased
production. In 1996, the mine was sealed and most of the salvageable plant and
equipment was sold or is under agreement to be sold. See Item 7, "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Nonutility Operations - Coal Operations - 1996 Compared to 1995 - Expenses" and
Item 8, "Financial Statements and Supplementary Data - Note 12 to the
Consolidated Financial Statements."
The oil and natural gas business is conducted in the United States
through North American Resources Company (NARCO) and in Canada through both
Altana Exploration Company (Altana) and Roan Resources, Ltd. (Roan).
The telecommunication business is conducted through Touch America, Inc.
Touch America offers three primary services to customers: equipment, private
lines and long distance services.
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.
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 and the Jewett Mine sells its entire
production to the two 800 MW Limestone Units. All of the contracts provide for
periodic price reopeners. The Company expects to be able 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. The Company holds significant reserves in
the Gillette area of Wyoming that are under development. A decision to commit
to mine construction will be based on the demand and price outlook for
production from the area. The Company is also investigating joint development
and sales alternatives for the property.
The Nonutility oil and natural gas business competes in the areas of
property acquisitions and the development, production and marketing of oil and
natural gas, as well as contracting for equipment, services, and securing
personnel, with major oil and natural gas companies, other independent and
individual producers and operators. The Company has production, development
and long-term marketing abilities, experience in acquiring properties, and the
financial resources to enable it to compete effectively.
The telecommunications business competes in the areas of long distance
and private line services, and telecommunication equipment sales, with major
and regional companies where price competition is intense. Telecommunication
services are provided in the regional marketplace and it competes effectively
due to a low cost structure.
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 97% of 1996 coal sales. The remainder of Rosebud
coal was sold under spot-market sale agreements and contracts in Michigan,
Minnesota, North Dakota, Wisconsin and Montana.
During 1996, Western mined and sold 7,828,347 tons, of which
2,804,034 tons were sold to the Company. Western's Rosebud Mine production is
estimated to be 9,250,000 tons in 1997, as a result of expected Colstrip Units
3 & 4 increased coal purchases, and 9,250,000 tons in 1998. However,
preliminary estimates of hydroelectric generating conditions in the Northwest
indicate higher than normal stream flows which may impact 1997 coal sales
volumes.
Northwestern's Jewett Mine, located in central Texas, supplies lignite
under a long-term contract to the two electric generating units, located
adjacent to the mine, that are owned by Houston Lighting and Power Company.
Total deliveries in 1996, were 8,508,212 tons. The estimated production for
1997 and 1998 are 8,700,000 and 8,600,000 tons, respectively. After 1998,
production is estimated to be approximately 8,500,000 tons annually.
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. NARCO's producing oil and natural gas properties are
principally located in the states of Wyoming, Colorado, Kansas, Oklahoma and
Montana. Altana's and Roan's properties are principally located in the
Province of Alberta, Canada. NARCO has entered into agreements to supply
109,800 Mmcf of natural gas to three co-generation facilities over a period of
8 to 14 years with performance guaranteed by Entech, Inc., a wholly owned
subsidiary of the Company. NARCO has 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
14,819 Mmcf, or 28% of Altana's and Roan's natural gas reserves, are dedicated
to long-term contracts expiring at various times through 2005. In addition to
serving these contracts, oil and natural gas operations intends to concentrate
its efforts on natural gas production in support of the expanding market
development objectives including adding production in target basins.
In February 1997, NARCO entered into an agreement to purchase Vessels
Energy's oil and gas assets in Colorado's Denver-Julesburg (D-J) Basin. With
this acquisition, NARCO's annual hydrocarbon production in the D-J Basin will
increase from 3,805 Mmcf of natural gas to 7,275 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. NARCO will own more than 565 wells, operating some 470 of
them, and also will own and operate an 800-mile gas-gathering system.
INDEPENDENT POWER OPERATIONS: Independent power operations develops,
acquires, operates, and manages facilities and resources to provide
electricity and other energy-related services.
Colstrip 4 Lease Management Division sells the Company's 210 megawatt
share of Colstrip Unit 4 generation to the Los Angeles Department of Water and
Power and to Puget Sound Power & Light Company (Puget) under contracts which
are coextensive with the term of the Company's leasehold interest in the Unit.
CES develops and invests in power projects, and currently holds
ownership interest 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 independent power project under
construction in Pakistan. In addition, CES is participating with others in
the development of a coal-fired project in India and is actively pursuing
development and investment opportunities in Brazil.
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 for private power generating companies and
provides maintenance services for power plants owned and operated by electric
utilities.
See Item 8, "Financial Statements and Supplementary Data - Note 2 to the
Consolidated Financial Statements" for additional information pertaining to
litigation involving the Puget contract.
TELECOMMUNICATIONS OPERATIONS: Touch America provides long distance,
private line, and telecommunications equipment sales and services to customers
in Montana, Idaho, Washington, Oregon and Wyoming. Touch America also markets
and maintains PBX and key systems, call accounting systems and voice mail
systems.
The telecommunications system includes private, dedicated communication
lines throughout Montana on a digital microwave and fiber network. Touch
America is currently expanding 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 network is expected to provide
full service by mid-1997, offering increased private line service and sales
options as well as increased long distance service efficiencies.
EMPLOYEES:
At December 31, 1996, the Company and its subsidiaries employed
2,949 persons of which 1,925 were utility employees (including 391 employees at
the jointly owned Colstrip Units 1-4), and 1,024 Nonutility employees.
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 imposes a first mortgage lien on
all physical properties owned, exclusive of subsidiary company assets, and
certain property and assets specifically excepted.
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 689,000 kW, and 12 hydroelectric projects, with
total net median water capability of 508,000 kW. 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 160,000 kW
wholly-owned Corette Plant. All of the Utility's Colstrip coal requirements
are supplied by Western Energy Company 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 20 contracts totaling 409,000 kW of firm
winter peak capacity. These contracts vary in type, size, seller and ending
dates.
Hydroelectric projects are licensed by the FERC under licenses which
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
Item 8, "Financial Statements and Supplementary Data - Note 2 to the
Consolidated Financial Statements."
At December 31, 1996, the Utility owned and operated 6,194 miles of
transmission lines and 15,433 miles of distribution lines.
The following table represents average revenues received per kWh by
customer classification for electricity from all sources for the years 1996,
1995 and 1994.
Year Ended December 31
Customer Classification 1996 1995 1994
Residential $0.061 $0.059 $0.057
Commercial 0.055 0.052 0.050
Industrial 0.041 0.040 0.038
Sales to Other Parties 0.018 0.021 0.025
Government and Municipal 0.077 0.073 0.070
NATURAL GAS PROPERTIES: The Utility produces natural gas from fields in
Montana and Wyoming and through its subsidiary, Canadian-Montana Gas Company,
from fields in southeastern Alberta, Canada.
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, 1996, the Gas Utility and its subsidiaries owned and
operated 2,103 miles of natural gas transmission lines and 3,322 miles of
distribution mains.
All natural gas volumes are at a pressure base of 14.73 psia at
60 degrees Fahrenheit, except for those volumes used to compute the average
revenues by customer classification.
For information pertaining to the Company's net recoverable utility
natural gas reserves, see Item 8, "Financial Statements and Supplementary
Data."
In addition to owned reserves, the Utility at December 31, 1996,
controlled under purchase contracts, 51,388 Mmcf of proven reserves in the
United States and 26,724 Mmcf in Canada. No significant change has occurred
and no event has taken place since December 31, 1996, that would materially
affect the magnitude of the Utility's reserve estimates.
Utility natural gas reserve estimates have not been filed with any other
federal or any foreign governmental agency during the past twelve months.
Certain lease and well data, with respect only to owned wells, are filed with
the Internal Revenue Service for tax purposes.
Total produced, royalty and purchased natural gas volumes in Mmcf during
the last three years were as follows:
United States Canada
Produced Royalty Purchased Produced Royalty Purchased
1994 4,724 230 7,565 3,350 998 2,709
1995 5,176 632 7,292 4,650 735 3,031
1996 5,055 230 6,749 4,694 950 4,850
The following table presents information as of December 31, 1996,
pertaining to the Utility natural gas wells and the owned or leased acreages in
which they are located.
United States Canada
Gross productive wells 615 183
Net productive wells 502 172
Gross wells with multiple completions 19 11
Net wells with multiple completions 13.8 10.5
Gross producing acres 360,978 150,236
Net producing acres 285,205 134,288
Gross undeveloped acres 20,601 71,040
Net undeveloped acres 17,035 65,712
These acreages are located primarily in Montana and Alberta, Canada.
The Company anticipates that during 1997 total exploration and
development expenditures (expense and capital) will be approximately $600,000
in the United States and approximately $900,000 in Canada.
The following table presents information on Utility natural gas
development wells drilled during 1996, 1995 and 1994. No exploratory wells
were drilled in the periods specified
United States Canada
1996 1995 1994 1996 1995 1994
Net productive development
wells 2.00 12.81 12.38 7.00 4.00 6.00
Net dry development wells - 1.60 4.00 - 4.00 1.00
The following table presents average revenues received per Mcf by
customer classification for natural gas from all sources for the years 1996,
1995 and 1994. Revenues per Mcf are computed based on volumes at varying
pressure bases as billed.
Year Ended December 31
Customer Classification 1996 1995 1994
Residential $4.72 $ 4.74 $ 4.64
Commercial 4.54 4.54 4.43
Industrial 4.32 4.33 4.25
Other gas utilities 3.41 3.64 3.72
The following table presents the average production cost per Mcf for
produced utility natural gas, in U. S. dollars, for the three years 1996, 1995
and 1994.
United States Canada
1994 $ 1.01 $ 0.40
1995 1.10 0.34
1996 0.92 0.32
Changes in operational practices will cause the price per unit to
fluctuate.
NONUTILITY OPERATIONS:
COAL PROPERTIES: Western leases and produces coal from Montana
properties. Northwestern leases and produces lignite from properties in Texas.
Horizon leases coal properties in Wyoming. Western SynCoal owns a 50%
partnership interest in a coal enhancement demonstration plant at Colstrip,
Montana. Basin produced coal from properties in Colorado that North Central
owns and leases. Basin ceased mining operations in December 1995 and the Mine
was sealed in 1996.
Western has coal mining leases covering approximately 528,000,000 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 236,000,000 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 171,400,000 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 154,000,000 tons located in central Texas. These reserves
are in close proximity to the Jewett Mine.
Horizon has surface rights and coal leases which contain approximately
684,000,000 proved and probable, and recoverable tons of compliance quality
surface-mineable coal reserves in the southern Powder River coal region located
near Gillette, Wyoming. A mining permit application was submitted to the
Wyoming Department of Environmental Quality in November 1994. Horizon expects
to receive the mine permit in the fourth quarter of 1997. Although property
development is required by 2002, the Company's plans for mine development are
not definite.
OIL AND NATURAL GAS PROPERTIES: In January 1997, Altana sold its interest
in nine (9) non-strategic oil and gas fields. The sale represented 5.2 Mmcf
(10% of Canadian total) of natural gas, and 731,000 barrels (23% of Canadian
total) of oil.
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 1996, 1995 and
1994.
<TABLE>
<CAPTION>
Year Ended December 31
1996 1995 1994
United United United
States Canada States Canada States Canada
<S> <C> <C> <C> <C> <C> <C>
Average sales price:
Per Mcf of natural gas $ 1.54 $ 1.10 $ 1.21 $ 0.99 $ 1.60 $ 1.48
Per barrel of oil 19.74 16.88 16.55 15.29 14.75 12.95
Per barrel of natural gas liquids 10.56 14.44 8.17 11.33 9.50 9.99
Average production cost:
Per barrel of oil equivalent $ 3.94 $ 3.10 $ 3.36 $ 2.90 $ 3.00 $ 2.93
</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 1995 to 1996, 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 wellwork and
maintenance in the Bowdoin Field. Production from this field began in late
1996. Production taxes increased due to higher product prices.
Information on the Nonutility natural gas and oil wells and the owned or
leased acreage in which they are located, as of December 31, 1996, is presented
below.
United
States Canada
Gross productive natural gas wells 642 151
Net productive natural gas wells 416.37 100.46
Gross productive oil wells 234 194
Net productive oil wells 210.99 107.95
Gross producing acres 194,518 148,942
Net producing acres 134,457 76,775
Gross undeveloped acres 296,785 227,073
Net undeveloped acres 186,098 153,966
The wells located in Canada include multiple completions of 8 gross
productive natural gas wells and 6.70 net productive gas wells. The wells
listed above include multiple completions of 19 gross productive natural gas
wells and 9 gross productive oil wells in the United States, and 11 gross
productive natural gas wells and 1 gross productive well in Canada.
The foregoing acreage located in the United States and Canada are
primarily in the Rocky Mountain states and Alberta.
It is anticipated that during 1997 total exploration, acquisition and
development expenditures (expense and capital) will be approximately
$31,762,000 in the United States and approximately $17,708,000 in Canada. See
Item 7, "Management's Discussion and Analysis of Financial Conditions and
Results of Operations - Liquidity and Capital Resources" for further discussion
of 1997 capital expenditures.
The following table presents information on Nonutility oil and natural
gas exploratory and development wells drilled during 1996, 1995 and 1994.
United States Canada
1996 1995 1994 1996 1995 1994
Net productive natural gas
exploratory wells 0.33 2.99 1.15 0.55 0.50 0.87
Net productive oil
exploratory wells - 1.00 - 2.23 - -
Net productive natural gas
development wells 2.58 6.23 6.28 1.83 - 1.06
Net productive oil
development wells - 1.34 1.29 9.78 7.38 8.67
Net dry exploratory wells 1.75 2.50 3.44 .50 1.69 2.00
Net dry development wells 1.81 4.24 0.59 .04 0.50 3.05
For information on properties acquired, see Item 8, "Financial Statements
and Supplementary Data."
TELECOMMUNICATIONS PROPERTIES: Touch America has a 4,100 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. Touch
America is beginning to build its network capacity. During 1996, the Company
acquired 11 PCS licenses in 12 marketing areas between Minneapolis, Minnesota
and Seattle, Washington which presents an opportunity for wireless telephone
service in that region.
INDEPENDENT POWER PROPERTIES: Independent power operations sell power
from the Company's 210 MW Colstrip 4 leased interest and associated common and
transmission facilities. They also own or have contract rights in a number of
Nonutility power generation projects:
<TABLE>
<CAPTION>
Projects in Operation (As of March 12, 1997):
IPG
Share
of
Rated Rated
Location Capa- Capa-
(Commercial Ownership city city Customer
Project Operation) or Interest MW MW Electricity Thermal
<S> <C> <C> <C> <C> <C> <C>
Encogen One Sweetwater, TX 49.9% 255 128 Texas Utility U.S. Gypsum
(1989) Electric Co.
Tenaska-Paris(1) Paris, TX 10.0% 223 22 Texas Utility Campbell
(1989) Electric Co. Soup Co.
Encogen Four Buffalo, NY 49.5% 62 31 Niagara Mohawk Outokumpu
(1992) Power Corp. AmBrass
Lockport(1) Lockport, NY 22.3% 168 37 New York State Harrison
(1993) Electric & Radiator
Gas Corp.
Teesside United Kingdom 3.2%(2) 1,725 56 Various U.K. --
(1993) customers
Tenaska- Ferndale, WA 25.1% 245 61 Puget Sound Tosco Corp.
Ferndale (1994) Power & Light
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 SHARED OF RATED CAPACITY MW 383
<FN>
(1) These co-generation facilities have a long-term contract with NARCO (a
Nonutility subsidiary) to purchase a portion of their natural gas supply.
(2) 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 (3) Power Admn
Uch Power Uch Pakistan 3.2% 586 19 Pakistan Water None
Limited (1998) & Power
Department
<FN>
(3) Construction is approximately 50% complete but has been suspended due to a dispute
with the Bonneville Power Administration.
</FN>
</TABLE>
<TABLE>
<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 (4) 500 (4) State of Andhra None
Krishnapatnam Pradesh Pradesh
<FN>
(4) Not determinable at this time.
</FN>
</TABLE>
ITEM 3. LEGAL PROCEEDINGS
Refer to Item 7, "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Environmental Issues" and to Item 8,
"Financial Statements and Supplementary Data - Note 2 to the Consolidated
Financial Statements" for information pertaining to legal proceedings.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
EXECUTIVE OFFICERS OF THE REGISTRANT
The Montana Power Company Officers:
In 1992, D. T. Berube, 63, was elected Chairman of the Board and Chief
Executive Officer.
On January 23, 1996, R. P. Gannon, 52, was elected Vice Chairman of the
Board and President. He had previously served as President and Chief Operating
Officer - Utility Operations from 1990-1996.
In 1996, J. P. Pederson, 54, was elected Vice President Chief Financial
and Information Officer. He had previously served as Vice President and Chief
Financial Officer since 1991.
In 1996, P. K. Merrell, 44, was elected Vice President, Human Resources
and Secretary. She had previously served as Vice President and Secretary since
1993, and Secretary from 1992-1993.
In 1991, M. E. Zimmerman, 48, was elected Vice President and General
Counsel.
On May 15, 1996, D. S. Smith, 53, was elected Controller. He had
previously served as Controller for Entech from 1988-1996.
On May 15, 1996, E. M. Senechal, 47, was elected Treasurer. She had
previously served as Vice President and Treasurer for Entech from 1984-1996.
Energy and Communications Services Division:
On January 23, 1996, J. D. Haffey, 51, 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, 51, 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, C. D. Regan, 59, was elected Vice President, Transmission
Services. He had previously served as Vice President - Natural Gas Supply and
Transportation 1993-1996. and as Vice President - Energy Services for the
Utility Division from 1991-1993.
In 1996, P. J. Cole, 39, was elected Vice President, Business Development
and Regulatory Affairs. He had previously served as Treasurer for the Utility
Division from 1993-1996, Assistant Treasurer from 1992-1993 and Manager,
Corporate Financial Planning and Analysis from 1986-1992.
In 1996, M. J. Meldahl, 47, was elected Vice President, Communication
Services. He had previously served as Vice President, Technology Division -
Entech since 1988.
Energy Supply Division:
In 1996, R. F. Cromer, 51, 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, 59, 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, 48, was elected Vice President - Colstrip
Project Division for the Energy Supply Division. He had previously served as
Vice President, Colstrip Project Division since 1995 and as Manager of Business
and Change Management from 1994-1995. He was Superintendent of Colstrip Units
l and 2 from 1988-1994.
In 1996, R. P. Madison, 59, 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, 46, was elected Vice President, Coal Operations.
He had previously served as Vice President, Entech Coal Division from 1992-
1996.
In 1996, F. L. Rotondi, 36, was elected Vice President, Business
Development. He had previously served as Manager of Business Development -
Entech since 1989.
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
1996 and 1995. The number of common shareholders of record on December 31,
1996, was 40,902.
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
Dividends
Declared
per
1995 High Low Share
1st quarter $ 24.125 $ 22.500 $ 0.40
2nd quarter 23.875 22.250 0.40
3rd quarter 23.375 21.125 0.40
4th quarter 23.750 21.500 0.40
ITEM 6. SELECTED FINANCIAL DATA
The Montana Power Company and Subsidiaries
Balance Sheet Items (000)
1996 1995 1994
Assets:
Utility plant $2,281,395 $2,204,386 $2,071,749
Less accumulated depreciation
and depletion 705,119 663,216 619,195
Net Utility plant 1,576,276 1,541,170 1,452,554
Nonutility property 666,679 633,079 600,299
Less accumulated depreciation
and depletion 256,489 252,612 207,486
Net Nonutility property 410,190 380,467 392,813
Total net plant and property 1,986,466 1,921,637 1,845,367
Other assets 711,749 664,454 667,330
Total Assets $2,698,215 $2,586,091 $2,512,697
Liabilities:
Common shareholders' equity $ 999,657 $ 976,043 $ 988,100
Unallocated stock held by trustee
for retirement savings plan (28,360) (30,565) (32,580)
Preferred stock 57,654 101,416 101,416
Mandatorily redeemable preferred
securities of trust 65,000
Long-term debt 633,339 616,574 588,876
Other liabilities 970,925 922,623 866,885
Total Liabilities $2,698,215 $2,586,091 $2,512,697
ITEM 6. SELECTED FINANCIAL DATA
The Montana Power Company and Subsidiaries
Balance Sheet Items (000)
1993 1992 1991
Assets:
Utility plant $1,943,428 $1,854,297 $1,774,185
Less accumulated depreciation
and depletion 572,141 533,216 495,720
Net Utility plant 1,371,287 1,321,081 1,278,465
Nonutility property 596,769 552,537 531,455
Less accumulated depreciation
and depletion 198,951 178,275 156,324
Net Nonutility property 397,818 374,262 375,131
Total net plant and property 1,769,105 1,695,343 1,653,596
Other assets 616,922 590,079 564,450
Total Assets $2,386,027 $2,285,422 $2,218,046
Liabilities:
Common shareholders' equity $ 945,651 $ 902,989 $ 862,601
Unallocated stock held by trustee
for retirement savings plan (34,419) (36,098) (37,631)
Preferred stock 101,419 51,984 51,984
Mandatorily redeemable preferred
securities of trust
Long-term debt 571,870 581,179 603,266
Other liabilities 801,506 785,368 737,826
Total Liabilities $2,386,027 $2,285,422 $2,218,046
Income Statement Items (000)
1996 1995 1994
Revenues $ 973,208 $ 953,224 $1,005,970
Expenses:
Operations 383,789 420,472 436,610
Maintenance 65,390 68,286 75,357
Selling, general and administrative 111,144 101,872 106,989
Taxes other than income taxes 87,903 89,858 99,200
Depreciation, depletion and
amortization 88,744 86,976 86,711
Writedowns of long-lived assets (a) 74,297
736,970 841,761 804,867
Income from operations 236,238 111,463 201,103
Interest expense and other income:
Interest 48,770 43,656 42,817
Other (income) deductions - net (3,893) (10,704) (10,532)
44,877 32,952 32,285
Income taxes 71,975 21,574 55,226
Net income 119,386 56,937 113,592
Dividends on preferred stock 8,358 7,227 7,227
Net income available for common stock $ 111,028 $ 49,710 $ 106,365
Net income per share of common stock:
Utility operations $ 1.13 $ 1.22 $ 0.91
Nonutility operations 0.90 (0.30) 1.09
$ 2.03 $ 0.92 $ 2.00
Dividends declared per share of
common stock $ 1.60 $ 1.60 $ 1.60
Average shares outstanding (000) 54,634 54,121 53,125
(a) Refer to Item 8, "Financial Statements and Supplementary Data - Note 12
to the Consolidated Financial Statements."
Income Statement Items (000)
1993 1992 1991
Revenues $1,024,285 $ 943,872 $ 889,254
Expenses:
Operations 476,733 412,387 365,597
Maintenance 70,029 70,525 70,510
Selling, general and administrative 104,900 91,230 92,126
Taxes other than income taxes 92,430 94,328 86,428
Depreciation, depletion and
amortization 82,696 81,732 75,782
Writedowns of long-lived assets
826,788 750,202 690,443
Income from operations 197,497 193,670 198,811
Interest expense and other income:
Interest 48,023 49,166 52,897
Other (income) deductions - net (11,857) (8,200) (10,194)
36,166 40,966 42,703
Income taxes 54,120 45,639 50,393
Net income 107,211 107,065 105,715
Dividends on preferred stock 4,353 3,790 3,790
Net income available for common stock $ 102,858 $ 103,275 $ 101,925
Net income per share of common stock:
Utility operations $ 1.07 $ 0.97 $ 0.98
Nonutility operations 0.91 1.05 1.05
$ 1.98 $ 2.02 $ 2.03
Dividends declared per share of
common stock $ 1.585 $ 1.55 $ 1.495
Average shares outstanding (000) 52,040 51,126 50,317
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
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 1994 through
1996 or which are expected to have an impact on operating results in the
future.
In May 1996, the Company began managing its operations as a restructured
company with two divisions: Energy Supply, and Energy and Communications
Services. Pending regulatory decisions pertaining to the Company's
restructuring, the discussions and financial information which follow are
presented in a Utility and Nonutility format.
Safe Harbor for Forward-Looking Statements:
The Company is including the following cautionary statements to make
applicable and take advantage of the safe harbors 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" 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 and changes in the utility industry.
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.
Net Income Per Share of Common Stock:
The Company's net income available for common stock increased to
$111,028,000 in 1996 compared to $49,710,000 and $106,365,000 in 1995 and 1994,
respectively. The following table shows the sources of consolidated net income
on a per share basis.
1996 1995 1994
Utility Operations $ 1.13 $ 1.22 $ 0.91
Nonutility Operations 0.90 (0.30) 1.09
$ 2.03 $ 0.92 $ 2.00
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.
The decrease in 1995 consolidated net income was largely due to a
90-cent-per-share charge related to the writedown of an investment in the
Golden Eagle Mine in Colorado, the adoption of SFAS No. 121 and the March 1995
arbitration decision that lowered the price of coal sold to Colstrip Units 1
and 2. The lower price, retroactive to July 1991, benefited Utility operations
by 13 cents per share through lower fuel costs, but reduced Nonutility earnings
by 18 cents.
Utility operations also benefited in 1995 from the availability of low-
cost hydroelectric power in the regional energy market, displacing higher cost
thermal energy. The availability of this low-cost power negatively impacted
Nonutility earnings due to reduced coal sales to the Colstrip units. The
expiration of a Midwestern coal contract in 1994 and the absence of independent
power development fees also contributed to the decline in 1995 Nonutility
earnings. Increased income from independent power operating projects partially
offset that decrease.
<TABLE>
<CAPTION>
UTILITY OPERATIONS
Year Ended December 31
1996 1995 1994
Thousands of Dollars
<S> <C> <C> <C>
ELECTRIC UTILITY:
REVENUES:
Revenues $ 430,171 $ 421,999 $ 427,686
Intersegment revenues 5,793 5,813 5,924
435,964 427,812 433,610
EXPENSES:
Power supply 136,817 148,240 178,927
Transmission and distribution 30,263 26,916 27,566
Selling, general and administrative 52,091 41,932 46,134
Taxes other than income taxes 46,191 43,302 42,214
Depreciation and amortization 48,479 42,506 40,699
313,841 302,896 335,540
INCOME FROM ELECTRIC OPERATIONS 122,123 124,916 98,070
NATURAL GAS UTILITY:
REVENUES:
Revenues (other than gas supply
cost revenues) 107,782 93,453 88,914
Gas supply cost revenues 20,746 21,660 18,191
Intersegment revenues 649 852 917
129,177 115,965 108,022
EXPENSES:
Gas supply costs 20,746 21,660 18,191
Other production, gathering and exploration 9,335 9,643 8,882
Transmission and distribution 11,711 10,934 10,154
Selling, general and administrative 18,684 17,161 17,669
Taxes other than income taxes 15,722 14,841 13,708
Depreciation, depletion and amortization 12,149 10,793 9,842
88,347 85,032 78,446
INCOME FROM GAS OPERATIONS 40,830 30,933 29,576
INTEREST EXPENSE AND OTHER INCOME:
Interest 46,663 44,031 43,013
Other (income) deductions - net (402) (5,419) (3,947)
46,261 38,612 39,066
INCOME BEFORE INCOME TAXES 116,692 117,237 88,580
INCOME TAXES 46,687 44,047 33,171
UTILITY NET INCOME $ 70,005 $ 73,190 $ 55,409
</TABLE>
UTILITY OPERATIONS:
The Company is a winter-peaking utility, which earns most of its revenue
from retail customers in the first and fourth quarters of the year. Weather
can significantly affect revenues and net income, and should be considered when
analyzing trends. As measured by heating degree days, a unit measuring the
extent to which the average daily temperature falls below 65 Fahrenheit, the
temperatures in 1996 in the Company's service territory were 12% colder than
1995 and 11% colder than the historic average. Temperatures in 1995 were six
percent colder than 1994 and equal to the historic average.
The Company's electric wholesale revenues and power purchase expenses are
influenced by weather, streamflow conditions and the wholesale power market in
the Northwest and California. During the year ended December 31, 1996, there
was a surplus of energy in the region which caused lower wholesale and
purchased-power prices. February 1997 forecasts for Montana streamflows predict
water volumes for the April to September period to be about 150% of average.
Higher than average runoff is also predicted for the Columbia River Basin. The
resulting hydroelectric generation will put more energy into the market as well
as displace some thermal generation.
Since 1994, Utility employment, through targeted and voluntary staff
reductions, under a severance plan, has been permanently reduced by
approximately 450 positions.
Competitive Environment:
The electric and natural gas utility businesses are in transition as
competition to provide energy commodity and related services to wholesale and
retail customers intensifies. The Company has taken a proactive approach to
these industry changes and has restructured to better align its business
functions with markets. Although the Company's principal business is its
utility operations, it received only 58% of its 1996 revenues and 59% of its
1996 net income from those operations. The remaining revenue and net income
was provided by its diverse Nonutility businesses involved in coal, oil and
natural gas, independent power and telecommunications operations. The
Company's hydroelectric and thermal units have low operating costs that should
allow it to compete effectively with other power generators. Issues remain to
be addressed, however, in the transition to a competitive power-supply
marketplace. These issues focus primarily on the recovery of the Company's
transition costs relating to certain power-purchase contracts, regulatory
assets, electric generating facilities and other items. While the Company
does not have an unusually large amount of regulatory assets compared to other
utilities, it does have regulatory assets to be recovered. The Company, under
the Public Utility Regulatory Policy Act (PURPA), entered into a number of
long-term purchase-power contracts from qualifying facilities (QF's) under
which the prices paid for power are now substantially above market. While the
Company's generation assets are low cost nationally, they will have to compete
with a surplus power-supply market in the Northwest. (For further information
pertaining to regulatory assets and QF contracts, see Item 8, "Financial
Statements and Supplementary Data - Notes 1 and 3 to the Consolidated
Financial Statements.") A variety of activities, which are detailed below,
will help the Company manage change and position itself for the future.
Wholesale --
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, among other things,
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 filed open-access transmission tariffs with FERC in November
1995. To fully conform to FERC Order No. 888 the Company refiled its tariffs
and separated its transmission and generation functions 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.
During January 1997, the Company created, with FERC's approval, an
affiliated power marketing subsidiary, MP Energy. MP Energy is pursuing
opportunities that emerge as the result of utility industry restructuring. MP
Energy is focused on new energy markets outside of the Company's traditional
utility boundaries, primarily in the western half of the United States and the
upper Midwest. MP Energy targets wholesale and large industrial customers
which have been granted the right, either by state or federal agencies, to
pursue other sources for their electricity and natural gas supplies. Any gains
or losses realized by the purchase and resale of energy in the unregulated
market will pass to the shareholders. Any gains realized through brokering
Utility surpluses will benefit general business customers of the regulated
Utility.
The Company has joined a group of other Pacific Northwest electric
utilities in a memorandum of understanding to study the formation of an
independent grid operator called "IndeGo" for the utilities' high-voltage
transmission lines. The grid operator would be independent of the utilities, as
required by FERC. IndeGo, though still in its development stage, is intended to
ensure the reliability of the regional transmission grid, to provide non-
discriminatory, open-access to electric transmission facilities in compliance
with recent FERC rulings and to help facilitate the operation of an evolving
competitive electric power market. The group, which continues to add new
members, intends to file a proposal with FERC and state regulators during 1997
and operation is expected to commence during 1999. Through IndeGo, the group of
utilities expects to increase the efficiency of their transmission systems and
provide improved access for scheduled electricity transactions in Oregon,
Washington, Idaho, Montana, Wyoming, Utah, Colorado and northern Nevada.
The Electric Utility currently competes with other utilities, marketers
and independent power producers in the wholesale market. 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, provides an example of the growing competition for wholesale
customers. Central terminated its contract with the Company, effective June
2000, and is seeking competitive bids to replace the energy. Central's 120 MW
load accounts for six percent of the Company's system load. The Company and
other electric suppliers are currently in the process of bidding for the
cooperatives' power requirements beyond June 2000. The Company plans to make
an application to FERC for recovery of costs which will be stranded by the
termination of this contract.
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 gas operations. The Company believes that the
combination of these experiences should give it an advantage in the
competitive environment.
Retail --
The Electric Utility does not yet face direct competition from other
electric suppliers in its retail market. During the past ten years, the
Company has sold approximately 30% of its system load to 16 contract
industrial customers. These sales and others are expected to be impacted by
competition in the future. The Company already has instituted Real Time
Pricing and Time of Use rate offerings in an attempt to bring market-like
rates to existing customers.
In open competition with two other utilities, the Company has
successfully secured a new retail industrial load of approximately 100 MW,
which will come on line in 1998. The acquisition of this load was dependent
upon an offer of a market-based rate. This customer's rate has been approved
by the Montana Public Service Commission (PSC). The Company has applied to the
PSC for a generic market-based rate offering to allow the Company to compete
for new loads that arise between now and a PSC-approved transition to retail
competition for all customers.
The Company is promoting a transition to retail competition over the
next several years. The Company has legislative proposals before the current
session of the Montana Legislature to open up the Utilities' electric and
natural gas supply functions to full competition by mid-2002.
The proposed electric legislation provides for a transition to choice
for all customers; large-customer choice occurring on July 1, 1998 and small
commercial and residential customer choice occurring no later than July 1,
2002. Residential and small-commercial pilot programs are expected to be
provided beginning July 1, 1998. Functional separation of supply, transmission
and distribution, with no forced divestiture of assets, is proposed.
Transmission and distribution would remain regulated. The proposed
legislation would allow for the recovery of transition costs, specifically
recovery of above-market QF costs and regulatory assets and a four-year
recovery period for Utility-owned above-market generation costs. Transition
bond financings would be used to lower transition costs. The legislation also
proposes the role the PSC will have in regulating distribution services,
licensing electricity suppliers in the state, and promulgating rules regarding
anticompetitive and abusive practices. Finally, the legislation provides for
reciprocity between utility companies. The ultimate disposition of this
legislation is uncertain, but some form of retail competition in Montana now
appears inevitable.
The proposed natural gas legislation is similar in form to the electric
legislation, but unique to natural gas utility service. In parallel with the
legislative actions proposed by the Company, the Gas Utility filed a formal
open-access and reorganization plan with the PSC in July 1996. This plan calls
for the transfer of all producing assets to an unregulated affiliate and the
retention of regulation for transmission, storage and distribution functions.
The movement to choice for all customers is proposed to be completed by mid-
2002, starting immediately for all customers with loads in excess of
5,000 decatherms per year who will have the opportunity to buy their supply
from their choice of natural gas supplier for the 1997-1998 heating season,
with smaller users transitioning over the five year period. The procedural
schedule for this filing has been suspended subject to continuing settlement
efforts among the parties to the filing. Substantial progress has been made
toward agreement in several areas. Hearings on the agreed-to items begin in
late March 1997. The procedure schedule on the remaining unsettled matters is
anticipated to begin in early May 1997 after the legislative proposals are
decided.
The Gas Utility has provided open-access to large customers
(60,000 Mcf's and above) since 1991 and expects to further open the system to
provide choice to all retail customers and to concentrate on the regulated
transmission, storage and distribution businesses. The Company is proposing to
transfer the Utility's existing production assets to an unregulated affiliate.
The Company submitted an Electric Utility "informational filing" to the
PSC in December 1996 that outlines the Company's restructuring plan, the
movement of generation to full competition, and an estimate of transition
costs together with the mechanisms for collection of these costs. Depending on
the outcome of the Montana electric retail open-access legislation, the
Company will update its December informational filing converting it to a
formal submission to the PSC that proposes full unbundling of services and
market-based rates for electric supply.
The Company has also created a new unregulated energy services
subsidiary, Montana Energy Services Company, to focus on activities associated
with the selling of retail energy-related products and services in a
competitive marketplace. This may include, among other things, assisting
customers with utility rate management; managing power contracts; installing
energy-efficient equipment; and tracking facility energy use and costs. This
subsidiary was created to more clearly separate the more competitive, retail
markets planned for this company from ongoing regulated Demand Side Management
activities.
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 addressed in the
transition process or they would be eliminated from the balance sheet and
included in income in the period when the discontinuation occurred. 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. For further information pertaining
to SFAS No. 71, see Item 8, "Financial Statements and Supplementary Data -
Note 1 to the Consolidated Financial Statements."
Summary of Significant Regulatory Matters:
Effective July 1, 1996, the PSC approved a rate plan for the Electric
Utility, affirming a settlement negotiated with the Montana Consumer Counsel
and the Large Customer Group, which increased revenues 4.2% or $14,800,000
annually. This increase includes $5,800,000 which had previously been approved
on an interim basis, effective March 1, 1996. The plan also includes revenue
increases of 2.4% or approximately $8,800,000 on January 1, 1997 and 2.4% or
approximately $9,000,000 on January 1, 1998. The PSC's final order was based
on an 11% return on common equity. Actual earnings in excess of 11.4% return
on common equity will be shared on a 50% basis between ratepayers and
shareholders.
The rate order also included the approval of a natural gas revenue
increase which was designed to increase revenues 5.3% or $6,700,000 annually,
effective July 1, 1996. This increase includes $3,100,000 which had been
included in rates on an interim basis, effective March 1, 1996. The increase
was based on an 11.25% return on common equity.
In July 1996, the Company filed a natural gas rate case requesting an
increase in natural gas revenues of $4,800,000 or 3.8% annually to recover
increased costs of service and to facilitate the Gas Utility's restructuring
plan. The plan proposes a transportation eligibility threshold lower than the
current 60,000 Mcf's per year, thereby increasing the number of customers
eligible to choose their own suppliers. Within five years, all customers would
have this choice. The plan requests the recovery of all Gas Utility
investment. Settlement meetings are in progress currently and the Company
cannot predict when a decision will be rendered.
On November 21, 1996, the Company filed its annual gas tracking filing
which resulted in a total annual adjustment decrease of $2,260,000, reflecting
lower gas costs and other tracking activities offset by the end of
price-reduction amortizations approved in previous filings. Rates reflecting
this filing were effective for service on and after December 1, 1996.
As discussed previously in "Competitive Environment", the Company also
filed an informational electric restructuring plan with the PSC on
December 20, 1996.
Electric Utility:
1996 Compared to 1995
Excluding the impact of the coal arbitration decision recorded during
1995, income from electric operations benefited from increased tariffs, colder
weather, continued customer growth and reduced power supply expenses offset by
increased selling, general and administrative (SG&A), depreciation and taxes
other than income tax expenses.
Revenues:
The following table shows year-to-year changes for the previous two
years, in millions of dollars, in the various classifications of electric
revenues, and the related percentage changes in volumes sold and prices
received:
1996 1995
General business - revenue $ 13 $ 12
- volume (2)% (1)%
- price/kWh 6 % 4 %
Other utilities - revenue $ (6) $ (16)
- volume 3 % (5)%
- price/kWh (12)% (17)%
Miscellaneous - revenue $ 1 $ (2)
Total operating revenues increased two percent or $8,100,000. Residential
and commercial customer revenues were up approximately $24,500,000 or 11%,
primarily as a result of a six percent increase in volumes sold due to colder
weather and two percent customer growth, along with increased tariffs.
Partially offsetting the increase was a decrease of $12,000,000 in revenues
from the industrial class principally due to a large retail customer closing
operations in December 1995. The customer was served under an interruptible
economic retention rate that was lower than the tariff rate.
Wholesale energy sales declined approximately $6,000,000 over 1995,
primarily due to the expiration of two firm sales contracts, one in late 1995
and the other in early 1996. The decrease was partially offset by increased
non-firm or secondary volumes sold, offset by lower regional energy prices.
An increase in miscellaneous revenue resulted primarily from higher
wheeling rates.
Expenses:
Power Supply:
The following table shows the Company's sources of electricity and power-
supply expenses (operation, fuel for electric generation and maintenance) for
1996 and 1995:
1996 1995
Sources MWh's
Hydroelectric 4,064,083 3,479,506
Steam 4,271,701 4,754,489
Purchases and Other 2,557,460 2,666,885
Total Power Supply 10,893,244 10,900,880
Expenses Thousands of Dollars
Hydroelectric $ 19,423 $ 19,291
Steam 47,185 44,010
Purchases and Other (a) 70,209 84,939
Total Power Supply Expenses $ 136,817 $ 148,240
Cents per Kilowatt-Hour 1.256 1.360
(a) Includes energy and capacity payments on purchased power contracts.
Excluding the impact of the coal arbitration decision that reduced 1995
steam expenses $11,300,000, power-supply expenses decreased $22,700,000. Better
streamflow conditions caused increases in Utility and regional low-cost
hydroelectric generation resulting in displacement of higher cost thermal
generation. Shorter maintenance periods, improved productivity and permanent
employee reductions at the Colstrip units also decreased steam expense.
Purchased power costs declined due to the expiration of two higher priced firm
contracts and a $3,600,000 credit from a party who delivers energy to the
Company's customers. The decrease was partially offset by increased purchases
of lower cost non-firm power and additional payments to independent power
producers.
Other Expenses:
Transmission and distribution expense increased as a result of
non-recurring items. SG&A increased primarily due to approximately $4,100,000
of expense recorded in the fourth quarter of 1996 related to permanent employee
reductions. As a result of the reduced payroll costs at the Colstrip plants,
SG&A costs allocated to the non-operating owners decreased from 1995 causing a
variance of approximately $1,800,000. Also contributing to the increase was
approximately $1,200,000 of insurance proceeds received in 1995 that were
absent from 1996 expenses. The increase in taxes other than income taxes was
due to increased property taxes resulting from property additions and higher
mill levies. Depreciation expense increased as a result of greater plant
investment and a change in the PSC-approved depreciation rate. See Liquidity
and Capital Resources for further discussion.
1995 Compared to 1994
Income from electric operations increased significantly over 1994
primarily the result of reduced power-supply costs, partially offset by a
decrease in operating revenues. Power-supply costs decreased due to the
previously discussed coal arbitration decision and reduced purchased-power
costs resulting from a 16% increase in low-cost hydroelectric generation and
reduced brokering transactions.
Revenues:
Revenue from general business customers increased largely as a result
of higher tariffs. Continued customer growth in the residential and
commercial markets, and colder temperatures resulted in increased sales to
these customer classes. Industrial volumes declined, however, due to
reductions in production by several customers, a 25% decrease in irrigation
loads due to cooler temperatures and increased precipitation, and the loss of
a large industrial customer.
Favorable hydroelectric generating conditions throughout the Northwest
kept energy prices below their 1994 levels all year, reducing revenues from
the off-system sales market. Volumes sold decreased 150,000 MWhs from 1994.
Miscellaneous revenues decreased primarily as a result of regulatory
accounting entries.
Expenses:
Power Supply:
The following table shows the Company's sources of electricity and power-
supply expenses (operation, fuel for electric generation and maintenance) for
1995 and 1994:
1995 1994
Sources MWh's
Hydroelectric 3,479,506 2,999,396
Steam 4,754,489 4,909,852
Purchases and Other 2,666,885 3,193,522
Total Power Supply 10,900,880 11,102,770
Expenses Thousands of Dollars
Hydroelectric $ 19,291 $ 18,395
Steam 44,010 61,385
Purchases and Other (a) 84,939 99,147
Total Power Supply Expenses $ 148,240 $ 178,927
Cents per Kilowatt-Hour 1.360 1.612
(a) Includes energy and capacity payments on purchased power contracts.
Power-supply costs decreased $30,700,000 during 1995. Of this decrease,
steam generation expenses accounted for $17,400,000, including a $15,200,000
reduction in fuel costs which resulted primarily from an arbitration decision
that reduced the price of coal sold by Western Energy Company to Colstrip
Units 1 and 2 and the Corette Plant. This price decrease was retroactive to
July 1991, and 1995 steam expenses included an $11,300,000 credit for coal
purchased in prior years. Reduced tonnage and lower prices associated with
1995 coal purchases accounted for the remaining $3,900,000 reduction in fuel
costs. In addition, improved productivity and maintenance practices at the
Colstrip generating units decreased generation maintenance expense by
$2,000,000.
Lower purchased-power expenses, net of demand side management
amortizations, contributed $14,200,000 to the reduction in power supply costs.
This reduction was made possible by the increased generation provided by the
Utility's hydroelectric facilities and reduced volumes sold to other
utilities.
Other Expenses:
SG&A expenses decreased primarily due to a reimbursement received in
1995 from insurers for Colstrip housing repair costs which had been expensed
in 1994 and lower pension costs. The increase in taxes other than income taxes
was due to increased property taxes resulting from property additions.
Depreciation and amortization expense increased as a result of additional plant
and property in service.
Natural Gas Utility:
1996 Compared to 1995
Income from natural gas operations increased primarily due to increased
volumes sold as the result of colder weather, customer growth and higher
tariffs.
Revenues:
The following table shows year-to-year changes for the previous two
years, in millions of dollars, in the full-requirement customer classification
of natural gas revenues, and the related percentage changes in volumes sold and
prices received:
1996 1995
Full-requirement
customers -revenue $ 13 $ 4
-volume 12 % 6 %
-price/Mcf 4 % -
Natural gas revenues (other than gas supply cost revenues) increased as a
result of increased volumes sold due to weather 12% colder than 1995, a 3.6%
increase in the number of residential and commercial customers and higher
tariff rates.
Expenses:
SG&A expense increased primarily due to the recording of approximately
$1,000,000 of expense in the fourth quarter of 1996 related to permanent
employee reductions. Depreciation expense increased for the same reasons
mentioned in the Electric Utility discussion.
1995 Compared to 1994
Income from natural gas operations increased principally due to increased
volumes sold as a result of colder weather, and residential and commercial
customer growth.
Revenues:
Natural gas revenues (other than gas supply costs) increased due to
customer growth of four percent in the residential and commercial markets and
temperatures six percent colder than 1994.
Gas supply cost revenues consist of the amount authorized by the PSC to
be collected in rates from full-requirement customers to cover the cost of gas
supplied. The increase in gas supply cost revenues is attributed to the
following factors: increased volumes sold, a refund made in 1994 for over-
collection of prior years' costs and a decrease in price. Gas supply cost
revenues and gas supply cost expenses are always equal due to rate and
accounting procedures.
Expenses:
The increase in gas supply costs resulted from the reasons mentioned in
the foregoing gas supply cost revenue discussion. The increase in taxes other
than income taxes was due to increased property taxes resulting from higher
mill levies and property additions.
Interest Expense and Other Income, and Income Taxes:
The change in interest expense from 1994 to 1996 is primarily the result
of refinancing long-term debt at lower interest rates, partially offset by
increased average borrowings. In addition, there was an increase in 1996
interest expense due to a decrease in the amount capitalized on construction
projects. Other income changed in 1996 and 1995 due to separate non-recurring
events. Income taxes increased due to higher before-tax net income and a higher
1996 effective tax rate due to regulatory accounting related to deferred income
taxes on depreciation.
<TABLE>
<CAPTION>
NONUTILITY OPERATIONS
Year Ended December 31
1996 1995 1994
Thousands of Dollars
<S> <C> <C> <C>
COAL:
REVENUES:
Revenues $ 163,901 $ 207,451 $ 252,507
Intersegment revenues 31,448 25,659 42,201
195,349 233,110 294,708
EXPENSES:
Operations and maintenance 115,859 155,149 169,259
Selling, general and administrative 21,373 28,211 29,463
Taxes other than income taxes 20,883 27,210 37,733
Depreciation, depletion and amortization 5,653 11,187 12,649
Writedowns of long-lived assets 55,103
163,768 276,860 249,104
INCOME (LOSS) FROM COAL OPERATIONS 31,581 (43,750) 45,604
OIL AND NATURAL GAS:
REVENUES:
Revenues: 124,553 100,030 97,994
Intersegment revenues 272 409 254
124,825 100,439 98,248
EXPENSES:
Operations and maintenance 76,975 60,526 54,283
Selling, general and administrative 10,152 9,320 8,514
Taxes other than income taxes 2,931 2,334 3,340
Depreciation, depletion and amortization 17,080 17,569 18,464
Writedowns of long-lived assets 19,194
107,138 108,943 84,601
INCOME (LOSS) FROM OIL AND
NATURAL GAS OPERATIONS 17,687 (8,504) 13,647
INDEPENDENT POWER:
REVENUES:
Revenues 75,322 79,095 93,647
Earnings from unconsolidated investments 21,174 2,622 2,080
Intersegment sales 1,426 796 1,461
97,922 82,513 97,188
EXPENSES:
Operations and maintenance 64,274 68,300 75,080
Selling, general and administrative 5,223 3,557 4,088
Taxes other than income taxes 1,783 1,831 1,916
Depreciation, depletion and amortization 3,793 3,176 3,112
75,073 76,864 84,196
INCOME FROM INDEPENDENT POWER OPERATIONS $ 22,849 $ 5,649 $ 12,992
NONUTILITY OPERATIONS
Year Ended December 31
1996 1995 1994
Thousands of Dollars
TELECOMMUNICATIONS:
REVENUES:
Revenues $ 27,341 $ 23,247 $ 20,723
Intersegment revenues 433 377 138
27,774 23,624 20,861
EXPENSES:
Operations and maintenance 18,316 15,520 14,316
Selling, general and administrative 5,499 4,688 4,240
Taxes other than income taxes 392 343 287
Depreciation, depletion and amortization 911 803 762
25,118 21,354 19,605
INCOME FROM TELECOMMUNICATIONS OPERATIONS. 2,656 2,270 1,256
OTHER OPERATIONS:
REVENUES:
Revenues 1,185 2,647 3,441
Intersegment revenues 782 699 649
1,967 3,346 4,090
EXPENSES:
Operations and maintenance 1,206 1,607 2,471
Selling, general and administrative 1,569 849 477
Depreciation, depletion and amortization 679 942 1,183
3,454 3,398 4,131
LOSS FROM OTHER OPERATIONS (1,487) (52) (41)
INTEREST EXPENSE AND OTHER INCOME:
Interest 4,810 4,494 1,447
Other (income) deductions - net (6,193) (10,155) (8,228)
(1,383) (5,661) (6,781)
INCOME (LOSS) BEFORE INCOME TAXES 74,669 (38,726) 80,239
INCOME TAXES 25,288 (22,473) 22,056
NONUTILITY NET INCOME (LOSS) $ 49,381 $ (16,253) $ 58,183
</TABLE
NONUTILITY OPERATIONS:
On February 21, 1997, the Company and Puget Sound Power & Light Company
settled all outstanding disputes related to a power-purchase contract and coal-
purchase contracts. The Company estimates the settlement will reduce future
consolidated revenues by $11,000,000 to $13,000,000 per year, before
anticipated efficiency gains. See Item 8, "Financial Statements and
Supplementary Data - Note 2 to the Consolidated Financial Statements" for
further information.
Coal Operations:
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 the effects of those
items, income from coal operations for 1996 decreased as a result of lower
sales to Colstrip Units 3 and 4, the expiration of a Midwestern contract in
December 1995 and decreased miscellaneous coal sales.
Revenues:
Excluding a non-recurring charge of approximately $20,700,000 recorded in
1995 as a result of the Colstrip Units 1 and 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 and 4 also decreased
$13,400,000 due to a 22% decline in volumes sold as a result of these units
being taken off line during the first and second quarters of 1996 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 increase in Jewett Mine volumes sold was offset by reduced reimbursable
mining expenses, resulting in a $600,000 revenue decrease.
Expenses:
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 Company acquired the Golden Eagle Mine in 1991. The mine incurred
after-tax losses of $9,500,000 in the first nine months of 1995, and
$7,800,000 and $4,300,000 in 1994 and 1993, respectively. 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. In an effort to solve these problems, $1,100,000 was
invested in 1994 and an additional $7,100,000 was invested in 1995. 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; most of the salvageable plant and equipment was
sold or is under agreement to be sold. The disposition of these assets has
been charged against the estimated loss provision which was established in
1995. See Item 8, "Financial Statements and Supplementary Data - Note 12 to
the Consolidated Financial Statements" for further discussion of asset
impairment.
1995 Compared to 1994
The net loss from coal operations resulted from the writedown of the
investment in the Golden Eagle Mine, the implementation of SFAS No. 121, the
results of the Colstrip Units 1 and 2 coal arbitration decision, the
expiration of a Midwestern coal contract and decreased sales to Colstrip Units
3 and 4 due to the increased availability of low-cost hydroelectric power in
the region.
Revenues:
Revenues, including intersegment revenues, decreased primarily at the
Rosebud Mine. Revenues from sales to Colstrip Units 1 and 2 and the Company's
Corette Plant decreased $27,000,000 as a result of the Colstrip Units 1 and 2
coal arbitration decision in 1995. Of this amount, $20,700,000 resulted from
sales between July 1991 and December 1994. Coal volumes sold decreased
2,200,000 tons from a combination of the expiration of a Midwestern contract
at the end of 1994 and fewer tons sold to Colstrip Units 3 and 4 due to the
displacement of generation by lower cost hydroelectric generation. Revenues
decreased $11,600,000 due to the Midwestern contract expiration at the end of
1994 and $8,300,000 from Colstrip Units 3 and 4. Revenues decreased $5,000,000
due to the conclusion of coal brokering agreements in December 1994. Brokered
coal was sold at cost. At the Jewett Mine, revenues increased $1,000,000 as a
net result of a $3,000,000 increase from reimbursable mining expenses related
to higher royalty costs and land damage settlement payments, offset by
$2,000,000 decreased revenues as a result of reduced volumes sold. Golden
Eagle Mine revenues decreased $10,700,000 as a result of lower volumes
available for sale due to production problems and the inclusion of fourth
quarter revenues in the writedown of the investment in the mine.
Expenses:
The decrease in cost of sales includes $13,500,000 decreased mining
costs at the Rosebud Mine due to lower volumes sold, decreased royalties
resulting from lower coal revenues, and the expiration of coal brokering
agreements. Operating costs at the Golden Eagle Mine decreased $3,400,000
because the fourth quarter costs were included in the writedown of the
investment. The decreased costs at the Rosebud and Golden Eagle Mines were
partially offset by $3,000,000 increased costs at the Jewett Mine due to the
reasons mentioned above. Taxes other than income taxes decreased as a result
of lower Rosebud Mine coal revenues.
As mentioned in the 1996 discussion, the Company wrote down its
investment in the Golden Eagle Mine by $46,500,000 before taxes in the fourth
quarter of 1995.
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:
1996 1995
Oil -revenue $ 3 $ 1
-volume 2% (8)%
-price/bbl 15% 17 %
Natural gas -revenue $ 20 $ 1
-volume 14% 10 %
-price/Mcf 10% (8)%
Miscellaneous -revenue $ 2 -
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.
Revenues:
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.
Expenses:
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.
1995 Compared to 1994
The implementation of SFAS No. 121, effective October 1, 1995, is the
primary cause of the loss from oil and natural gas operations. Lower margins
on oil and natural gas production were offset in part by increased income from
natural gas marketing.
Revenues:
Higher market prices increased oil revenues $1,000,000. However,
declining field production and property dispositions in Canada decreased oil
volumes sold. A combination of lower market prices, and lower volumes produced
and sold in the U.S. and Canada decreased natural gas revenues $9,700,000. The
lower volumes were principally a result of well shut-ins that occurred due to
capacity constraints in Canada. Sales of purchased gas increased $10,800,000
due to higher volumes sold under short-term agreements and higher prices
received on gas sold under co-generation supply agreements.
Expenses:
Higher volumes of natural gas purchased for resale increased the cost of
sales by $5,500,000. Taxes other than income taxes decreased as a result of
lower natural gas revenues.
Independent Power Operations:
1996 Compared to 1995
Independent power operations net income for 1996 increased primarily from
continued growth in earnings from power investments throughout the year,
including a gain on the sale of a portion of an investment in the fourth
quarter of 1996. Also contributing to the increase was a decrease in power
supply costs due to the availability of low-cost hydroelectric generation in
the region to service power supply obligations.
Revenues:
Earnings from unconsolidated investments increased $8,700,000 as a result
of growth in earnings from prior investments coupled with additional
investments made in late 1995. 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 revenues resulting from a decrease in volumes sold.
Expenses:
Independent power operations 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 purchased 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.
1995 Compared to 1994
The 1995 net income from independent power operations decreased primarily
as a result of fewer development projects reaching successful completion. Also
contributing to the 1995 decrease were the absence of the 1994 gain recognized
on the sale of 50% of North American Energy Services and the 1995 loss on the
withdrawal from another investment. Net income benefited from higher earnings
from unconsolidated investments and decreases in power supply and maintenance
costs at the Colstrip plant.
Revenues:
The decrease in independent power revenues resulted primarily from a
$12,900,000 decrease in power project development fees, which were not expected
to meet the levels achieved in 1994. The increase in earnings from
unconsolidated investments resulted from higher earnings from independent power
projects which were offset by the loss on the withdrawal from a power service
business.
Expenses:
The independent power operations and maintenance expense decreased
approximately $7,000,000 due to reduced project development expenses and lower
power supply and maintenance expenses at the Colstrip plant. Project
development expenses decreased approximately $3,000,000 as a correlating result
of the anticipated decline in successful project development completions. Lower
fuel, rental and transmission costs, due primarily to reduced generation and
lower power sales, resulted in a $2,000,000 decrease in power supply costs.
Operation and maintenance expense also decreased approximately $2,000,000 due
to improved maintenance practices at the Colstrip plant.
Telecommunications Operations:
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.
1995 Compared to 1994
Additional leased network capacity sold to private businesses and a 26%
increase in minutes sold to long-distance customers increased earnings from
telecommunications operations.
Other Operations:
1996 Compared to 1995
Income from other operations decreased primarily due to a decrease in
distributions from the Company's investment in a Brazilian gold mining
operation.
Interest Expense and Other Income, and Income Taxes:
The changes in interest expense from 1994 to 1996 were a result of
increases in the amount of outstanding borrowings and the interest paid
pursuant to the 1995 coal arbitration decision discussed above. 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:
Net cash provided by operating activities was $217,293,000 in 1996
compared to $268,890,000 in 1995 and $203,886,000 in 1994. Cash from operating
activities less dividends paid provided 77% of capital expenditures in 1996,
76% in 1995 and 54% in 1994.
The Company's long-term debt as a percentage of capitalization was 37%,
37% and 36% in 1996, 1995 and 1994, respectively. The Company also has entered
into long-term lease arrangements and other long-term contracts for sales and
purchases that are not reflected on its balance sheet. See Item 8, "Financial
Statements and Supplementary Data - Note 3 to the Consolidated Financial
Statements" for additional information.
Capital expenditures during the prior three years were as follows:
Utility Nonutility Total
Thousands of Dollars
1994 $150,903 $ 56,407 $207,310
1995 163,238 67,849 231,087
1996 107,085 51,992 159,077
The following table sets forth the Company's estimated capital
expenditures for the years 1997-2001:
Utility Nonutility Total
Thousands of Dollars
1997 $ 95,000 $129,000(a) $224,000
1998 110,000 99,000 209,000
1999 80,000 78,000 158,000
2000 82,000 70,000 152,000
2001 102,000 86,000 188,000
(a) On February 28, 1997, the Company committed to purchase Vessels Energy's
oil and natural gas assets in Colorado's Denver-Julesburg Basin for
approximately $85,000,000. To the extent that 1997 capital expenditures
are increased, they will be financed internally by oil and natural gas
operations.
The majority of the Utility's capital expenditures during the next five
years are expected to be spent on environmental mitigation, relicensing and
rehabilitation of hydroelectric projects, refurbishing electric and natural
gas transmission lines and extending and maintaining electric and natural gas
distribution lines. The majority of the Nonutility's capital expenditures
during the next five years are expected to be spent on replacements, heavy
equipment purchases, expansion and development of oil and natural gas
properties and the expansion of the fiber optic network.
In addition, $238,000,000 of long-term debt will mature during the years
1997-2001. See Item 8 "Financial Statements and Supplementary Data - Note 8 to
the Consolidated Financial Statements" for details on maturities of long-term
debt.
For the years 1997-2001, the Company estimates that, by business unit,
internally-generated funds will average 98% of its utility construction program
and 98% 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.
Dividends paid on common and preferred stock were $95,284,000 in 1996,
$93,600,000 in 1995, and $92,009,000 in 1994. During 1996, 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.
The Company has Revolving Credit and Term Loan Agreements in the amount
of $135,000,000. 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 8 and 9 to the Consolidated Financial Statements
for further information."
The Company submitted its latest depreciation study as part of its rate
request filed with the PSC on September 21, 1995. The PSC approved and included
in rates the settlement of the depreciation study, effective July 1, 1996. The
provision for utility depreciation changed from approximately 2.7% of the
depreciable utility plant to approximately 3.0%, resulting in an increase in
annual depreciation expense of approximately $5,900,000.
In November 1996, the Company sold to the public, through a subsidiary
trust, Montana Power Capital I, $65,000,000 of 8.45% Cumulative Quarterly
Income Preferred Securities, Series A maturing on December 31, 2036. The
proceeds from the sale were used to purchase from the Company a like amount of
its Subordinated Debentures. Approximately $31,000,000 of the proceeds from the
purchase was used to redeem in December 1996 all 1,200,000 outstanding shares
of the Company's Preferred Stock, $2.15 Series, at $25.25 per share, plus
accumulated dividends. The balance of the proceeds was used for general
corporate purposes including the repurchase and retirement of 139,200 shares of
the $6.875 Series Preferred Stock. See Item 8, "Financial Statements and
Supplementary Data - Note 7 to the Consolidated Financial Statements" for
further information.
In December 1996, the Company received PSC approval to offer from time
to time up to $150,000,000 of its Unsecured Medium-Term Notes, Series B on
terms to be determined at the time of the sale. In December 1996, the Company
sold an aggregate of $55,000,000 of Unsecured Medium-Term Notes. The amounts,
interest rates and due dates are: $15,000,000 7.07% series due 2006,
$5,000,000 7.96% series due 2026 and $35,000,000 7.875% series due 2026. The
net proceeds received by the Company from the sale of these notes were used
for general corporate purposes, including the repayment of long-term and
short-term borrowings.
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 will not preclude it from issuing sufficient First
Mortgage Bonds to meet its bonded debt requirements during the years 1997-2001.
There are no restrictions upon issuance of short-term debt or preferred stock
in the Company's Restated Articles of Incorporation, its Mortgage and Deed of
Trust or its Sinking Fund Debenture Agreement.
SEC RATIO OF EARNINGS TO FIXED CHARGES:
For the twelve months ended December 31, 1996, the Company's ratio of
earnings to fixed charges was 3.21 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.
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.
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 $525,000 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 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 has determined that
the Colstrip Units can meet the Phase I nitrogen oxide standards by January 1,
1997, it exercised this option for the Colstrip plants. The Company did not
exercise this option for its Corette Plant because, due to improvements in the
plant's emissions which will not be completed until late in 1997, the level of
nitrogen oxide emissions at the plant could not be determined before the early
election deadline.
The costs associated with any modifications that ultimately may be
required to comply with Phase II nitrogen oxide standards have not been
determined because they have only recently been promulgated.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA
Page
Management's Responsibility for Financial Statements 50
Report of Independent Accountants 51
Consolidated Financial Statements:
Consolidated Statements of Income for the Years Ended
December 31, 1996, 1995 and 1994 52
Consolidated Balance Sheets as of December 31, 1996 and 1995 53-54
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1996, 1995 and 1994 55
Consolidated Statements of Common Shareholders' Equity for the
Years Ended December 31, 1996, 1995 and 1994 56
Notes to Consolidated Financial Statements 57-82
Supplementary Data (Unaudited)
Financial Statement Schedules for the Years Ended December 31,
1996, 1995 and 1994 83-91
Schedule II - Valuation and Qualifying Accounts and Reserves 96
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 public accountants, also
considered the systems in connection with its audit. Management has considered
the internal auditors' and Price Waterhouse LLP's recommendations concerning
the systems and has taken cost-effective actions to respond appropriately to
these recommendations.
The Board of Directors, acting through an Audit Committee composed
entirely of directors who are not employees of the Company, is responsible for
determining that management fulfills its responsibilities in the preparation of
the financial statements. The Audit Committee recommends, and the Board of
Directors appoints, the independent public accountants. The independent
accountants and internal auditors are assured of full and free access to the
Audit Committee and meet with it to discuss their audit work, the Company's
internal controls, financial reporting and other matters. The Committee is
also responsible for determining that there is adherence to the Company's Code
of Business Conduct (Code). The Code addresses, among other things, potential
conflicts of interests and compliance with laws, including those relating to
financial disclosure and the confidentiality of proprietary information.
The financial statements have been examined by Price Waterhouse LLP,
which is responsible for conducting its examination in accordance with
generally accepted auditing standards.
Daniel T. Berube J. P. Pederson
Chairman of the Board and Vice President and
Chief Executive Officer Chief Financial and Information
Officer
Report of Independent Accountants
February 6, 1997, except as to paragraphs 3 and 5 of Note 2, which are as of
February 21, 1997
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, 1996
and 1995 and the results of their operations and of their cash flows for each
of the three years in the period ended December 31, 1996 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 12 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
</TABLE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENT OF INCOME
The Montana Power Company and Subsidiaries
Year Ended December 31
1996 1995 1994
Thousands of Dollars
<S> <C> <C> <C>
REVENUES $ 973,208 $ 953,224 $1,005,970
EXPENSES:
Operations 383,789 420,472 436,610
Maintenance 65,390 68,286 75,357
Selling, general and administrative 111,144 101,872 106,989
Taxes other than income taxes 87,903 89,858 99,200
Depreciation, depletion and amortization 88,744 86,976 86,711
Writedowns of long-lived assets 74,297
736,970 841,761 804,867
INCOME FROM OPERATIONS 236,238 111,463 201,103
INTEREST EXPENSE AND OTHER INCOME:
Interest 48,770 43,656 42,817
Other (income) deductions - net (3,893) (10,704) (10,532)
44,877 32,952 32,285
INCOME TAXES 71,975 21,574 55,226
NET INCOME 119,386 56,937 113,592
DIVIDENDS ON PREFERRED STOCK 8,358 7,227 7,227
NET INCOME AVAILABLE FOR COMMON STOCK $ 111,028 $ 49,710 $ 106,365
AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING (000) 54,634 54,121 53,125
NET INCOME PER SHARE OF COMMON STOCK $ 2.03 $ 0.92 $ 2.00
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
1996 1995
Thousands of Dollars
<S> <C> <C>
PLANT AND PROPERTY IN SERVICE:
Utility plant $2,281,395 $2,204,386
Less - accumulated depreciation and depletion 705,119 663,216
1,576,276 1,541,170
Nonutility property 666,679 633,079
Less - accumulated depreciation and depletion 256,489 252,612
410,190 380,467
1,986,466 1,921,637
MISCELLANEOUS INVESTMENTS (at cost):
Independent power investments 53,035 57,013
Reclamation fund 43,001
Other 39,531 38,645
135,567 95,658
CURRENT ASSETS:
Cash and temporary cash investments 32,404 15,541
Accounts receivable 142,347 152,386
Materials and supplies (principally at average cost) 39,322 42,194
Prepayments and other assets 46,408 46,172
Deferred income taxes 11,095 15,899
271,576 272,192
DEFERRED CHARGES:
Advanced coal royalties 19,298 20,175
Regulatory assets related to income taxes 149,150 148,350
Regulatory assets - other 66,688 68,637
Other deferred charges 69,470 59,442
304,606 296,604
$ 2,698,215 $ 2,586,091
The accompanying notes are an integral part of these statements.
LIABILITIES
December 31
1996 1995
Thousands of Dollars
CAPITALIZATION:
Common shareholders' equity:
Common stock (120,000,000 shares without par
value authorized; 54,630,994 and 54,614,481
shares issued) $ 691,853 $ 691,043
Retained earnings and other shareholders' equity 307,804 285,000
Unallocated stock held by trustee for retirement
savings plan (28,360) (30,565)
971,297 945,478
Preferred stock 57,654 101,416
Company obligated mandatorily redeemable preferred
securities of subsidiary trust which holds solely
company junior subordinated debentures 65,000
Long-term debt 633,339 616,574
1,727,290 1,663,468
CURRENT LIABILITIES:
Short-term borrowing 104,702 96,348
Long-term debt-portion due within one year 69,268 24,804
Dividends payable 22,707 23,668
Income taxes 11,083 9,937
Other taxes 41,667 43,302
Accounts payable 62,218 63,920
Interest accrued 11,909 12,341
Other current liabilities 41,155 63,488
364,709 337,808
DEFERRED CREDITS:
Deferred income taxes 332,861 320,736
Investment tax credit 44,467 47,001
Accrued mining reclamation costs 129,878 122,008
Other deferred credits 99,010 95,070
606,216 584,815
CONTINGENCIES AND COMMITMENTS (Notes 2 and 3)
$2,698,215 $2,586,091
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
1996 1995 1994
Thousands of Dollars
<S> <C> <C> <C>
NET CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 119,386 $ 56,937 $ 113,592
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation, depletion and amortization 88,744 86,976 86,711
Writedowns of long-lived assets 74,297
Deferred income taxes 15,430 (11,819) 4,792
Noncash earnings from unconsolidated
independent power investments (11,505) (2,314) (169)
Reclamation expensed and paid - net 7,870 7,411 8,218
Other - net 25,132 20,105 27,390
Changes in current assets and liabilities:
Accounts receivable 10,039 7,589 (1,622)
Materials and supplies 2,872 5,743 (5,209)
Accounts payable (1,702) 13,132 (5,007)
Other assets and liabilities (38,973) 10,833 (24,810)
Net cash provided by operating activities 217,293 268,890 203,886
NET CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (159,077) (231,087) (207,310)
Reclamation funding (43,001)
Sales of property 11,171 13,987 27,729
Additional investments (2,255) (2,640) 1,143
Net cash used for investing activities (193,162) (219,740) (178,438)
NET CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends paid (95,284) (93,600) (92,009)
Sales of common stock 798 23,465 24,380
Redemption of preferred stock (46,790)
Issuance of long-term debt 82,890 50,758 52,094
Retirement of long-term debt (22,236) (18,155) (45,078)
Issuance of mandatorily redeemable preferred
securities 65,000
Net change in short-term borrowing 8,354 (17,641) 45,125
Net cash used for financing activities (7,268) (55,173) (15,488)
CHANGE IN CASH FLOWS 16,863 (6,023) 9,960
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR 15,541 21,564 11,604
CASH AND CASH EQUIVALENTS, END OF YEAR $ 32,404 $ 15,541 $ 21,564
SUPPLEMENTAL DISCLOSURES OF CASH FLOW:
Cash paid during the year for:
Income taxes $ 55,399 $ 32,666 $ 45,875
Interest 49,962 46,141 45,990
The accompanying notes are an integral part of these statements.
</TABLE
</TABLE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENT OF COMMON SHAREHOLDERS' EQUITY
The Montana Power Company and Subsidiaries
Year Ended December 31
1996 1995 1994
Thousands of Dollars
<S> <C> <C> <C>
COMMON STOCK:
Balance at beginning of year $ 691,043 $ 667,344 $ 642,926
Issuances (16,513; 1,035,744;
and 1,079,841 shares) 810 23,699 24,418
Balance at end of year 691,853 691,043 667,344
RETAINED EARNINGS AND OTHER SHAREHOLDERS'
EQUITY:
Balance at beginning of year 285,000 320,756 302,725
Net income 119,386 56,937 113,592
Dividends on common stock ($1.60;
$1.60; and $1.60 per share) (87,432) (86,791) (85,193)
Dividends on preferred stock (7,705) (7,227) (7,227)
Other (1,445) 1,325 (3,141)
Balance at end of year 307,804 285,000 320,756
UNALLOCATED STOCK HELD BY TRUSTEE FOR
RETIREMENT SAVINGS:
Balance at beginning of year (30,565) (32,580) (34,419)
Distributions 2,205 2,015 1,839
Balance at end of year (28,360) (30,565) (32,580)
TOTAL COMMON SHAREHOLDERS' EQUITY AT
END OF YEAR $ 971,297 $ 945,478 $ 955,520
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 FERC and was an average of 7.2% for 1996, 8.1% for 1995 and
7.9% for 1994. 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
1996 1995
Thousands of Dollars
Utility plant:
Electric:
Production $ 748,044 $ 748,276
Transmission 352,993 335,338
Distribution 487,937 456,312
Other 175,728 172,371
Natural Gas:
Production and storage 194,531 197,005
Transmission 146,072 128,700
Distribution 128,877 120,152
Other 47,213 46,232
Total Utility 2,281,395 2,204,386
Nonutility plant:
Coal 255,788 266,218
Oil and natural gas 274,880 261,700
Technology 48,069 20,164
Electric production 75,298 72,179
Other 12,644 12,818
Total Nonutility 666,679 633,079
Total Plant $2,948,074 $2,837,46
Included in the plant classifications are Utility plant under
construction in the amounts of $52,125,000 and $57,095,000 for 1996 and 1995,
respectively and Nonutility plant under construction in the amounts of
$39,252,000 and $15,887,000 for 1996 and 1995, respectively.
Provisions for depreciation and depletion are recorded at amounts
substantially equivalent to calculations made on straight-line and
unit-of-production methods by application of various rates based on useful
lives of properties determined from engineering studies. The provisions for
Utility depreciation and depletion approximated 3.0% for 1996 and 2.7% for 1995
and 1994 of the depreciable and depletable Utility plant at the beginning of
the year.
The Company's Nonutility oil and natural gas operations uses 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, 1996, 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 $ 183,938 $ 285,388 $ 51,170
Plant under construction 150 168 4
Accumulated depreciation 90,791 99,191 12,875
*This is an approximate ownership percentage based on capacity rights
on the various segments of the transmission system.
The Company also owns $41,825,000 and $33,237,000 of the Nonutility
Colstrip Unit 4 share of common production plant and transmission plant that
had related accumulated depreciation of $14,854,000 and $6,999,000,
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 the 1996 coal arbitration decision, the Company was
required to establish a reclamation fund, representing restricted cash equal to
a portion of their accumulated reclamation liability plus interest. The fund
will increase as reclamation expenses are collected from customers and all
proceeds will be invested until reclamation is performed. 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.
1996 1995
Assets Liabilities Assets Liabilities
Thousands of Dollars
Income taxes $ 146,737 $ 147,388
Conservation programs 41,372 40,640
Other 48,074 $ 12,207 33,298 $ 12,623
Subtotal 236,183 12,207 221,326 12,623
Less:
Current portions 20,345 3,195 4,339 3,675
Total $ 215,838 $ 9,012 $ 216,987 $ 8,948
Income taxes reflect the impacts of temporary difference that will be
recovered in rates in future periods. 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. Items included in Other are
either being amortized currently or are subject to regulatory confirmation in
future ratemaking 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 was 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
addressed in the transition process or they would be eliminated from the
balance sheet and included in income in the period when the discontinuation
occurred.
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, 1996 and 1995 were approximately $3,600,000
and $4,200,000, 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:
Net income per share of common stock is computed for each year based upon
the weighted average number of common shares outstanding.
Derivative financial instruments:
To manage nonutility price risk, the Company uses a variety of derivative
financial instruments, including oil and natural gas swap, collar and cap
agreements, to hedge revenue from anticipated production and sales of oil and
natural gas. Under swap agreements, the Company receives or makes payments
based on the differential between a specified price and the market price of oil
or natural gas when the hedged transaction is settled. Under collar
agreements, the Company makes or receives monthly payments 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 based on the differential between the actual price of
oil or natural gas and the cap established in the agreement. At December 31,
1996, the Company had cap agreements on approximately 164,500 barrels of crude
oil; 48% of its expected production from proved, developed and producing oil
reserves through February 1997. The Company had swap and cap agreements on
approximately 2.0 Bcf of Nonutility natural gas; 13% of its expected production
from proved, developed and producing Nonutility reserves through October 1997.
In addition, the Company had swap and collar agreements to hedge approximately
3.8 Bcf of Nonutility natural gas; 27% of its expected delivery obligations
under long-term sales contracts through March 1998. At December 31, 1996, the
Company had no material gains or losses from 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, 1996, the Company believes it would not
experience any materially adverse impacts from the risks inherent in these
instruments.
Fair value of financial instruments:
1996 1995
Carrying Fair Carrying Fair
Amount Value Amount Value
Thousands of Dollars
Assets:
Investments in independent
power projects (cost basis
only) $ 6,090 $ 10,300 $ 7,868 $ 2,169
Reclamation fund 43,001 43,001
Other significant investments 35,449 39,837 33,558 34,575
Liabilities:
Mandatorily redeemable preferred
securities $ 65,000 $ 67,600
Long-term debt(including due
within one year) 702,607 717,504 $641,378 $672,699
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.
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.
NOTE 2 - Contingencies:
In 1990, pursuant to a Federal Energy Regulatory Commission (FERC)
license obligation, the Company proposed a plan to protect fish, wildlife and
habitat affected by the operation of the 180 megawatt Kerr Project (Project),
which would cost the Company $15,600,000 initially and, thereafter, $965,000
annually. Management's estimate of the initial cost has been capitalized to
plant. The United States Department of Interior (Department) has proposed an
alternative to the plan which the Company estimates would cost approximately
$35,000,000 initially and, thereafter, $1,300,000 annually. An Environmental
Impact Statement prepared by the FERC staff concludes that the Department's
alternative is preferable, from an environmental perspective, to the Company's
plan. In addition to requiring expenditures for environmental mitigation
which are not included in the Company's plan, the alternative proposed by the
Department would change the operation of the Project from a peaking to a
baseload operation. This matter is pending FERC's decision, which is expected
in 1997. The Company can not predict what FERC's decision might be.
In November 1992, the Company applied to FERC to relicense nine Madison
and Missouri River hydroelectric projects, with generating capacity of 292
megawatts. The net present value of relicensing and environmental mitigation
is estimated to be approximately $158,000,000. The FERC staff is expected to
issue a draft environmental impact statement in mid-1997. The Company expects
to receive a license order in late 1998 or early 1999. The majority of the
cost is capital for physical improvements, which is not expected to be spent
before 2006.
In March 1995, the Company sued Puget Sound Power & Light Company
(Puget) in the United States District Court for the District of Montana
seeking a determination that the Company was in compliance with an agreement
to sell Puget 94 megawatts of power annually to the year 2010. This action
arose out of an allegation by Puget that the Company breached the agreement by
failing to provide firm contractual rights to a transmission path for the
power, thereby entitling Puget to terminate the agreement. On February 21,
1997 the Company and Puget settled this litigation. The litigation has been
dismissed with prejudice. In the settlement, the Company agreed to reduce
prices for power purchased under the terms of the agreement and to amend other
provisions to grant Puget access to an additional 3 MW of capacity and to
eliminate restrictions limiting Puget's right to take energy to a 75% capacity
factor. The Company and Puget agreed that the General Transmission Agreement
between Puget and the Bonneville Power Administration provides firm
contractual rights to transmission paths sufficient to fulfill the Company's
obligations under the Agreement through the end of the contract. In addition,
Western Energy Company (Western), a subsidiary of the Company, agreed to
reduce the price of coal to Puget for Colstrip Units 1,2,3 and 4. The Company
estimates the settlement will reduce future consolidated revenues between
approximately $11,000,000 and $13,000,000 per year. This settlement had no
effect on the Company's consolidated financial position or consolidated
results of operation for the year ended December 31, 1996.
In 1994, the Company entered into an agreement to purchase 98 megawatts
of capacity during the winter months from Basin Electric Power Cooperative
(Basin), delivery of which was to begin in November 1996. The purchase
obligation under the agreement was from November 1, 1996 to April 30, 2012.
Under the terms of the agreement, the Company would have purchased seasonal
power between November and April of each year at a cost estimated to be
approximately $11,200,000 in 1997 and escalating annually, pursuant to the
contract. On October 31, 1996, the Company notified Basin of the Company's
rescission of the agreement as a consequence of Basin's refusal to provide
electricity at the delivery points the Company had requested under the terms
of the agreement without imposing unacceptable precedent conditions. On
November 5, 1996, Basin sued the Company in the Federal District Court for the
Southwestern District of North Dakota seeking specific performance, a stay of
the litigation and an order compelling the Company to arbitrate the dispute.
On January 6, 1997, the Company answered Basin's complaint stating numerous
counterclaims. The outcome of this litigation can not be predicted at this
time. As of December 31, 1996, the Company did not pay approximately
$2,000,000 that otherwise would have been payable under the terms of the
agreement.
Western is seeking to resolve a Coal Supply Agreement (CSA) dispute with
the non-operating owners (NOOs) of Colstrip Units 3 and 4, other than Puget.
In the settlement of the litigation regarding the power sales agreement
described above, Puget withdrew from this dispute. The doubling of the
Consumers Price Index, which occurred in 1996, triggered a right to assert a
Gross Inequity claim. The NOOs claim that the combination of electric utility
industry restructuring and economic and other changes, which have occurred
since the CSA was entered into, has created a Gross Inequity. Thus, according
to the NOOs, a reduction of the coal price is necessary to remedy the Gross
Inequity and assure the competitive posture of Colstrip Units 3 and 4. Western
disputes that a Gross Inequity has occurred and is discussing this matter with
the NOOs. The outcome, however, can not be predicted at this time.
Houston Lighting & Power (HL&P), the purchaser of lignite produced by
Northwestern Resources Company (Northwestern), a subsidiary of the Company,
has filed litigation in the District Court of the 157th Judicial District,
Harris County, Texas, seeking a declaratory judgment that changed conditions
require a renegotiation of management and dedication fees paid to Northwestern
under the terms of the Lignite Sales Agreement (LSA) between it and
Northwestern. The LSA governs the delivery of approximately 8,000,000 tons
per year and is effective until July 29, 2015. Northwestern realizes
approximately $25,000,000 per year from the management and dedication fees
under the terms of the agreement. HL&P alleges Northwestern failed to
renegotiate these fees in good faith as HL&P alleges the agreement requires.
As its remedy, HL&P seeks to terminate the LSA or, alternatively, asks the
court to set reasonable fees. HL&P appears to be seeking an approximate 60%
reduction in these fees and alleges that the reduction should be retroactive
to September 1, 1995. Additionally, HL&P is seeking a declaration that it may
substitute other fuels for lignite without violating the LSA. If HL&P does
not have this right, it further seeks a declaration that the absence of this
right constitutes a gross inequity which entitles HL&P to have the court
reform the LSA to provide the right to substitute fuels. Finally, HL&P
alleges that the parties were mutually mistaken regarding the quantity and the
quality of lignite dedicated to the LSA and, consequently, the original
bargain has been so altered that either no agreement was made or the agreement
should be reformed.
Northwestern disputes HL&P's claims and does not believe the Texas
district court has jurisdiction to make the declarations HL&P is seeking. The
court will order mediation. If settlement is not achieved, trial is expected
in 1997. The outcome of mediation and litigation are uncertain.
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:
The Company has long-term purchase contracts with certain 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 17 QF contracts,
with expiration terms ranging from 1997 through 2031. Three contracts account
for 97% of the 1,179 MWs of capacity provided by these facilities. The
purchased gas contracts provide for take-or-pay payments. The Nonutility oil
and natural gas operations have various natural gas transportation contracts
with terms that expire beginning in 1998.
Total payments under these contracts for the prior three years were as
follows:
Thousands of Dollars
Utility Nonutility Total
Electric Natural Gas
1994 $ 19,242 $ 11,072 $ 3,298 $ 33,612
1995 21,830 9,873 3,020 34,723
1996 30,751 8,100 3,334 42,185
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
1997 $ 7,292 $ 6,853 $ 3,000 $ 17,145
1998 7,085 3,321 3,785 14,191
1999 6,700 2,816 3,486 13,002
2000 6,352 2,457 3,227 12,036
2001 6,004 1,915 1,819 9,738
Remainder 83,542 2,718 10,582 96,842
$116,975 $ 20,080 $ 25,899 $162,954
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, 1996, the remaining payments under this agreement were $8,600,000.
Under current mine plans, these payments should be recovered through lignite
sales.
The Nonutility oil and natural gas operations have agreed to supply
approximately 110 Bcf of natural gas to three co-generation facilities through
mid-2011. 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 Company has also entered into various contracts for the completion of
its fiber optic network expansion. The Company is committed to spend
approximately $21,000,000 in 1997.
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. 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
$55,500,000, $55,958,000 and $56,928,000 for 1996, 1995 and 1994, respectively.
NOTE 4 - Income tax expense:
Income before income taxes was as follows:
1996 1995 1994
Thousands of Dollars
United States $ 181,393 $ 75,458 $ 155,978
Canada 7,706 111 9,144
Other countries 2,262 2,942 3,696
$ 191,361 $ 78,511 $ 168,818
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:
1996 1995 1994
Thousands of Dollars
Computed "expected" income tax expense $ 66,976 $ 27,479 $ 59,086
Adjustments for tax effects of:
Statutory depletion (2,317) (6,508) (4,983)
Tax credits (5,286) (5,331) (5,130)
State income tax, net 5,772 3,327 4,772
Reversal of utility book/tax
depreciation 4,054 2,552 3,236
Other 2,776 55 (1,755)
Actual income tax expense $ 71,975 $ 21,574 $ 55,226
Income tax expense as shown in the Consolidated Statement of Income
consists of the following components:
1996 1995 1994
Thousands of Dollars
Current:
United States $ 44,304 $ 25,119 $ 38,519
Canada 3,309 1,510 3,093
Other countries 445 548 1,080
State 8,487 6,216 7,742
56,545 33,393 50,434
Deferred:
United States 15,590 (8,648) 4,426
Canada 135 (1,124) 850
State (295) (2,047) (484)
15,430 (11,819) 4,792
$ 71,975 $ 21,574 $ 55,226
Deferred tax liabilities (assets) are comprised of the following:
December 31
1996 1995
Thousands of Dollars
Plant related $ 388,973 $ 377,741
Investment in Nonutility generation projects 26,785 23,896
Other 33,509 25,724
Gross deferred tax liabilities 449,267 427,361
Coal reclamation (45,252) (42,438)
Amortization of gain on sale/leaseback (14,898) (15,962)
Investment tax credit amortization (28,895) (30,542)
Other (38,455) (33,582)
Gross deferred tax assets (127,500) (122,524)
Net deferred tax liabilities 321,767 304,837
Plus current deferred tax assets-net 11,094 15,899
Total noncurrent deferred tax liabilities $ 332,861 $ 320,736
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 $ 12,125
Regulatory assets related to income taxes (800)
Current deferred tax assets-net 4,805
Amortization of investment tax credits (2,534)
Other 1,834
Deferred tax expense $ 15,430
NOTE 5 - Common stock:
The Company has a Shareholder Protection Rights Plan which provides one
preferred share purchase right (Right) on each outstanding common share of the
Company. Each Right entitles the registered holder, upon the occurrence of
certain events, to purchase from the Company one one-hundredth of a share of
Participating Preferred Shares, A Series, without par value. If it should
become exercisable, each Right would have economic terms similar to one share
of common stock of the Company. The Rights trade with the underlying shares
and will, except under certain circumstances described in the Plan, expire on
June 6, 1999, unless 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, 1996, 866,363 shares had been allocated to the
participants' accounts. Expense for the Plan is recognized using the Shares
Allocated Method, and was $6,046,000, $5,610,000 and $5,683,000 for 1996, 1995
and 1994, respectively.
Under the Long-Term Incentive Plan, options have been issued to Company
employees. Options issued to Utility employees are not reflected in balance
sheet accounts until exercised, at which time (i) authorized, but unissued
shares are issued to the employee, (ii) the capital stock account is credited
with the proceeds and (iii) no charges or credits to income are made. Options
issued to Nonutility employees are not reflected in balance sheet accounts.
Rather, upon exercise, outstanding shares are purchased at current market
prices and compensation expense is charged with the excess of the market price
over the option price.
Option activity is summarized below:
1996 1995 1994
Options outstanding 569,982 480,986 412,310
(Price range) ($17.25 - $26.50) ($17.25 - $26.50) ($14.25 - $26.50)
Options granted 164,400 116,730 117,100
(Price range) ($21.625) ($21.125 - $22.50) ($22.625 - $25.625)
Options exercised 11,578 19,034 43,884
(Price range) ($17.25 - $22.125) ($17.25 - $26.50) ($14.25 - $26.50)
Options canceled 28,000 8,700 4,540
(Price range) ($22.125 - $22.625) ($22.125 - $22.625) ($14.25 - $26.50)
There were 421,051 options exercisable at December 31, 1996.
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 Balance Sheet and Income
Statement, respectively. At December 31, 1996 there were 29,564 shares of
restricted stock remaining.
The Financial Accounting Standards Board has issued Statement of
Financial Accounting Standards No. 123 "Accounting for Stock-Based
Compensation" (SFAS No. 123), which is effective for years beginning after
December 15, 1995. SFAS No. 123 encourages, but does not require, companies to
recognize compensation expense for grants of common stock, stock options, and
other equity instruments to employees based upon the fair value of the
instruments when issued. The Company applies APB Opinion 25 and related
Interpretations in accounting for its plan. Accordingly, no compensation cost
has been recognized for the options granted under the Long-Term Incentive Plan.
Had the Company used the fair value method in accordance with SFAS No. 123,
compensation expense would have increased $108,000 and $37,000 for 1996 and
1995, respectively.
NOTE 6 - Preferred stock:
The number of authorized shares of preferred stock is 5,000,000. No
dividends may be declared or paid on common stock while cumulative dividends
have not either been declared and set apart or paid on any of the preferred
stock.
Preferred stock is in four series as detailed in the following table:
Stated and
Liquidation Shares Issued and Outstanding Thousands of Dollars
Series Price* 1996 1995 1994 1996 1995 1994
$6.875 $100 360,800 500,000 500,000 $ 36,080 $ 50,000 $ 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 1,200,000 30,000 30,000
580,389 1,919,589 1,919,589 $ 58,064 $101,984 $101,984
* Plus accumulated dividends.
The preferred stock is redeemable at the option of the Company upon the
written consent or affirmative vote of the holders of a majority of the common
shares on thirty days notice at $110 per share for the $6.00 series and
$103 per share for the $4.20 series, plus accumulated dividends. The $6.875
series is redeemable in whole or in part, at anytime on or after November 1,
2003 for a price beginning at $103.438 per share with annual decrements through
October 2013, after which the redemption price is $100 per share.
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 has been included in preferred dividends in
the Consolidated Income Statement.
NOTE 7 - 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, 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 8 - Long-term debt:
The Company's Mortgage and Deed of Trust imposes a first mortgage lien on
all physical properties owned, exclusive of subsidiary company assets, and
certain property and assets specifically excepted. The obligations
collateralized are First Mortgage Bonds, including those First Mortgage Bonds
designated as Secured Medium-Term Notes and those securing Pollution Control
Revenue Bonds.
Long-term debt consists of the following:
December 31
1996 1995
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 1997-2025 5.75%-8.11% 128,000 128,000
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 16,000 16,500
ESOP Notes Payable - 9.2%, due 2004 27,587 29,861
Unsecured Medium-Term Notes:
Series A - maturing 1997-2022 8.68%-8.9% 29,500 38,250
Series B - maturing 2006-2026 7.07%-7.96% 55,000
Revolving Credit Agreements 35,000 10,000
Other 10,536 17,696
Unamortized Discount and Premium (4,221) (4,134)
702,607 641,378
Less: Portion due within one year 69,268 24,804
$ 633,339 $ 616,574
Revolving Credit Agreements:
The Company has two Revolving Credit Agreements that allow it to borrow
up to a combined total of $135,000,000, of which $100,000,000 was unused at
December 31, 1996. One agreement requires that borrowings outstanding at
October 27, 1998 must be repaid at that time. The other agreement states that
borrowings outstanding at September 30, 1997 must be repaid at that time. Fixed
or variable interest rate options are available under the facilities with
commitment fees on the unused portions.
The sinking fund requirements and maturities for the five years ending
December 31, 2001, on the long-term debt outstanding at December 31, 1996,
amount to: $69,000,000 in 1997; $45,000,000 in 1998; $61,000,000 in 1999;
$34,000,000 in 2000 and $29,000,000 in 2001.
NOTE 9 - 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, 1996, the Company had lines of credit consisting of
$100,000,000 committed and $95,400,000 uncommitted. There is a commitment fee
on the unused portion of some of these facilities which is not significant. The
Company has the ability to issue up to $175,000,000 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
1996 1995
Amount Rate Amount Rate
Thousands of Dollars
Notes payable to banks $ 70,500 7.17% $ 78,400 6.18%
Commercial paper 34,202 5.79% 17,948 6.33%
$104,702 $ 96,348
NOTE 10 - 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 1996, 1995 and 1994, pension costs funded were less than SFAS No. 87
pension expense by $188,000, $1,501,000 and $2,770,000, respectively and the
difference was recorded as a deferred charge which will be recovered in rates.
At December 31, 1996, the regulatory asset was $3,097,000.
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
1996 1995 1994
Thousands of Dollars
Service cost on benefits earned $ 7,991 $ 6,165 $ 8,442
Interest cost on projected benefit
obligation 15,861 14,524 13,430
Actual return on plan assets (30,331) (13,009) (13,051)
Net amortization and deferral 15,270 1,719 3,788
Net pension and benefit expense $ 8,791 $ 9,399 $ 12,609
<TABLE>
<CAPTION>
The funded status of the pension and benefit plans is as follows:
December 31
1996 1995
Thousands of Dollars
<S> <C> <C>
Actuarial present value of benefit obligation:
Vested $ 152,115 $ 149,122
Nonvested 19,029 17,768
Accumulated benefit obligation 171,144 166,890
Effect of projected future compensation levels 51,125 53,340
Projected benefit obligation 222,269 220,230
Plan assets at fair value 223,686 196,427
Plan assets less than projected
benefit obligation 1,417 (23,803)
Unrecognized net gain (34,793) (7,082)
Unrecognized prior service cost 10,088 10,466
Unrecognized initial obligation 2,491 2,874
Accrued benefits expense $ (20,797) $ (17,545)
</TABLE>
<TABLE>
<CAPTION>
The following assumptions were used in the determination of actuarial
present values of the projected benefit obligations:
December 31
1996 1995
<S> <C> <C>
Assumed discount rates 7.50% 7.00%
Long-term rate of average compensation increase 4.50%-5.00% 4.00%-4.90%
Long-term rate on plan assets 8.50% 8.50%
</TABLE>
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, 1996, 1995
and 1994, portions of which have been deferred or capitalized, includes the
following components:
December 31
1996 1995 1994
Thousands of Dollars
Service cost on benefits earned $ 1,074 $ 1,221 $ 1,455
Interest cost on projected benefit 2,092 2,482 2,323
Actual return on plan assets (876) (219) (38)
Net amortizations 1,577 1,299 1,535
Total postretirement benefit cost $ 3,867 $ 4,783 $ 5,275
The funded status of the postretirement benefit plans other than pensions
is as follows:
December 31
1996 1995
Thousands of Dollars
Accumulated benefit obligation:
Fully eligible active employees $ 3,267 $ 1,939
Other active employees 16,267 22,856
Retirees 10,330 11,909
Accumulated benefit obligation 29,864 36,704
Plan assets at fair value 5,740 3,714
Plan assets less than projected
benefit obligation (24,124) (32,990)
Unrecognized net transition obligation 20,012 24,728
Unrecognized net gain (8,064) 542
Accrued benefits expense $(12,176) $ (7,720)
The assumed 1996 health care cost trend rates used to measure the
expected cost of benefits covered by the plans are 8.25% and 9% for the Utility
and Nonutility operations, respectively. The trend rates decrease through 2004
to 5%. One Nonutility subsidiary's plan used a trend rate of 9% decreasing
through 2003 to an ultimate rate of 5% for post-65 benefits. The effect of a
1% increase in each future year's assumed health care cost trend rates
increases the service and interest cost from $3,200,000 to $3,500,000 and the
accumulated postretirement benefit obligation from $29,900,000 to $32,100,000.
At December 31, 1993, the unrecorded postemployment benefit liability for
regulated Utility operations was estimated to be $6,900,000. The amount was
recorded in 1994 as a deferred charge and will be expensed and included in
rates over the next ten years. The estimated December 31, 1993 postemployment
benefit liability of $1,300,000 for Nonutility operations was charged to income
in 1994. The Company is no longer self-insured for disability-related benefits
resulting from claims occurring after December 31, 1993. Therefore, SFAS
No. 112 will not apply to benefits after that date, except workman's
compensation claims which are accrued and recovered in rates.
NOTE 11 - Information on industry segments:
The Company and its subsidiaries conduct a number of diversified, but
related businesses. The Company's principal business is its Montana electric
and natural gas utility operation. This activity includes utility operations
involved in the generation, purchase, transmission and distribution of
electricity, and the production, purchase, transportation and distribution of
natural gas. The Company's nonutility businesses are involved principally in
the mining and sale of coal, exploration for, and the development, production,
processing and sale of oil and natural gas; the sale of telecommunication
equipment, internet, long distance and dedicated services; and independent
power activities that include the sales of power under long-term contracts, and
the development of and investment in nonutility power projects and other
energy-related businesses.
The Company's assets and operations are located principally in the United
States. The assets of the Company's Canadian operations were $77,266,000 ,
$77,282,000 and $79,337,000 at December 31, 1996, 1995 and 1994, respectively.
Substantially all of the natural gas produced by the Company's Canadian utility
operations has been sold to the Company's United States utility operations.
<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 48,479 12,149
Capital expenditures 74,930 31,060
Identifiable assets 1,526,197 421,955
<CAPTION>
NONUTILITY Independent
Oil and Power
Coal* Natural Gas Investments
<S> <C> <C> <C>
Sales to unaffiliated customers $ 166,678 $ 124,553 $ 75,322
Intersegment sales 31,448 272 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 $ 27,275 $ 1,185
Intersegment sales 443 782
Pre-tax operating income (loss) 2,590 (1,487)
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.
</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 42,506 10,793
Capital expenditures 127,917 35,091
Identifiable assets 1,503,619 410,267
<CAPTION>
NONUTILITY Independent
Oil and Power
Coal* Natural Gas Investments
<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 55,102 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.
</FN>
</TABLE>
<TABLE>
<CAPTION>
Operations Information:
Year Ended
December 31, 1994
Thousands of Dollars
UTILITY Electric Natural Gas
<S> <C> <C>
Sales to unaffiliated customers $ 427,686 $ 107,105
Intersegment sales 5,924 917
Pre-tax operating income 98,070 29,576
Depreciation, depletion and amortization 40,699 9,842
Capital expenditures 108,933 41,969
Identifiable assets 1,430,516 368,320
<CAPTION>
NONUTILITY Independent
Oil and Power
Coal* Natural Gas Investments
<S> <S> <C> <C>
Sales to unaffiliated customers $ 255,247 $ 97,994 $ 93,647
Intersegment sales 42,201 254 1,461
Pre-tax operating income 48,344 13,647 10,912
Earnings (loss) from unconsolidated
investments (2,740) 2,080
Depreciation, depletion and amortization 12,649 18,464 3,112
Capital expenditures 16,115 32,417 6,154
Identifiable assets 291,224 179,261 159,138
<CAPTION>
NONUTILITY (continued)
Tele-
communications Other
<S> <C> <C>
Sales to unaffiliated customers $ 20,655 $ 3,441
Intersegment sales 138 649
Pre-tax operating income (loss) 1,188 (41)
Earnings from unconsolidated
investments 68
Depreciation, depletion and amortization 762 1,183
Capital expenditures 449 43
Identifiable assets 14,319 19,450
<CAPTION>
CORPORATE
<S> <C>
Capital expenditures $ 1,231
Identifiable assets 50,469
<FN>
* Sales under one coal contract with Houston Light and Power Company amounted to
$101,845,000.
</FN>
</TABLE>
NOTE 12 - 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. which owned and
operated the Golden Eagle Mine in Colorado. In addition, the Nonutility coal
operations recorded impairment charges of approximately $8,600,000 before tax
for certain non-producing leaseholds and other investments and the Nonutility
oil operations recorded an impairment charge of $19,200,000 before tax.
SUPPLEMENTARY DATA
OIL AND NATURAL GAS PRODUCING ACTIVITIES
<TABLE>
<CAPTION>
For the years ended December 31, 1996, 1995 and 1994 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:
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>
<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>
<TABLE>
<CAPTION>
1994
U.S. CANADA STORAGE
<S> <C> <C> <C>
PROVED DEVELOPED AND UNDEVELOPED RESERVES:
UTILITY OPERATIONS:
Natural Gas (Mmcf):
Beginning Balance 80,070 98,871 56,318
Production (4,742) (3,350)
Additions 87 570 230
(Sales) and Purchases of Reserves in Place
Revisions - Other 5,147 480
Revisions - Price
Ending Balance 80,562 96,571 56,548
NONUTILITY OPERATIONS:
Natural Gas (Mmcf):
Beginning Balance 140,923 59,071
Production (9,444) (7,785)
Additions 4,683 13,830
(Sales) and Purchases of Reserves in Place 2,250 5,866
Revisions - Other 14,385 4,987
Revisions - Price 365 3,314
Ending Balance 153,162 79,283
Natural Gas
Liquids (Bbls):
Beginning Balance 3,682,700 1,508,100
Production (376,650) (172,600)
Additions 103,300 365,300
(Sales) and Purchases of Reserves in Place (116,298) 81,184
Revisions - Other (199,552) 217,216
Revisions - Price 16,800 300
Ending Balance 3,110,300 1,999,500
Oil (Bbls):
Beginning Balance 6,238,700 4,511,600
Production (440,040) (709,248)
Additions 77,800 1,497,400
(Sales) and Purchases of Reserves in Place 821,276 (215,042)
Revisions - Other (740,736) (135,310)
Revisions - Price 122,700 (14,400)
Ending Balance 6,079,700 4,935,000
<CAPTION>
1994
U.S. CANADA
PROVED DEVELOPED RESERVES:
<S> <C> <C>
UTILITY OPERATIONS:
Natural Gas (Mmcf):
Ending Balance 79,731 96,571
NONUTILITY OPERATIONS:
Natural Gas (Mmcf):
Ending Balance 89,305 65,454
Natural Gas Liquids (Bbls):
Ending Balance 2,588,700 1,634,200
Oil (Bbls):
Ending Balance 3,194,600 3,437,600
</TABLE
SUPPLEMENTARY DATA
Oil and Natural Gas Producing Activities (Cont.)
As determined by engineers, Utility natural gas reserves were revised
during 1996, 1995 and 1994 due to a change in projected performance or a change
in the Company's ownership interest in specific fields.
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 the 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.
In 1994, the Nonutility U.S. oil and natural gas reserves increased as a
result of the acquisition of oil interests in Kansas and the drilling of 25
development wells and six exploratory wells in Colorado, Montana, Oklahoma and
Wyoming. Natural gas liquid reserves decreased due to a lower liquid recovery
factor experienced at the Fort Lupton, Colorado gas processing plant. Higher
oil market prices contributed to an upward revision in U.S. reserves. The
Canadian companies participated in 21 development wells and seven exploratory
wells. Significant natural gas and natural gas liquid reserves were added as a
result of exploratory well discoveries in the Grand Prairie and Saddle Lake
areas of Alberta. A development well in the Caroline area in Alberta extended
the new pool discovery from 1993. Significant oil reserves were added at
Manyberries because of a new pool discovery and development drilling in 1994.
The following table presents information for 1996, 1995 and 1994 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>
<TABLE>
<CAPTION>
1996 1995 1994
U.S. Canada U.S. Canada U.S. Canada
Thousands of Dollars
<S> <C> <C> <C> <C> <C> <C>
UTILITY OPERATIONS
At December 31:
Capitalized costs relating
to natural gas producing
activities $ 87,363 $ 38,551 $ 89,520 $ 37,683 $ 95,713 $ 36,904
Accumulated depreciation,
depletion and valuation
allowances 46,881 20,102 50,377 19,812 48,913 19,386
Net capitalized costs $ 40,482 $ 18,449 $ 39,143 $ 17,871 $ 46,800 $ 17,518
For the year ended
December 31:
Costs incurred in natural
gas property acquisition,
exploration and
development activities:
Acquisition of
properties $ 474 $ 49 $ 48 $ 170 $ 414 $ 259
Exploration 54 191 70 198 358 231
Development 501 1,230 1,753 1,240 5,158 1,203
Costs reflected in results
of operations:
Production costs $ 4,773 $ 1,510 $ 5,710 $ 1,592 $ 4,795 $ 1,348
Exploration expenses 54 191 70 198 128 231
Development expenses 22 113 165 416 165 197
Depreciation, depletion
and valuation
provisions 2,667 711 2,716 586 2,607 487
</TABLE
</TABLE>
<TABLE>
<CAPTION>
The following table presents information for 1996, 1995 and 1994 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:
1996 1995 1994
U.S. Canada U.S. Canada U.S. Canada
Thousands of Dollars
<S> <C> <C> <C> <C> <C> <C>
NONUTILITY OPERATIONS
At December 31:
Capitalized costs relating
to oil and natural gas
producing activities $182,339 $ 87,529 $171,795 $ 83,457 $145,639 $ 78,667
Accumulated depreciation,
depletion and valuation
allowances 65,401 44,770 60,329 39,834 39,534 27,247
Net capitalized costs $116,938 $ 42,759 $111,466 $ 43,623 $106,105 $ 51,420
For the year ended
December 31:
Costs incurred in oil and
natural gas property
acquisition, exploration
and development
activities:
Acquisition of
properties $ 4,667 $ 3,722 $ 13,024 $ 4,407 $ 8,134 $ 5,866
Exploration 1,780 2,157 4,592 1,642 2,513 1,924
Development 10,651 3,345 11,244 4,298 11,514 4,068
Results of operations for
oil and natural gas
producing activities:
Revenues $ 26,872 $ 19,789 $ 20,461 $ 19,022 $ 25,319 $ 22,542
Production costs 8,901 6,547 7,298 6,812 7,261 7,404
Exploration expenses 1,670 1,747 2,460 1,517 1,610 1,426
Depreciation, depletion
and valuation
provisions 10,019 6,133 21,079 15,371 10,533 7,669
6,282 5,362 (10,376) (4,678) 5,915 6,043
Income tax expenses 946 2,393 (5,708) (2,087) 25 2,679
Results of operations from
producing activities
(excluding corporate
overhead and interest
cost) $ 5,336 $ 2,969 $ (4,668) $ (2,591) $ 5,890 $ 3,364
</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
1996 1995
U.S. Canada U.S. Canada
Thousands of Dollars
<S> <C> <C> <C> <C>
Future cash inflows $ 684,709 $ 185,988 $ 523,563 $ 148,140
Future production and
development costs 261,432 68,921 197,073 57,455
Future income tax expenses 129,091 27,876 89,726 18,033
Future net cash flows 294,186 89,191 236,764 72,652
10% annual discount for
estimated timing
of cash flows 135,285 23,407 98,831 16,163
Standardized measure of
discounted future net
cash flows $ 158,901 $ 65,784 $ 137,933 $ 56,489
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 $ (22,466) $ (13,242) $ (33,013) $ (24,585)
Net changes in prices,
development and production
costs 16,095 30,948 (24,122) (7,886)
Extensions, discoveries, and
improved recovery, less
related costs 19,823 2,597 8,100 1,728
Revisions of previous quantity
estimates 14,012 (11,395) (12,950) 4,860
Accretion of discount 16,939 6,150 20,816 7,483
Net change in income taxes (14,670) (4,005) 10,948 6,315
Other (8,765) (1,758) 2,403 5,074
</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 1996 and 1995, 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 1996 and 1995
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>
<TABLE>
<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 57,029 22,749 23,895 59,280
Utility Net Income 27,530 5,644 7,823 29,008
Nonutility Operating Revenues 137,421 110,926 94,560 104,930
Nonutility Operating Income 32,271 16,547 8,385 16,083
Nonutility Net Income 19,026 12,585 6,463 11,307
Consolidated Net Income 46,556 18,229 14,286 40,315
Net Income Per Share of Common
Stock $ 0.80 $ 0.30 $ 0.23 $ 0.70
<CAPTION>
Quarter Ended
Dec. 31, Sept. 30, June 30, Mar. 31,
1995 1995 1995 1995
<S> <C> <C> <C> <C>
Utility Operating Revenues $165,280 $110,248 $108,144 $160,105
Utility Operating Income 61,213 19,218 16,084 59,334
Utility Net Income 32,204 6,251 3,768 30,967
Nonutility Operating Revenues 116,995 117,255 103,891 104,891
Nonutility Operating
Income (Loss) (59,267) 10,149 3,060 1,671
Nonutility Net Income (Loss) (33,320) 9,900 3,802 3,365
Consolidated Net Income (Loss) (1,116) 16,151 7,570 34,332
Net Income (Loss) Per Share of
Common Stock $ (0.05) $ 0.25 $ 0.11 $ 0.61
</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 1997 Annual Meeting of Shareholders and
Proxy Statement, pages 1-3.
ITEM 11. EXECUTIVE COMPENSATION
Incorporated by reference from Notice of 1997 Annual Meeting of
Shareholders and Proxy Statement, pages 6-8.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Incorporated by reference from Notice of 1997 Annual Meeting of
Shareholders and Proxy Statement, pages 4-5.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Incorporated by reference from Notice of 1997 Annual Meeting of
Shareholders and Proxy Statement, page 14.
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 22, 1996 Item 5. Other Events. Discussion of Third
Quarter Net Income.
Item 7 Exhibits. Consolidated Statements of
Income for the Quarters Ended September 30,
1996 and 1995, Nine Months Ended September 30,
1996 and 1995, and for the Twelve Months Ended
September 30, 1996 and 1995. Utility
Operations Schedule of Revenues and Expenses
for the Quarters Ended September 30, 1996 and
1995, Nine Months Ended September 30, 1996 and
1995 and for the Twelve Months Ended
September 30, 1996 and 1995. Nonutility
Operations Schedule of Revenues and Expenses
for the Quarters Ended September 30, 1996 and
1995, Nine Months Ended September 30, 1996 and
1995 and for the Twelve Months Ended
September 30, 1996 and 1995.
December 11, 1996 Item 5. Other Events. MPC's Board Announces
Succession Plan.
February 21, 1997 Item 5. Other Events. Montana Power Company
and Puget Sound Power and Light Resolve a
Pending Litigation Matter.
February 28, 1997 Item 2. Acquisition or Disposition of
Assets. Montana Power Company, through its
subsidiary, North American Resources Co.,
announced its commitment to purchase Vessels
Energy's oil and gas assets in Colorado's
Denver-Julesburg Basin.
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
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
THE MONTANA POWER COMPANY AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Thousands of Dollars
</TABLE>
<TABLE>
<CAPTION>
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
Balance Additions
at Charged to Charged to Balance
beginning costs and other at close
Description of period expenses accounts Deductions of period
<S> <C> <C> <C> <C> <C>
(Note a)
Year Ended:
December 31, 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
December 31, 1994
Reserves deducted
in balance sheet
from assets to
which they apply:
Doubtful accounts
Utility $ 748 $ 781 $ 721 $ 808
Nonutility 643 156 $ (9) 174 616
Total $ 1,391 $ 937 $ (9) $ 895 $ 1,424
<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/ Daniel T. Berube
Daniel T. Berube
(Chairman of the Board)
Date: March 26, 1997
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title Date
/s/ Daniel T. Berube Principal Executive
Daniel T. Berube Officer and Director March 26, 1997
(Chief Executive Officer)
/s/ J. P. Pederson Principal Financial
J. P. Pederson and Accounting Officer March 26, 1997
(Vice President and Chief and Director
Financial and Information
Officer)
/s/ Tucker Hart Adams Director March 26, 1997
Tucker Hart Adams
/s/ Alan F. Cain Director March 26, 1997
Alan F. Cain
/s/ R. D. Corette Director March 26, 1997
R. D. Corette
/s/ Robert P. Gannon Director March 26, 1997
Robert P. Gannon
/s/ Kay Foster Director March 26, 1997
Kay Foster
/s/ Beverly D. Harris Director March 26, 1997
Beverly D. Harris
/s/ Chase T. Hibbard Director March 26, 1997
Chase T. Hibbard
/s/ John R. Jester Director March 26, 1997
John R. Jester
/s/ Daniel P. Lambros Director March 26, 1997
Daniel P. Lambros
/s/ Carl Lehrkind, III Director March 26, 1997
Carl Lehrkind, III
/s/ James P. Lucas Director March 26, 1997
James P. Lucas
/s/ Arthur K. Neill Director March 26, 1997
Arthur K. Neill
/s/ N. E. Vosburg Director March 26, 1997
N. E. Vosburg
EXHIBIT INDEX
Exhibit 3(a)(2)
Articles of Amendment to the Restated Articles of
Incorporation 100-101
Exhibit 3(b)(1)
Amendment to By-laws dated August 27, 1996 102-104
Exhibit 10(a)(v)
Termination Compensation Agreements with Senior Management
Executives 105-114
Exhibit 12
Statement Re Computation of Ratio Earnings to Fixed Charges 115
Exhibit 21
Subsidiaries of the Registrant 116-118
Exhibit 23
Consent of Independent Accountants 119
Exhibit 27
Financial Data Schedule 120
- -1-
- -15-
- -27-
- -51-
- -81-
-97-
SIGNATURES (Continued)
- -99-
</TABLE>
3(a)(2)
ARTICLES OF AMENDMENT
TO THE RESTATED ARTICLES OF INCORPORATION
OF
THE MONTANA POWER COMPANY
Pursuant to the provisions of Section 35-1-230, MCA, the undersigned
corporation adopts the following Articles of Amendment to its Articles of
Incorporation.
FIRST: The name of the corporation is The Montana Power Company.
SECOND: The following amendment to the corporation's Restated
Articles of Incorporation was adopted by the shareholders of the corporation
on May 14, 1996, in the manner prescribed by the Montana Business Corporation
Act.
Article VI of the Restated Articles of Incorporation of the corporation
is amended
to read as follows:
No Director of the Corporation shall be personally liable to the
Corporation or its shareholders for money damages for any actions
taken or any failure to take any action, as a Director, except
liability for: (a) the amount of a financial benefit received by a
Director to which the Director is not entitled; (b) an intentional
infliction of harm on the corporation or its shareholders; (c) a
violation of 35-1-713 of the Montana Code Annotated; or, (d) an
intentional violation of criminal law. No amendment to or repeal
of this Article VI shall apply to or have any effect on the
liability or alleged liability of any Director of the Corporation
for or with respect to any acts or omissions of such Director
occurring prior to such amendment or repeal.
THIRD: The number of Common shares of the corporation outstanding
at the record date was 54,632,075 common shares; and the number of such
shares entitled to vote on the amendment was 54,632,075. The number of
Preferred shares of the corporation outstanding at the record date was
1,919,589; and the number of such shares entitled to vote on the amendment
was 1,919,589.
FOURTH: The number of voting shares represented at the meeting were:
Common 47,509,562 Preferred 1,621,807
FIFTH: The vote on the Amendment was as follows:
For Against
Common and Preferred Total: 43,561,574 4,475,104
DATED: June 13, 1996.
THE MONTANA POWER COMPANY
/s/Robert P. Gannon
Vice Chairman of the Board and
President
(SEAL)
/s/Pamela K. Merrell
Assistant Secretary
STATE OF MONTANA )
ss.
County of Silver Bow )
I, the undersigned Notary Public, do hereby certify that on this
13th day of June, 1996, personally appeared before me R. P. Gannon, who,
being by me first duly sworn, declared that he is Vice Chairman of the Board
and President of THE MONTANA POWER COMPANY, that he signed the foregoing
document as Vice Chairman of the Board and President of the Corporation, and
that the statements therein contained are true.
/s/Lauri A. Yelenich
Notary Public for the State of Montana
(SEAL) Residing at Butte, Montana
My Commission Expires: 9/1/96
3(b)(1)
BYLAWS
OF
THE MONTANA POWER COMPANY
Adopted on : August 22, 1995
As Amended on : August 27, 1996
THE MONTANA POWER COMPANY
AMENDED BYLAWS
Article Amendment Date of Amendment
11 The affairs of the Corporation shall be managed by August 27, 1996
a Board of fifteen (15) Directors. The Directors
shall be divided into three groups, each as nearly
equal in number as possible. Each group of
Directors shall stand for election upon expiration
of their terms. Directors shall hold office for a
term of three (3) years or until a successor is
duly elected and qualified.
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 August 27, 1996 and that
said Resolution is in full force and effect as of the date of this
certificate.
RESOLVED, that effective August 27, 1996, the first sentence of
Section 11 of the Bylaws of The Montana Power Company is hereby amended
to reduce the number of Directors to fifteen (15) as follows:
SECTION 11. The affairs of the Corporation shall be managed by a
Board of fifteen (15) Directors.
IN WITNESS WHEREOF, I have hereunto set my hand and the Seal of said
Corporation this 11th day of November, 1996.
/s/R. M. Ralph
Assistant Secretary
(SEAL)
Dear:
The Board of Directors (the "Board") of The Montana Power Company and
the Personnel Committee (the "Committee") of the Board have determined that
it is in the best interests of the Company (as hereinafter defined) and its
shareholders for the Company to enter into this agreement with you to pay
you termination compensation in the event you should leave the employ of the
Company under the circumstances described below.
The Board and the Committee recognize the valuable services you render
and want to assure your continued and active participation in the Company's
business affairs. They also realize that the possibility of a Change of
Control (as hereafter defined) of the Company is unsettling to you and other
senior executives of the Company. Therefore, this agreement is being made
to protect you against some of the possible consequences of a Change of
Control and thereby to induce you to continue to serve the Company. In
particular, the Board and the Committee believe it important, should the
Company receive proposals from third parties with respect to its future, to
enable you, without being influenced by the uncertainties of your own
situation, to contribute to the assessment of such proposals, to the end
that the Board may be competently and objectively advised whether a proposal
would be in the best interests of the Company, its shareholders, employees
and customers, and the communities which it serves and to participate in
such other actions regarding such proposals as the Board might determine to
be appropriate. The Board and the Committee also wish to demonstrate to
executives of the Company that the Company is concerned with the welfare of
its executives.
1. Cash Severance
In view of the foregoing and in consideration of your agreement to
remain employed with the Company, the Company will pay you as termination
compensation a single sum amount, determined as provided below, in the event
that within three years after a Change of Control of the Company your
employment with the Company (i) is terminated by the Company during the Term
(as defined below in section 6.3) (other than (a) for Cause (as hereafter
defined) or (b) due to Disability or your death) or (ii) is terminated by
you for Good Reason (as hereafter defined), such payment to be made within
five (5) business days of the effective date of any such termination. Your
employment shall be deemed to have been terminated following a Change of
Control by the Company without Cause or by you for Good Reason (a) if you
reasonably demonstrate that your employment was terminated prior to a Change
of Control without Cause (1) at the request of a Person who has entered into
an agreement with the Company the consummation of which will constitute a
Change of Control (or who has taken other steps reasonably calculated to
effect a Change of Control) or (2) otherwise in connection with, as a result
of or in anticipation of a Change of Control, or (b) if you terminate your
employment for Good Reason prior to a Change of Control and you reasonably
demonstrate that the circumstance(s) or events(s) which constitute such Good
Reason occurred (1) at the request of such Person or (2) otherwise in
connection with, as a result of or in anticipation of a Change of Control.
Your right to terminate your employment for Good Reason shall not be
affected by your incapacity due to physical or mental illness. Your
continued employment shall not constitute your consent to, or a waiver of
your rights with respect to, any act or failure to act constituting Good
Reason hereunder. The single sum compensation so payable shall be equal to
299.9% of the sum of (i) the highest annual rate of base salary paid or
payable to you during the thirty-six (36) month period immediately preceding
the month in which the Change of Control occurred, and (ii) the highest
annual bonus paid or determined payable to you during such thirty-six (36)
month period.
2. Other Severance.
In addition, in the event your employment with the Company terminates
as described in Section 1 above, within three years after a Change of
Control of the Company:
(a) If you have any awards of Dividend Equivalents outstanding (a)
at the date of termination of your employment any such awards will be
accelerated and be payable to you as follows:
(i) Actual annual performance will be calculated to the
end of the calendar year (s) prior to the date of
termination of your employment;
(ii) Performance for the years remaining in an Award Period
which end after the date of termination of your
employment will be deemed to be sufficient such that
100% of all the performance measures would have been
achieved; and
(iii) Payout will be made no later than 60 days from the
date of termination of employment by calculating the
amount due using the above assumptions in the
methodology prescribed in the Dividend Equivalent
Award.
(b) Your participation in and rights and benefits under the
Retirement Plan for Employees of The Montana Power Company, any
corresponding Plan of a subsidiary company or any other
successor retirement or pension plan adopted by the Company
("the Plan") shall be governed by the terms of the Plan;
provided, however that you shall be paid, at the same time that
benefit payments are distributed to you under the Plan, an
additional supplemental retirement benefit in cash equal in
amount to the excess (if any) of (i) the benefit payable to you
under the Plan calculated, for this purpose only, (A) as if you
had reached your Normal Retirement Date (as hereinafter defined)
on your date of termination, (B) as if you had become a member
of the Plan on or after January 1, 1985, all in accordance with
the terms and provisions of the Plan (other than as modified
herein) in existence on the date of any Change of Control or
related Potential Change of Control, whichever would produce the
highest benefit, and (C) assuming the benefit so determined, as
modified under (A) and (B) of this clause, shall be first
reduced by 4.545% for each year or fraction thereof by which you
are younger than age 62, over (ii) your actual benefit under the
Plan.
(c) To the extent the plans so provide, you shall be eligible to
continue participation in the Company's life insurance plan,
health plan, dental plan and disability plan and other welfare
benefit plans, as each shall have been in effect immediately
prior to any Potential Change of Control, for three years after
the termination of your employment, provided, however, that in
the event you are ineligible (or become ineligible) under the
terms of any such plan to continue to so participate, the
Company shall provide through other sources substantially
equivalent benefits until the earlier of three years after
termination or your Normal Retirement Date (it being understood
that death benefits payable under the life insurance plan may
continue to be paid beyond such three year period). At the
earlier of three years after termination or your Normal
Retirement Date, the Company shall provide, at no cost to you, a
permanent, fully paid life insurance policy in the amount of
$5,000.
3. Special Reimbursement
In the event that you become entitled to payments and/or benefits
under this agreement, if any payment or benefits paid or payable, or
received or to be received, by you or on your behalf in connection with a
Change of Control or termination of your employment, whether any such
payments or benefits are pursuant to the terms of this agreement or any
other plan, arrangement or agreement with the Company, any of its
subsidiaries, any Person, or otherwise(the "Total Payments") will or would
be subject to the excise tax imposed by Section 4999 of the Code, or any
successor or similar provision thereto (the "Excise Tax"), the Company shall
pay to you an additional amount (the "Gross-Up Payment") such that the net
amount retained by you, after deduction of any Excise Tax on the Total
Payments and any federal, state and local income tax and Excise Tax upon the
payments provided for in this Section 5, but before deduction for any
federal, state or local income tax on the Total Payments, shall be equal to
the Total Payments.
3.1 For purposes of determining whether any of the Total Payments
will be subject to the Excise Tax and the amount of such Excise Tax:
(a) the Total Payments shall be treated as "parachute payments"
within the meaning of Section 280G(b)(2) of the Code, and all
"excess parachute payments" within the meaning of Section
280G(b)(1) of the Code shall be treated as subject to the Excise
Tax, unless, in the opinion of tax counsel selected by the
Company's independent auditors (and reasonably acceptable to
you), such payments or benefits (in whole or in part) do not
constitute parachute payments, or such excess parachute payments
(in whole or in part) represent reasonable compensation for
services actually rendered within the meaning of Section
280G(b)(4)(B) of the Code or are otherwise not subject to the
Excise Tax;
(b) the value of any non-cash benefits or any deferred payment or
benefit shall be determined by the Company's independent
auditors in accordance with the principles of Sections
280G(d)(3) and (4) of the Code.
3.2 For purposes of determining the amount of the Gross-Up Payment,
you shall be deemed to pay federal income taxes at the highest marginal rate
of federal income taxation for the calendar year in which the Gross-Up
Payment is to be made and applicable state and local income taxes at the
highest marginal rate of taxation for the calendar year in which the Gross-
Up Payment is to be made, net of the maximum reduction in federal income
taxes which could be obtained from deduction of such state and local taxes.
In the event that the Excise Tax is subsequently determined to be less than
the amount taken into account hereunder at the time the Gross-Up Payment is
made, you shall repay to the Company, at the time that the amount of such
reduction in Excise Tax is finally determined, the portion of the Gross-Up
Payment attributable to such reduction plus interest on the amount of such
repayment at the rate provided in Section 1274(b)(2)(B) of the Code. In the
event that the Excise Tax is determined to exceed the amount taken into
account hereunder at the time the Gross-Up Payment is made (including by
reason of any payment the existence or amount of which cannot be determined
at the time of the Gross-Up Payment), the Company shall make an additional
Gross-Up Payment in respect of such excess (plus any interest payable with
respect to such excess at the rate provided above for repayments) at the
time that the amount of such excess is finally determined. You and the
Company shall each reasonably cooperate with the other in connection with
any administrative or judicial proceedings concerning the existence or
amount of liability for Excise Tax with respect to any payments received by
you from the Company or otherwise in connection with any Change of Control
or termination of your employment.
3.3 The Gross-Up Payment or portion thereof provided for above shall
be paid not later than the thirtieth day following the date of your
termination, provided, however, that if the amount of such Gross-Up Payment
or portion thereof cannot be finally determined on or before such day, the
Company shall pay to you on such day an estimate, as determined by the
Company's independent auditors, of the minimum amount of such payments and
shall pay the remainder of such payments (together with interest at the rate
provided in Section 1274(b)(2)(B) of the Code) as soon as the amount thereof
can be determined, but in no event later than the forty-fifth day after the
date of your termination. In the event that the amount of the estimated
payments exceeds the amount subsequently determined to have been due, such
excess shall constitute a loan by the Company to you, payable on the fifth
day after demand by the Company (together with interest at the rate provided
in Section 1274(b)(2)(B) of the Code).
4. Certain Definitions
4.1 For purposes of this agreement, a "Change of Control" means and
shall be deemed to occur if:
(a) the Shareholders of the Company approve the dissolution or
liquidation of the Company; or
(b) the Shareholders of the Company approve a reorganization,
merger, or consolidation of the Company, other than a
reorganization, merger or consolidation with respect to which
all or substantially all of the individuals and entities who
were "beneficial owners" (as defined below), immediately prior
to such reorganization, merger or consolidation, of the combined
voting power of the Company's then outstanding securities
beneficially own, directly or indirectly, immediately after any
such reorganization, merger or consolidation, more than eighty
percent (80%) of the combined voting power of the securities of
the corporation resulting from such reorganization, merger or
consolidation in substantially the same proportions as their
respective ownership, immediately prior to any such
reorganization, merger or consolidation, of the combined voting
power of the Company's securities; or
(c) there occurs the sale, exchange, transfer, or other disposition
of shares of stock of the Company (or shares of the stock of any
Person (as hereafter defined) that is a shareholder of the
Company) in one or more transactions, related or unrelated, to
one or more Persons if, as a result of such transactions, any
Person is or becomes the "beneficial owner" (as defined in Rule
13d-3 under the Securities Exchange Act of 1934 (the "Exchange
Act")), directly or indirectly, of securities of the Company
(not including in the securities beneficially owned by such
Person(s) any securities acquired directly from the Company)
representing more than 20% of the combined voting power of the
then outstanding stock of the Company; or
(d) there occurs any transaction which the Company is required to
disclose pursuant to Item 1(a) of Form 8-K (as filed pursuant to
Rule 13a-11 or Rule 15d-11 of the Exchange Act); or
(e) during any period of twenty-four (24) consecutive months (not
including any period prior to December 31, 1995), individuals
who constitute the Board at the beginning of such period(the
"Incumbent Board") cease for any reason to constitute at least a
majority thereof, provided that any individual becoming a
director (other than a director designated by a Person who has
entered into an agreement with the Company or an affiliate of
the Company to effect a transaction described in clauses (a),
(b), (c), (e), or (f) of this definition or any such individual
whose initial assumption of office occurs as a result of either
an actual or threatened election contest (as such terms are used
in Rule 14a-11 of Regulation 14A promulgated under the Exchange
Act) or other actual or threatened solicitations of proxies or
consents) subsequent to the beginning of such period whose
election, or nomination for election by the Company's
shareholders, was approved by a vote of at least two-thirds of
the directors then still in office and comprising the Incumbent
Board at the beginning of such period or whose election or
nomination for election was previously so approved (either by a
specific vote or by approval of the proxy statement of the
Company in which such individual is named as a nominee for
director, without objection to such nomination) shall be
considered as though such individual were a member of the
Incumbent Board; or
(f) there occurs the sale of all or substantially all the assets of
the Company; for purposes of this clause (f) the sale of
subsidiaries or assets having a fair market value in excess of
$100,000,000, shall be deemed conclusively to constitute a sale
or other dispositions of substantially all the assets of the
Company if (i) such assets constitute an entire line of business
of the Company (such as, for example, coal mining, lignite
mining or oil and gas) and (ii) if you are an employee of or
your work substantially relates to the subsidiary or line of
business which is sold; provided however, that a sale and
leaseback of an asset in a financing transaction is not a sale
hereunder.
Notwithstanding the foregoing, a Change of Control shall not include
any event, circumstance or transaction which results from the action
(excluding your employment activities with the Company or any of its
subsidiaries) of any Person or group of Persons which includes, is directly
affiliated with or is wholly or partly controlled by one or more executive
officers of the Company and in which you actively participate.
4.2 For purposes of this agreement, "Potential Change of Control"
shall mean and be deemed to have occurred if:
(i) the Company commences negotiations in respect of or enters
into an agreement, the consummation of which would result in occurrence of a
Change of Control;
(ii) the Company or any Person publicly announces an intention
to take actions which, if consummated, would constitute a Change of Control;
and/or
(iii) any Person becomes the "beneficial owner" (as defined
above), directly or indirectly, of securities of the Company representing
ten percent (10%) or more of the combined voting power of the Company's then
outstanding securities, or any Person increases such Person's beneficial
ownership of such securities by five (5) percentage points or more over the
percentage so owned by such Person on December 31, 1995.
4.3 For the purposes of this agreement, unless the context requires
otherwise, "Company" shall mean and include The Montana Power Company and
any successor to its business and/or assets which assumes (either expressly,
by operation of law or otherwise) and/or agrees to perform this agreement by
operation of law or otherwise (except in determining whether or not any
Change of Control has occurred in connection with such succession).
4.4 For purposes of this agreement, "Person" shall mean and include
any individual, corporation, partnership, group, association or other
"person," as such term is used in Section 3(a) (9) of the Exchange Act, as
modified and use in Sections 13(d) and 14(d) there of, other than (i) the
Company, or any subsidiary of the Company, (ii) any trustee or other
fiduciary holding securities under any employee benefit plan(s) sponsored by
the Company or any such subsidiary (iii) an underwriter temporarily holding
securities pursuant to an offering of such securities, or (iv) a corporation
owned, directly or indirectly, by the stockholders of the Company in
substantially the same character and proportions as their ownership of stock
of the Company.
4.5 For purposes of this agreement, "Normal Retirement Date" shall
have the meaning set forth in the Plan.
4.6 For purposes of this agreement, "Disability" shall mean and be
deemed the reason for the termination by the Company of your employment, if,
as a result of your incapacity due to physical or mental illness, (i) you
shall have been absent from the full-time performance of your duties with
the Company for a period of six (6) consecutive months, (ii) the Company
gives you a notice of termination for Disability, and (iii) within thirty 30
Days after such notice of termination is given, you do not return to the
full-time performance of your duties.
4.7 For purposes of this agreement, "Cause" shall mean (i) the
willful and continued failure by you to perform substantially your duties
with the Company (other than any such failure resulting from your incapacity
due to physical or mental illness) after a demand for substantial
performance is delivered to you by the Chairman of the Board or Chief
Executive Officer or President of the Company which demand specifically
identifies the manner in which such executive believes that you have not
substantially performed your duties or (ii) the continued and willful
engaging by you in conduct which is demonstrably and materially injurious to
the Company and/or its subsidiaries, monetarily or otherwise; provided that
no act, or failure to act, on your part shall be considered "willful" unless
done, or omitted to be done, by you in bad faith and without reasonable
belief that your action or omission was in, or not opposed to, the best
interests of the Company. Any act, or failure to act, based upon authority
given pursuant to a resolution duly adopted by the Board or upon the
instructions of the Company's Chief Executive Officer or other duly
authorized senior officer of the Company or based upon the advice of counsel
for the Company shall be conclusively presumed to be done, or omitted to be
done, by you in good faith and in the best interest of the Company and its
subsidiaries. The cessation of your employment shall not be deemed to be
for Cause unless and until there shall have been delivered to you a copy of
a resolution duly adopted by the affirmative vote of not less than three-
quarters of the entire membership of the Board at a meeting of the Board
called and held for such purpose (after reasonable notice of any such
meeting is provided to you and you are given an opportunity, together with
counsel, to be heard before the Board), finding that, in the good faith
opinion of the Board, you are guilty of the conduct described in clause (i)
or (ii) above, and specifying the particulars thereof in detail.
4.8 For purposes of this agreement, "Good Reason" shall mean the
occurrence (without your prior express written consent) of any of the
following acts or failure to act:
(a) the assignment to you of any duties inconsistent with your
positions, duties, responsibilities and status with the Company
immediately prior to any Potential Change of Control, or an
adverse and substantial change in your reporting
responsibilities, titles, or offices or any removal of you from
or any failure to re-elect you to any of such positions or
offices, as you may hold immediately prior to any such Potential
Change of Control, except in connection with the termination of
your employment for disability, retirement or as a result of
your death, or by you other than for Good Reason;
(b) the reduction by the Company in your rate of salary per annum as
in effect immediately prior to any Potential Change of Control;
(c) a failure by the Company to continue in effect any retirement or
benefit plan of the Company (including, but not limited to the
Plan, the Deferred Savings and Employee Stock Ownership Plan,
the Long-Term Incentive Plan, executive bonus plan, deferred
compensation plan, supplemental or excess benefit plan, benefit
restoration plan or similar plan of the Company) in which you
are participating immediately prior to any Potential Change of
Control, substantially in the form then in effect, unless an
equitable arrangement (embodied in an ongoing substitute or
alternative plan or arrangement) has been made with respect to
such plan, or the failure by the Company or a subsidiary to
continue your participation therein (or in such substitute or
alternative plan or arrangement) on a basis not materially less
favorable, both in terms of the amount of benefits provided and
the level of your participation relative to other participants,
as existed at the time of the Potential Change of Control;
(d) the failure by the Company to continue you and, if applicable,
your family's participation in any life insurance plan, retiree
or other medical plan, accident plan, hospitalization plan,
health plan, dental plan, disability plan or other welfare
benefit plan) in which you (or if applicable your family) are
participating immediately prior to a Change of Control, or any
successor to any such plans, at at least the same participation
and benefit level to which you were entitled immediately prior
to such Potential Change of Control, the taking of any action by
the Company or a subsidiary which would directly or indirectly
materially reduce any of such benefits or deprive you of any
material fringe benefits enjoyed by you at the time of the
Potential Change of Control, or the failure by the Company or a
subsidiary to provide you with the number of paid vacation days
to which you are entitled in accordance with the Company's or a
subsidiary's normal vacation policy in effect at the time of the
Potential Change of Control;
(e) the relocation of the office or place where you normally report
for work to a location more than twenty (20) miles distant from
the location where you normally reported for work immediately
prior to the Potential Change of Control, except for required
travel in respect of the Company's business to an extent
substantially consistent with your business travel obligations
as of the date of any Potential Change of Control;
(f) the failure by the Company to provide you with the number of
paid vacation days to which you are entitled on the basis of
your years of service with the Company in accordance with the
Company's normal vacation policy as in effect immediately prior
to any Potential Change of Control;
(g) the failure by the Company to obtain a satisfactory agreement
from any successor to assume and agree to perform this
agreement; and/or
(h) a termination by you for any reason during the thirty (30) day
period immediately following the first anniversary of any Change
of Control, unless your Normal Retirement Date will occur within
six months of such anniversary.
5. Legal Fees. If at any time you shall (i) institute legal
proceedings to enforce any of the provisions of this agreement, and without
regard to whether or not, as a result thereof, you become entitled to
monetary or other relief from the Company (whether by way of judgment,
settlement or otherwise), or (ii) become involved in any tax audit or
proceeding to the extent attributable to the application of Section 4999 of
the Code to any payment provided to you, the Company shall, in addition to
paying or otherwise providing any such or other relief, reimburse you for
all reasonable expenses incurred by you resulting from or in connection with
such audit or proceedings, including (without limitation) your attorneys'
fees and expenses, except in the case of (i) above if a court determines
that your initiation of or legal position in such legal proceedings was
frivolous or advanced in bad faith. Any monetary relief to which you shall
become entitled shall bear interest at the highest legal rate allowable from
the date of termination of your employment. The Company also agrees to
reimburse you for all reasonable expenses, including (without limitation)
your attorneys' fees and expenses , incurred by you in connection with
litigation concerning this agreement instituted by third parties, whether on
behalf of the Company or not. The Company agrees that litigation concerning
this agreement, whether instituted by you, the Company, or third parties,
shall not be grounds for withholding payment to you of the termination
compensation and other benefits provided for herein or elsewhere and such
termination compensation and other benefits shall be paid to you
notwithstanding such litigation.
6. Miscellaneous.
6.1 The termination compensation and other benefits provided herein
are in lieu of, and not in addition to, compensation and benefits provided
to other employees by The Montana Power Company Termination Benefits Upon
Change of Control Policy. The Company agrees that you are not required to
seek other employment or to attempt in any way to reduce any amounts payable
to you by the Company pursuant to this agreement. Further, the amount of
any payment or benefit provided for by this Agreement shall not be reduced
by any compensation earned by you as the result of employment by another
employer, by retirement benefits, or offset against any amount claimed to be
owed by you to the Company or any of its subsidiaries, or otherwise.
6.2 This agreement shall be binding upon and inure to the benefit of
you and your estate and the Company and any successor of the Company.
6.3 This agreement shall be effective on the date hereof and shall
continue in effect through December 31, 1998; provided, however, that
commencing on January 1, 1998 and each January 1 thereafter the term of this
agreement shall be extended for additional one year periods unless, prior to
June 30 of the preceding year you or the Company shall have given written
notice to the other that this agreement shall not be so extended; provided,
further, however, that if a Change of Control occurs during the initial
term, or any extension term, of this agreement, the agreement shall continue
in full force and effect for a period of not less than thirty-six (36)
months beyond the month in which the Change of Control occurred (the
"Term"). This binding severance agreement is not and should not be
characterized as a contract of employment.
6.4 Prior to a Change of Control, and except as otherwise provided
herein, this agreement does not impose on the Company any obligation to
change or not to change the status of your employment, or to change or not
to change any policies or practices regarding conditions of employment or
termination of employment.
6.5 This agreement shall be governed by the laws of the state of
Montana without regard to the principles of conflict of laws thereof.
6.6 You shall hold in a fiduciary capacity for the benefit of the
Company all secret or confidential information, knowledge or data relating
to the Company or any of its affiliated companies, and their respective
businesses, which shall have been obtained by you during your employment by
the Company or any of its affiliated companies and which shall not be or
become public knowledge (other than by direct or indirect acts by you in
violation of this agreement). After termination of your employment with the
Company, you shall not, without the prior written consent of the Company or
as may otherwise be required by law or legal process, communicate or divulge
any such information, knowledge or data to anyone other than the Company and
those designated by it. In no event, however, shall an asserted violation
of the provisions of this Section 6.6 constitute a basis for deferring or
withholding any amounts otherwise payable to you under this agreement.
If you are in agreement with the foregoing, please so indicate by
signing and returning to the Company the enclosed copy of this letter,
whereupon this letter shall constitute a binding agreement between you and
the Company.
Very truly yours,
THE MONTANA POWER COMPANY
\s\Daniel T. Berube
Chairman of the Board
AGREED:
Schedule to Exhibit 10 (a)(v)
Agreements entered into on January 1, 1996, with Daniel T. Berube, Robert P.
Gannon, Jerrold P. Pederson, Arthur K. Neill, Richard F. Cromer, Michael E.
Zimmerman, and Pamela K. Merrell. All of these agreements are identical in
material aspects.
Another agreement with Jack Haffey was entered into on October 3, 1996 and is
an identical agreement as the above agreements, except that the agreement's
definition of change of control, Section 4.1 (f) includes only a sale of all
or substantially all of the assets of the Company, where as the other
agreements include sales of portions of the business as well as the sale of
all or substantially all of the Company's assets.
Exhibit 10(a)(v)
January 1, 1996
1
Exhibit 12
THE MONTANA POWER COMPANY
Computation of Ratio Earnings to Fixed Charges
(Dollars in Thousands)
Twelve Months
Ended
December 31,1996
Net Income $ 119,147
Income Taxes 72,813
$ 191,960
Fixed Charges:
Interest $ 50,937
Amortization of Debt Discount,
Expense and Premium 1,610
Rentals 34,470
$ 87,017
Earnings Before Income Taxes
and Fixed Charges $278,977
Ratio of Earning to Fixed Charges 3.21 x
SUBSIDIARIES OF REGISTRANT Exhibit 21
Percentage of Voting
Securities Owned
by Registrant
Canadian-Montana Gas Company Limited
An Alberta Corporation 100
Canadian-Montana Pipe Line Company
An Alberta Corporation 100
Glacier Gas Company
A Montana Corporation 100
Colstrip Community Services Company
A Montana Corporation 100
Montana Energy Services Company
A Montana Corporation 100
Montana Power Capital 1
A Delaware 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.
Investment in English Partnership in a
Gas-fired Cogeneration Project
(A 47.5% owned subsidiary of Continental
Energy Services, Inc.) 50
Entech, Inc.
A Montana Corporation 100
Western Energy Company
A Montana Corporation 100
Western Syncoal Company
A Montana Corporation
(A wholly-owned subsidiary of Western
Energy Company) 100
Montana Participacoes, Ltda.
A Brazilian Corporation 100
Financiera Ulken Sociedad Anonima (SA)
A Uruguayan Corporation
(A wholly-owned subsidiary of Montana
Mineracao Participacoes, Ltda.) 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
MP Energy, Inc.
A Montana Corporation 100
Basin Resources, Inc.
A Colorado Corporation 100
Horizon Coal Services, Inc.
A Montana Corporation 100
North Central Energy Company
A Colorado Corporation 100
Trinidad Railway, Inc.
A Montana Corporation 100
Entech Gas Ventures, Inc.
A Montana Corporation 100
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
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. 33-58403, 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
6, 1997, except as to paragraphs 3 and 5 of Note 2, which are as of February
21, 1997, appearing on page 51 of The Montana Power Company's Annual Report on
Form 10-K for the year ended December 31, 1996.
/s/ Price Waterhouse LLP
PRICE WATERHOUSE LLP
Portland, Oregon
March 16, 1997
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THIS SCHEDULE CONTAINS SUMMARY INFORMATION EXTRACTED FROM THE CONSOLIDATED
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<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> DEC-31-1996
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<TOTAL-NET-UTILITY-PLANT> 1,576,276
<OTHER-PROPERTY-AND-INVEST> 545,757
<TOTAL-CURRENT-ASSETS> 271,576
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<TOTAL-ASSETS> 2,698,215
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57,654
<LONG-TERM-DEBT-NET> 627,057
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<OTHER-OPERATING-EXPENSES> 736,970
<TOTAL-OPERATING-EXPENSES> 808,945
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<OTHER-INCOME-NET> 3,893
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<EARNINGS-AVAILABLE-FOR-COMM> 111,681
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