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 (FEE REQUIRED)
For the fiscal year ended December 31, 1995
-OR-
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
For the transition period from ______________ to _______________.
Commission file number 1-4566
THE MONTANA POWER COMPANY
(Exact name of registrant as specified in its charter)
Montana 81-0170530
(State or other jurisdiction (IRS Employer
of incorporation or organization) Identification No.)
40 East Broadway, Butte, Montana 59701-9394
(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
Securities registered pursuant to Section 12(g) of the Act:
Preferred Stock
(Title of Class)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K (Section 229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K.
Yes X No
The aggregate market value of the voting stock held by nonaffiliates of the
registrant was $1,277,206,731 at March 18, 1996.
On March 18, 1996, the Company had 54,632,075 shares of common stock
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
(1) Notice of 1996 Annual Meeting of Shareholders and Proxy Statement,
pages 1- 17, is incorporated into Part III of this report.
PART I
ITEM 1. BUSINESS
GENERAL - INDUSTRY SEGMENTS: The Montana Power Company (the Company) and
its subsidiaries engage in a number of diversified and energy related
businesses. The Company's principal business, which is conducted through its
Utility Division, includes regulated utility operations involving the
generation, purchase, transmission and distribution of electricity and the
production, purchase, transportation and distribution of natural gas. The
Company, through its wholly-owned subsidiary, Entech, Inc. (Entech), engages in
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. The Company, through its Independent Power Group (IPG) manages long-
term power sales, and develops and invests in nonutility power projects and
other energy-related businesses. See Item 8, "Financial Statements and
Supplementary Data - Note 10 to the Consolidated Financial Statements" for
further information. A group of officers and employees of the Company
constitute the Office of the Corporation, 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.
UTILITY DIVISION:
SERVICE AREA AND SALES: The Utility Division's service territory
comprises 107,600 square miles or approximately 73% of Montana. Within its
service territory, 86% of the state's population resides. The Division serves
approximately 606,000 residents, or 81% of the population within the service
territory. Additionally, energy is provided to cooperatives that serve
approximately 72,000 residents. Dominant factors in Montana's diversified
economy are agriculture and livestock, which constitute Montana's largest
industry, tourism and recreation, coal and metals mining, oil and gas
production, and the forest products industry which includes the production of
pulp and paper, plywood and lumber.
Electric service is provided to 191 communities, the rural areas
surrounding them and Yellowstone National Park, and natural gas service is
provided to 109 communities. Firm electric power is sold at wholesale to two
rural electric cooperatives. Natural gas is sold at wholesale or transported
to distribution companies in Great Falls, Cut Bank, Shelby, Kevin, Sweetgrass
and Sunburst, Montana.
COMPETITIVE ENVIRONMENT: The electric and natural gas utility
businesses are in transition to a competitive market.
Recent federal legislation has opened the Utility Division's electric
wholesale business to competition from other suppliers. While its retail
business is now free from competition, the Montana Public Service Commission
(PSC) has initiated consideration of a transition to retail competition. The
Company is preparing for such competition.
The Utility Division offers its large customers the option of purchasing
their own natural gas supplies, which the Division will transport to these
customers. While its other natural gas customers do not have this choice, the
Company is preparing for its extension to all customers.
Competition in both the electric and natural gas utility businesses has
been heightened in the Northwest by an abundance of low cost electric and
natural gas supplies, which the Company expects to continue through the end of
the century.
In March 1995, the Federal Energy Regulatory Commission (FERC) issued a
Notice of Proposed Rulemaking (NOPR) on Open-Access Non-Discriminatory
Transmission Services by Public and Transmitting Utilities and on Recovery of
Stranded Costs. The NOPR would require utilities to file non-discriminatory
tariffs available to all wholesale buyers and sellers of electricity, require
utilities to use those tariffs for their own wholesale sales and purchases,
and allow utilities to recover stranded costs. A final rule is expected in
1996. The Company has filed open-access transmission tariffs with FERC and
applied for authorization to create an affiliated power marketing subsidiary.
Central Montana Electric Power Cooperative, Inc. (Central), which
manages a contract for purchases of power from the Utility Division by a group
of Montana cooperatives, provides an example of the growing competition for
wholesale customers. Central has given notice of termination, effective in
June 2000, of this contract, which, during 1995, accounted for 4% of the
electric energy sold by the Utility Division. The Utility Division and other
electric suppliers are in the process of bidding for the cooperatives' power
requirements beyond June 2000. The Company is planning to request FERC to
authorize recovery of costs which will be stranded by the termination of this
contract. The Company cannot predict the extent of stranded cost recovery.
Among other steps the Company has taken to position itself to meet
competition, it has joined two regional transmission groups, the Western
Regional Transmission Association, currently comprised of 63 members; and the
Northwest Regional Transmission Association, currently comprised of 18
members. These groups, whose memberships include transmission owning
utilities, transmission dependent utilities, non-utility generators, and
others, were formed to take advantage of the benefits that might arise through
joint transmission planning and operation and regional transmission tariff and
pricing developments.
The PSC has initiated an inquiry into the restructuring of the electric
industry in Montana. The Company is participating in these proceedings and
plans to file an electric restructuring case with the PSC in the fall of 1996.
The Company has been ordered by the PSC to file a consolidated natural
gas structural and cost allocation case in July 1996. This filing will
address such issues as transportation thresholds, stranded costs, utility gas
production costs and rates charged to various customer classes. The Company
anticipates that all customers should and will be able to choose a natural gas
supplier after a transition period.
These changes in the utility and energy industries have prompted the
Company to re-evaluate the basic structure of its operations to meet the
challenges ahead. The Company is realigning its businesses into two
divisions. An energy supply division will be responsible for coal, oil and
natural gas, and power generation including marketing, brokering and wholesale
business development. An energy services and communications division will
engage in the transmission and distribution of electricity and gas as well as
telecommunications, energy management services and retail business
development. The Company believes this structure will accommodate its
businesses, yet be flexible enough to fit anticipated federal and state
mandates. The new structure is being put in place in 1996 and contemplates a
five to ten year transition period before open-access will be available to all
customers. At the end of the transition period, generation and gas supply
would be fully deregulated.
REGULATION AND RATES: The Company's public utility business in Montana
is subject to the jurisdiction of the PSC. The PSC has jurisdiction over the
issuance of securities by the Company. FERC also has jurisdiction over the
Company, under the Federal Power Act, as a licensee of hydroelectric projects
and as a public utility engaged in interstate commerce. The importation of
natural gas from Canada requires approval by the Alberta Energy Resources
Conservation Board, the National Energy Board of Canada and the United States
Department of Energy
On April 25, 1995, the PSC approved an electric rate increase of
$13,900,000, on an annual basis, effective May 1, 1995. This increase affirmed
a settlement with intervenors and included $7,700,000 which had been authorized
on November 28, 1994 on an interim basis. The final order did not identify an
allowed rate of return.
On September 21, 1995, the Company filed a request with the PSC to
increase both electric and natural gas rates. The Company also offered a
preferred three-year 'alternative' rate plan. The filing, as adjusted,
requests an additional $27,500,000 (7.80%) for electric revenues and $9,200,000
(7.34%) for natural gas revenues, based upon a 12.0% return on equity.
Requested interim increases were $11,000,000 for electricity and $4,400,000 for
natural gas. On February 14, 1996, the PSC granted interim increases of
$5,800,000 for electricity and $3,100,000 for natural gas, effective March 1,
1996.
The 'alternative' plan would establish rates for the next three years
thus eliminating conventional filings until 1998. The 'alternative' plan
includes predetermined rate adjustments. The plan is intended to allow the
Utility to maintain financial integrity while providing time for parties
usually involved in rate proceedings, including the Company, the PSC and
intervenors, to deal with issues related to changes in the utility industry.
The 'alternative' plan's three year rate increases, as adjusted, would
provide the following additional electric and natural gas revenues:
Three Year Plan Electric Natural Gas
Effective July 1996 $19,600,000 $ 7,700,000
Effective January 1997 10,400,000 3,800,000
Effective January 1998 10,700,000 4,100,000
Hearings on the rate filing are scheduled to begin in April 1996 and a
decision is expected in June.
On December 15, 1995 the Company filed with the PSC its annual gas cost
tracking application, reflecting a net decrease of $5,100,000 in annual natural
gas revenues in response to reduced operating costs. This rate change will not
affect the Company's overall net income.
In 1995, the Company and Central negotiated a $960,000 annual rate
increase adjustment for the 1995 rate period and agreed to continue an annual
rate review/adjustment process.
ELECTRIC UTILITY OPERATIONS: The maximum demand on the resources in 1995
was 1,350,000 kW on February 13, 1995. Total firm capability of the Utility's
electric system for 1995 was 1,703,000 kW (including resources added in late
1995). Of this capability, 1,227,000 kW was provided by the Utility's
generating facilities, and 476,000 kW was provided by firm Electric Utility
power purchase and exchange arrangements. The Electric Utility's reserve
margin on February 13, 1995, as a percentage of maximum demand, was 19%.
The Company's future need for electric resources is to meet winter peak
requirements. Future power needs could change depending on wholesale wheeling
customer gains or losses, and changes that retail wheeling would cause, if it
occurs. In 1995, the electric utility's resource capability was increased by
the Thompson Falls 41,000 kW hydroelectric upgrade and a 57,000 kW power
purchase from Billings Generation Inc. The Billings Generation Inc. purchase
is being acquired under a PURPA Qualifying Facility (QF) contract. In 1996,
two purchase power contracts totaling approximately 150,000 kW will terminate.
As part of its planning activities, the Company biannually prepares an
Electric Least Cost Resource Plan (Plan), which is filed with the PSC. The
document identifies the Company's expectations for load and energy requirements
as well as the resources expected to meet those requirements. The plan, which
is prepared with input from low income, large user and environmental groups,
considers societal and environmental costs in addition to actual dollar costs.
The plan is referred to as "dynamic" indicating that it is responsive to
change. A comparison of the 1993 plan to the 1995 plan demonstrates the
changes taking place as a result of competition. The comparative costs of
specific resources have changed drastically in two years with wholesale
purchases becoming a cheaper resource. The plan has been modified to rely more
heavily on purchases to meet peak demand. As a result, future demand side
management expenditures have been reduced and expansion of Company owned
generating facilities has been postponed.
ITEM 1. BUSINESS (Continued)
During the year ended December 31, 1995, the sources of the Utility
Division electric supply were: hydro, 32%; coal, 44%; and purchased power,
24%. The cost of coal burned has been as follows:
Year Ended December 31
1995 1994 1993
Average cost per million Btu's $ 0.56 $ 0.66 $ 0.65
Average cost per ton (delivered) 9.67 11.24 11.16
The average cost of coal declined in 1995 due to the Colstrip Units 1
and 2 Coal Supply Agreement arbitration decision and reduced generation at the
incrementally more expensive Colstrip Unit 3. See Item 8, "Financial
Statements and Supplementary Data - Note 2 to the Consolidated Financial
Statements."
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 74 member systems and
11 affiliates in the 14 western states, British Columbia, Alberta and Mexico to
assure reliability of operations and service to their customers; is one of
97 members of the Western Systems Power Pool, organized to enhance the
economics of power production and reliability of service among the western
states power systems; and is a party to the Intercompany Pool Agreement for the
coordination of load, resource and transmission planning, operations and
reserve requirements among eight utilities in Washington, Oregon, Idaho,
Montana, Wyoming, Nevada and Utah. The Company participates in an
interconnection agreement with The Washington Water Power Company, Idaho Power
Company, and PacifiCorp, providing for the sharing of transmission capacity of
certain lines on their respective interconnected systems. The Company also
operates, in coordination with its own transmission lines and facilities, the
transmission lines and facilities which are jointly owned by the utility owners
of the four Colstrip generating units. The Company and the Western Area Power
Administration have transmission interconnection and agreements which provide
for the mutual use of excess capacity of certain lines on each party's system
for the transmission of power east of the Continental Divide in Montana and for
the firm use of certain of the Company's transmission lines to deliver
government power.
NATURAL GAS UTILITY OPERATIONS: Natural gas supply requirements in 1995
totaled 21,173 Mmcf, of which 12,792 Mmcf were from Montana and 8,381 Mmcf from
Canada. The Gas Utility produced 43% of the Montana natural gas and its
Canadian subsidiaries produced 64% of the Canadian natural gas.
The Company implemented open-access gas transportation on November 1,
1991. As of September 1993, substantially all eligible customers were
acquiring 100% of their gas supplies directly from other suppliers. The Gas
Utility transports gas supplies for these customers. The total volumes of
natural gas transported were 26,700 Mmcf, 23,700 Mmcf and 17,900 Mmcf for 1995,
1994 and 1993, respectively.
Total 1996 natural gas requirements, estimated to be 21,870 Mmcf, are
anticipated to be supplied from existing reserves and purchase contracts.
Approximately 12,563 Mmcf of these requirements are expected to be obtained in
the United States and 9,307 Mmcf from Canada. The Gas Utility expects to
produce 45% of the Montana natural gas and 53% of the Canadian natural gas. The
1996 transportation volumes are anticipated to be 26,800 Mmcf.
Exportation of natural gas from Canada is controlled by the Canadian
provincial and federal governments. The Company has a long-term export license
which entitles it to export up to 10,000 Mmcf annually through October 2006.
ENTECH:
GENERAL: Entech conducts its businesses through various subsidiaries. It
also owns a passive investment in a gold mine in Brazil.
Entech's 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. 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) markets coal, and 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. See Item 7,
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Entech Operations - Coal Operations - 1995 Compared to 1994 -
Expenses" and Item 8, "Financial Statements and Supplementary Data - Note 11 to
the Consolidated Financial Statements."
Entech's oil and natural gas business is conducted in the United States
through North American Resources Company (NARCO) and in Canada through both
Altana Exploration Company (Altana) and Roan Resources, Ltd. (Roan).
Entech's telecommunication business is conducted through Touch America,
Inc. Touch America offers three primary services to customers: equipment,
private lines and long distance services.
Entech's other businesses are conducted by various subsidiaries, none of
which is a significant subsidiary.
COMPETITIVE ENVIRONMENT: The Rosebud Mine faces competition from the
Montana and Wyoming Powder River Basin producers. The Montana and Wyoming
producers generally experience lower stripping ratios, royalties and
production taxes. Additionally, the Wyoming coal is a lower sulfur coal. The
Midwestern coal contracts that expired were not extended due to the extremely
low prices of competing coals. The Rosebud Mine does have a stable future due
to the long-term contracts to supply the mine-mouth Colstrip units. The Jewett
Mine sells its entire production under an exclusive supply contract to the two
750 megawatt Limestone Units. In 1996, substantially all of the Company's
coal and lignite production is expected to be sold under long-term exclusive
supply contracts.
The Oil Division competes in the areas of property acquisitions and the
development, production and marketing of oil and natural gas, as well as
contracting for equipment and securing personnel, with major oil and natural
gas companies, other independent and individual producers and operators. The
Oil Division believes that its production and development capabilities, long-
term marketing abilities, experience in acquiring properties, and financial
resources enable it to compete effectively.
The Telecommunications Division 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. The
Telecommunication Division provides services in the regional marketplace and
has made economic investments which allow it to compete effectively.
COAL OPERATIONS: Western's Rosebud Mine is at Colstrip, Montana, in the
northern Powder River Basin, where coal is surface-mined and, after crushing,
sold without further preparation, principally for use by electric utilities in
steam-electric generating plants. Western's principal customers from this mine
are the owners of the four mine-mouth Colstrip units, the SynCoal plant, and
the Utility Division's Corette Plant located in Billings, Montana. These
customers accounted for approximately 79% of 1995 coal sales. The remainder of
Rosebud coal was sold under spot-market sale agreements and contracts in
Michigan, Minnesota, North Dakota, Wisconsin and Montana. The Midwestern
contracts made up 18% of 1995 coal sales of which one representing 9% expired
and was not renewed at the end of 1995.
During 1995, Western mined and sold 11,493,179 tons, of which 3,462,483
tons were sold to the Company. Western's Rosebud Mine production is estimated
to be 8,000,000 tons in 1996, as a result of the Colstrip Units 3 & 4 reduced
coal purchases, and 10,325,000 tons in 1997. Coal production in 1996 is
expected to be lower due to the availability of hydroelectric generation in the
Pacific Northwest, expiration of a Midwestern customer contract at the end of
1995 and reduced sales to the Corette Plant.
Northwestern's Jewett Mine is located between Dallas and Houston, Texas.
Northwestern supplies lignite under a long-term contract to the two electric
generating units, located adjacent to the mine, that are owned by Houston
Lighting and Power Company. Total deliveries in 1995, were 8,268,149 tons. The
estimated production for 1996 and 1997 are 8,200,000 and 8,400,000 tons,
respectively. After 1997, production is estimated to be approximately 8,500,000
tons annually.
Basin's underground Golden Eagle Mine is located near Trinidad, Colorado.
Total deliveries from the mine were 872,043 tons during 1995. As discussed
above under "General", Basin ceased production in December 1995.
OIL AND GAS OPERATIONS: The Oil and Gas Division is 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
126,000 Mmcf of natural gas to four co-generation facilities over a period of 9
to 15 years with performance guaranteed by Entech. NARCO has sufficient
proven, developed and undeveloped reserves to supply all of the remaining
natural gas required by those agreements. None of the reserves are dedicated
to supply these agreements.
Natural gas production in both the United States and Canada is currently
sold pursuant to short-term, spot-market and long-term contracts. Approximately
18,960 Mmcf, or 30.3% of Altana's and Roan's natural gas reserves, are
dedicated to long-term contracts expiring at various times through 2005.
Through a subsidiary, Entech owns a minority interest in a joint venture
to construct the proposed Altamont pipeline. In 1991, Altamont received FERC
approval to construct a 620 mile pipeline running from the Alberta-Montana
border to Muddy Creek, Wyoming. The decision to proceed with the construction
of this pipeline will depend upon obtaining the necessary regulatory approval
and shipper commitments by July 1996 unless approval is extended.
TELECOMMUNICATIONS: Touch America's network provides long distance and
private line sales and services to customers in Montana, Idaho, Washington and
Oregon. The telecommunications system includes private, dedicated
communication lines throughout Montana on a digital microwave and fiber
network. Touch America is currently in the process of installing a fiber optic
cable in Montana, Wyoming and Colorado that is expected to be in service in
early 1997. This cable will connect to other carriers to provide interstate and
international communications.
Touch America sells, installs and maintains telephone equipment in the
states of Montana, Idaho, Washington, Oregon and Wyoming. Touch America
markets and maintains PBX and key systems, call accounting systems and voice
mail systems.
Touch America provides telecommunication services to over
12,000 customers.
INDEPENDENT POWER GROUP:
GENERAL: The Independent Power Group (IPG), which consists of
Continental Energy Services, Inc. (CES) and Colstrip 4 Lease Management
Division, manages sales of the Company's 210 megawatt share of Colstrip Unit 4
generation to the Los Angeles Department of Water and Power and to Puget Sound
Power & Light Company (Puget) under contracts which are coextensive with the
Company's leasehold interest in the Unit.
Through CES, the IPG has invested in six operating, natural gas fired,
independent power projects located in Texas, New York, Washington and the
United Kingdom, one heavy oil-fired project in Jamaica, and one independent
power project under construction in Texas. In addition to other project
acquisition and development activities, CES is participating with others in the
development of a coal-fired project in India. In early 1996, the IPG elected
to withdraw from the development of a coal-fired project in China.
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 and an arbitration involving the
termination of a contract for power from a plant under construction at
Frederickson, Washington.
ENVIRONMENT:
The information required in this section is contained in Item 7,
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" under "Environmental Issues."
EMPLOYEES:
At December 31, 1995, the Company and its subsidiaries employed
3,278 persons of which 2,112 were utility and Office of the Corporation
employees (including 511 employees at the jointly owned Colstrip Units 1-4),
9 Independent Power Group employees and 1,157 Entech 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 DIVISION:
ELECTRIC PROPERTIES: The Company's Utility Division electric system
extends through the western two-thirds of Montana. Generating capability is
provided by four coal-fired thermal generation units, with total net capability
available to the Utility of 697,000 kW, and 12 hydroelectric projects, with
total net capability of 530,000 kW. The thermal units are (1) Colstrip Unit 3,
which has a net capability of 727,000 kW, of which the Company owns 218,000 kW,
(2) Colstrip Units 1 and 2, with a combined net capability of 638,000 kW, of
which the Utility owns 319,000 kW, and (3) the 160,000 kW wholly-owned Corette
Plant. All of the Utility's Colstrip coal requirements are supplied by Western
Energy Company under long-term contracts. Reliability of service is enhanced
by the location of hydroelectric generation on two separate watersheds with
different precipitation characteristics and by various sources of thermal
generation.
In addition to the Utility's hydroelectric and thermal resources, it
currently receives power through 22 power contracts totaling 476,000 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, 1995, the Utility owns and operates 6,911 miles of
transmission lines and 15,255 miles of distribution lines.
NATURAL GAS PROPERTIES: The Utility produces natural gas from fields in
Montana and Wyoming and through its subsidiary, Canadian-Montana Gas Company,
from fields in southeastern Alberta, Canada. Natural gas is also purchased
from independent producers in Montana and Alberta.
All of the Utility's natural gas customers are served from its
transmission system which extends through the western two-thirds of Montana.
System reliability is enhanced by four natural gas storage fields which enable
the Utility to store natural gas in excess of system load requirements during
the summer for delivery during winter periods of peak demand.
At December 31, 1995, the Gas Utility and its subsidiaries owns and
operates 2,070 miles of natural gas transmission lines and 3,219 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, 1995,
controlled under purchase contracts, 60,116 Mmcf of proven reserves in the
United States and 27,999 Mmcf in Canada. No significant change has occurred
and no event has taken place since December 31, 1995, 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:
<TABLE>
<CAPTION>
United States Canada
Produced Royalty Purchased Produced Royalty Purchased
<S> <C> <C> <C> <C> <C> <C>
1993 5,587 539 8,554 3,927 1,186 2,824
1994 4,724 230 7,565 3,350 998 2,709
1995 5,176 632 7,292 4,650 735 3,031
</TABLE>
The following table presents information as of December 31, 1995,
concerning the Utility natural gas wells and the owned or leased acreages in
which they are located.
United States Canada
Gross productive wells 616 177
Net productive wells 503 166
Gross wells with multiple completions 19 11
Net wells with multiple completions 13.8 10.5
Gross producing acres 387,149 154,716
Net producing acres 294,756 137,808
Gross undeveloped acres 32,776 79,360
Net undeveloped acres 27,313 72,752
These acreages are located primarily in Montana and Alberta, Canada.
The Company anticipates that during 1996 total exploration and
development expenditures (expense and capital) will be approximately $1,300,000
in the United States and approximately $1,700,000 in Canada.
The following table presents information on utility natural gas
exploratory and development wells drilled during 1995, 1994 and 1993.
United States Canada
1995 1994 1993 1995 1994 1993
Net productive exploratory
wells - - - - - -
Net dry exploratory wells - - - - - -
Net productive development
wells 14.81 14.38 12.25 4.00 6.00 -
Net dry development wells 1.60 4.00 2.00 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 1995,
1994 and 1993. Revenues per Mcf are computed based on volumes at varying
pressure bases as billed.
Year Ended December 31
Customer Classification 1995 1994 1993
Residential $ 4.74 $ 4.64 $ 4.35
Commercial 4.54 4.43 4.20
Industrial 4.33 4.25 4.02
Other gas utilities 3.64 3.72 3.38
The following table presents the average production cost per Mcf for
produced utility natural gas, in U. S. dollars, for the three years 1995, 1994
and 1993.
United States Canada
1993 $ 0.89 $ 0.36
1994 1.01 0.40
1995 1.10 0.34
Changes in operational practices will cause the price per unit to
fluctuate.
ENTECH:
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 on December 29, 1995.
Management is attempting to sell these reserves.
Western has coal mining leases covering approximately 536,000,000 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 200,000,000 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 223,000,000 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.
In 1990, Northwestern acquired surface rights and coal leases which
contain approximately 628,000,000 proved and probable, and recoverable, tons of
compliance quality surface-mineable coal reserves in the southern Powder River
coal region located near Gillette, Wyoming. In January 1993, an adjacent
federal lease was acquired which contains approximately 56,000,000 proved and
probable, and recoverable tons of compliance quality coal reserves. The coal
reserves average less than 0.6 pounds of sulfur per million BTU (compliance
quality). The application with the Department of Interior to combine these
leases into one logical mining unit, which was granted in December 1993,
requires the property to be developed by 2002. A permit application was
submitted to the Wyoming Department of Environmental Quality in November 1994.
The leases were transferred to Horizon in the fourth quarter 1995. Horizon
expects to receive the mine permit by the third quarter of 1996. No definite
plans for mine development have been made.
Horizon's undeveloped mining leases in southeastern Alabama and central
Texas were released at the end of 1995.
OIL AND NATURAL GAS PROPERTIES: No significant change has occurred and
no event has taken place since December 31, 1995, which would materially affect
the estimated quantities of proved reserves. For information pertaining to net
recoverable Entech oil and natural gas reserves, see Item 8, "Financial
Statements and Supplementary Data."
All Entech natural gas volumes are at a pressure base of 14.73 psia at
60 degrees Fahrenheit.
Entech 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 1995, 1994 and
1993.
<TABLE>
<CAPTION>
Year Ended December 31
1995 1994 1993
United United United
States Canada States Canada States Canada
<S> <C> <C> <C> <C> <C> <C>
Average sales price:
Per Mcf of natural gas $ 1.21 $ 0.99 $ 1.60 $ 1.48 $ 1.84 $ 1.25
Per barrel of oil 16.55 15.29 14.75 12.95 17.61 14.21
Per barrel of natural gas liquids 8.17 11.33 9.50 9.99 10.98 11.66
</TABLE>
Average production cost:
Per barrel of oil equivalent $ 3.36 $ 2.90 $ 3.00 $ 2.93 $ 3.84 $ 3.02
Natural gas production was converted to barrel of oil equivalents based
on a ratio of 6 Mcf to 1 barrel of oil.
Entech's oil, natural gas and natural gas liquids production was sold
under short-term and long-term contracts at posted prices or under forward
market arrangements. From 1994 to 1995, Entech's average sales prices changed
due to fluctuations in the market. Entech's average production cost in the
U.S. reflects higher lease operating expenses due to declining production in
older fields and startup waterflood injection costs. Increased production from
this waterflood is expected in late 1996.
Information on Entech natural gas and oil wells and the owned or leased
acreage in which they are located, as of December 31, 1995, is presented below.
United
States Canada
Gross productive natural gas wells 474 134
Net productive natural gas wells 299.53 83.65
Gross productive oil wells 253 181
Net productive oil wells 184.29 96.49
Gross producing acres 209,505 152,453
Net producing acres 80,332 75,359
Gross undeveloped acres 264,212 240,567
Net undeveloped acres 146,011 162,639
The wells located in Canada include multiple completions of 8 gross
productive natural gas wells and 6.70 net productive gas wells.
The foregoing acreage located in the United States and Canada are
primarily in the Rocky Mountain states and Alberta.
It is anticipated that during 1996 total exploration, acquisition and
development expenditures (expense and capital) will be approximately
$19,532,000 in the United States and approximately $11,780,000 in Canada.
The following table presents information on Entech oil and natural gas
exploratory and development wells drilled during 1995, 1994 and 1993.
<TABLE>
<CAPTION>
United States Canada
1995 1994 1993 1995 1994 1993
<S> <C> <C> <C> <C> <C> <C>
Net productive natural gas
exploratory wells 2.99 1.15 1.25 0.50 0.87 0.87
Net productive oil
exploratory wells 1.00 - 3.00 - - 1.04
Net productive natural gas
development wells 6.23 6.28 32.16 - 1.06 5.70
Net productive oil
development wells 1.34 1.29 4.12 7.38 8.67 6.56
Net dry exploratory wells 2.50 3.44 2.79 1.69 2.00 5.92
Net dry development wells 4.24 0.59 2.76 0.50 3.05 3.00
</TABLE>
For information on properties acquired, see Item 8, "Financial Statements
and Supplementary Data."
INDEPENDENT POWER GROUP:
The IPG manages the sale of power from the Company's 210 MW Colstrip 4
leased interest and associated common and transmission facilities. The IPG
also has ownership or contract rights in a number of nonutility power
generation projects:
<TABLE>
<CAPTION>
Projects in Operation:
IPG
Share
of
Rated Rated
Location Capa- Capa-
(Commercial Ownership city city Customer
Project Operation) or Interest MW MW Electricity Thermal
<S> <C> <C> <C> <C> <C> <C>
Encogen One Sweetwater, TX 49.5% 255 126 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
Jamaica Barge Old Harbour, 17.6% 74 13 Jamaica Public None
Jamaica Service
(1995)
(1) These co-generation facilities have a long-term contract with NARCO (an Entech
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.
</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
Tenaska- Cleburne, TX 25.0% 258 65 Brazos REA Distilled
Cleburne (1997) Water Plant
(3) Construction is 50% complete but has been suspended due to a dispute with the
Bonneville Power Administration (BPA). See Item 8, "Financial Statements and
Supplementary Data - Note 2 to the Consolidated Financial Statements".
</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>
India- State of Andhra (4) 500 (4) State of Andhra None
Krishnapatnam Pradesh Pradesh
(4) Not determinable at this time.
</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
Corporate Officers:
In 1992, D. T. Berube, 62, was elected Chairman of the Board and Chief
Executive Officer. He served as President and Chief Operating Officer, Entech,
Inc., 1988-1991.
On January 23, 1996, R. P. Gannon, 51, was elected Vice Chairman and
President. He has been President since 1990. He was Chief Operating Officer -
Utility Division from 1990-1996.
In 1991, J. P. Pederson, 53, was elected Vice President and Chief
Financial Officer. He served as Vice President Corporate Finance 1990-1991.
In 1993, P. K. Merrell, 43, was elected Vice President and Secretary. She
served as Staff Attorney 1981-1991, Assistant Secretary 1991-1992, and
Secretary 1992-1993.
In 1991, M. E. Zimmerman, 47, was elected Vice President and General
Counsel. He served as General Counsel from 1989-1991.
Utility Division Officers:
On January 23, 1996, J. D. Haffey, 50, 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 1994, A. K. Neill, 58, was elected Executive Vice President -
Generation and Transmission. He had previously served as Executive Vice
President - Utility Services from 1987-1994.
In 1993, D. A. Johnson, 51, was elected Vice President - Utility
Services. He had previously served as Vice President - Gas Supply and
Transportation for the Utility Division from 1984-1993.
In 1993, C. D. Regan, 59, was elected Vice President - Natural Gas Supply
and Transportation. He had previously served as Vice President - Energy
Services for the Utility Division from 1986-1993.
On July 17, 1995, M. C. Enterline, 47, was elected Vice President -
Colstrip Project Division for the Utility Division. He had previously served
as Manager of Business and Change Management from 1994-1995 and was
Superintendent of Colstrip Units l and 2 from 1988-1994.
In 1993, W. C. Verbael, 58, was elected Vice President - Accounting,
Finance and Information Services. He had previously served as Vice President -
Accounting and Finance for the Utility Division from 1984-1993.
In 1993, P. J. Cole, 38, was elected Treasurer for the Utility Division.
He served as Manager, Corporate Financial Planning and Analysis 1986-1992, and
as Assistant Treasurer 1992-1993.
In 1990, J. S. Miller, 52, was elected Controller for the Utility
Division.
Entech Officers:
In 1992, J. J. Murphy, 57, was elected President and Chief Operating
Officer - Entech, Inc. He served as President and Chief Operating Officer,
Western Energy and Northwestern Resources Co., 1988-1991.
In 1985, E. M. Senechal, 46, was elected Vice President and Treasurer -
Entech, Inc.
Independent Power Group Officer:
In 1992, R. F. Cromer, 50, was elected President and Chief Operating
Officer - Continental Energy Services, Inc. He served as Vice President and
General Manager, Continental Energy Services 1989-1992.
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
1995 and 1994. The number of common shareholders of record on December 31,
1995, was 42,441.
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
Dividends
Declared
per
1994 High Low Share
1st quarter $ 25.875 $ 23.250 $ 0.40
2nd quarter 25.000 22.125 0.40
3rd quarter 24.625 21.750 0.40
4th quarter 24.000 22.250 0.40
ITEM 6. SELECTED FINANCIAL DATA
The Montana Power Company and Subsidiaries
Balance Sheet Items (000)
1995 1994 1993
Assets:
Utility plant $2,205,564 $2,071,749 $1,943,428
Less accumulated depreciation
and depletion 663,215 619,195 572,141
Net Utility plant 1,542,349 1,452,554 1,371,287
Entech property 559,722 530,167 526,692
Less accumulated depreciation
and depletion 232,947 189,926 182,129
Net Entech property 326,775 340,241 344,563
Independent Power Group property 72,179 70,132 70,077
Less accumulated depreciation 19,666 17,560 16,822
Net Independent Power Group 52,513 52,572 53,255
Total net plant and property 1,921,637 1,845,367 1,769,105
Other assets 664,454 667,330 616,922
Total Assets $2,586,091 $2,512,697 $2,386,027
Liabilities:
Common shareholders' equity $ 976,043 $ 988,100 $ 945,651
Unallocated stock held by Trustee
for Deferred Savings and ESOP (30,565) (32,580) (34,419)
Preferred stock 101,416 101,416 101,419
Long-term debt 616,574 588,876 571,870
Other liabilities 922,623 866,885 801,506
Total Liabilities $2,586,091 $2,512,697 $2,386,027
ITEM 6. SELECTED FINANCIAL DATA
The Montana Power Company and Subsidiaries
Balance Sheet Items (000)
1992 1991 1990
Assets:
Utility plant $1,854,297 $1,774,185 $1,712,255
Less accumulated depreciation
and depletion 533,216 495,720 468,201
Net Utility plant 1,321,081 1,278,465 1,244,054
Entech property 482,732 464,978 403,169
Less accumulated depreciation
and depletion 163,185 144,691 124,309
Net Entech property 319,547 320,287 278,860
Independent Power Group property 69,805 66,477 66,507
Less accumulated depreciation 15,090 11,633 10,583
Net Independent Power Group 54,715 54,844 55,924
Total net plant and property 1,695,343 1,653,596 1,578,838
Other assets 590,079 564,450 537,686
Total Assets $2,285,422 $2,218,046 $2,116,524
Liabilities:
Common shareholders' equity $ 902,989 $ 862,601 $ 821,521
Unallocated stock held by Trustee
for Deferred Savings and ESOP (36,098) (37,631) (39,031)
Preferred stock 51,984 51,984 51,984
Long-term debt 581,179 603,266 599,971
Other liabilities 785,368 737,826 682,079
Total Liabilities $2,285,422 $2,218,046 $2,116,524
Income Statement Items (000)
1995 1994 1993
Revenues $ 953,539 $1,005,970 $1,024,285
Expenses:
Operations 424,443 440,472 480,382
Maintenance 68,286 75,357 70,029
Selling, general and administrative 98,327 103,127 101,251
Taxes other than income taxes 89,858 99,200 92,430
Depreciation, depletion and
amortization 86,976 86,711 82,696
Writedowns of long-lived assets (a) 74,297
842,187 804,867 826,788
Income from operations 111,352 201,103 197,497
Interest expense and other income:
Interest 43,788 42,817 48,023
Other (income) deductions - net (10,947) (10,532) (11,857)
32,841 32,285 36,166
Income taxes 21,574 55,226 54,120
Net income 56,937 113,592 107,211
Dividends on preferred stock 7,227 7,227 4,353
Net income available for common stock $ 49,710 $ 106,365 $ 102,858
Net income per share of common stock:
Utility operations $ 1.22 $ 0.91 $ 1.07
Entech operations (0.38) 0.90 0.91
Independent Power Group operations 0.08 0.19 -
$ 0.92 $ 2.00 $ 1.98
Dividends declared per share of
common stock $ 1.60 $ 1.60 $ 1.585
Average shares outstanding (000) 54,121 53,125 52,040
(a) Refer to Item 8, "Financial Statements and Supplementary Data - Note 11
to the Consolidated Financial Statements."
Income Statement Items (000)
1992 1991 1990
Revenues $ 943,872 $ 889,254 $ 795,528
Expenses:
Operations 416,072 368,797 322,010
Maintenance 70,525 70,510 66,634
Selling, general and administrative 87,545 88,926 78,188
Taxes other than income taxes 94,328 86,428 82,418
Depreciation, depletion and
amortization 81,732 75,782 65,790
Writedowns of long-lived assets
750,202 690,443 615,040
Income from operations 193,670 198,811 180,488
Interest expense and other income:
Interest 49,166 52,897 53,537
Other (income) deductions - net (8,200) (10,194) (8,235)
40,966 42,703 45,302
Income taxes 45,639 50,393 40,206
Net income 107,065 105,715 94,980
Dividends on preferred stock 3,790 3,790 3,790
Net income available for common stock $ 103,275 $ 101,925 $ 91,190
Net income per share of common stock:
Utility operations $ 0.97 $ 0.98 $ 0.89
Entech operations 0.98 0.98 0.94
Independent Power Group operations 0.07 0.07 0.01
$ 2.02 $ 2.03 $ 1.84
Dividends declared per share of
common stock $ 1.55 $ 1.495 $ 1.435
Average shares outstanding (000) 51,126 50,317 49,657
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 1993 through
1995. Also presented are factors which are expected to have an impact on
operating results in the future.
Net Income Per Share of Common Stock:
The Company's net income available for common stock decreased to
$49,710,000 in 1995 compared to $106,365,000 and $102,858,000 in 1994 and 1993,
respectively. The following table shows the sources of consolidated net income
on a per share basis.
1995 1994 1993
Utility Operations $ 1.22 $ 0.91 $ 1.07
Entech (0.38) 0.90 0.91
Independent Power Group 0.08 0.19 -
$ 0.92 $ 2.00 $ 1.98
The decrease in 1995 consolidated net income was largely due to the
writedown of an investment in an underground mine in Colorado and the adoption
of a new financial accounting standard "Accounting for the Impairment of Long-
Lived Assets and for Long-Lived Assets to be Disposed Of" (SFAS No. 121). The
impairments, recorded as of October 1, 1995, resulted in an after tax charge to
income of approximately $46,000,000 or 85 cents per share. The after tax
writedown of the investment in the underground coal mine was $29,000,000 and of
certain other non-regulated coal, oil and gas properties was $17,000,000. For
further information concerning the mine closure see "Entech Operations - Coal
Operations - 1995 Compared to 1994 - Expenses."
Net income for 1995 was also adversely impacted by 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 Entech's earnings
by 18 cents. The lower contract price will reduce pre-tax consolidated net
income approximately $3,500,000 per year.
Utility operations benefited from a 16% increase in low-cost
hydroelectric generation in 1995. Favorable hydroelectric conditions increased
the availability of low-cost power in the regional energy market, displacing
higher cost thermal energy. These conditions and the arbitration decision
increased Utility earnings. Entech's earnings for the year also declined as
the result of reduced coal volumes sold due to the displacement of generation
at the Colstrip units by low-cost hydroelectric power and the expiration of a
Midwestern coal contract in 1994.
The hydroelectric conditions that displaced thermal generation and
reduced Entech's 1995 earnings are expected to continue into 1996.
The Independent Power Group's earnings were lower in 1995, reflecting the
absence of development revenues. Increased income from operating projects
partially offset this expected decrease.
Consolidated net income per share for 1994 increased due to higher
Independent Power Group earnings resulting from power project development
revenues and improved performance by the Colstrip units. Despite higher
revenues from rate increases, customer growth, increased industrial electric
loads and the Colstrip units' improved performance, the Utility Division
earnings were lower due to less favorable hydroelectric generation and
wholesale energy market conditions. Also contributing to the decrease in
earnings were increased property taxes, a regulatory disallowance on coal
purchases and warmer weather. Entech earnings were comparable to 1993. A 1993
non-recurring gain on the sale of an Entech Oil Division non-strategic asset
and losses at the underground mine in Colorado were offset by increased coal
sales from Montana and Texas mines.
<TABLE>
<CAPTION>
UTILITY OPERATIONS
Year Ended December 31
1995 1994 1993
Thousands of Dollars
<S> <C> <C> <C>
ELECTRIC UTILITY:
REVENUES
Revenues $ 422,019 $ 427,686 $ 426,746
Intersegment revenues 5,793 5,924 7,532
427,812 433,610 434,278
EXPENSES
Power supply 148,240 178,927 172,190
Transmission and distribution 26,916 27,566 28,109
Selling, general and administrative 41,932 46,134 43,284
Taxes other than income taxes 43,302 42,214 39,014
Depreciation and amortization 42,506 40,699 39,151
302,896 335,540 321,748
INCOME FROM ELECTRIC OPERATIONS 124,916 98,070 112,530
NATURAL GAS UTILITY:
REVENUES
Revenues (other than gas supply
cost revenues) 93,460 88,914 87,634
Gas supply cost revenues 21,660 18,191 23,062
Intersegment revenues 862 917 778
115,982 108,022 111,474
EXPENSES
Gas supply costs 21,660 18,191 23,062
Other production, gathering and exploration 9,662 8,882 9,331
Transmission and distribution 10,932 10,154 9,256
Selling, general and administrative 17,161 17,669 17,162
Taxes other than income taxes 14,841 13,708 12,715
Depreciation, depletion and amortization 10,793 9,842 9,006
85,049 78,446 80,532
INCOME FROM GAS OPERATIONS 30,933 29,576 30,942
INTEREST EXPENSE AND OTHER INCOME:
Interest 44,029 43,013 46,885
Other (income) deductions - net (5,417) (3,947) (839)
38,612 39,066 46,046
INCOME BEFORE INCOME TAXES 117,237 88,580 97,426
INCOME TAXES 44,047 33,171 37,364
UTILITY NET INCOME $ 73,190 $ 55,409 $ 60,062
</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, the temperatures in 1995
in the Company's service territory were equal to the historic average and
6% colder than 1994. Temperatures in 1994 were 13% warmer than 1993 and
6% warmer than normal.
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, 1995, there
was a surplus of energy in the region which caused lower wholesale and
purchased power prices. The Company believes that the wholesale power market
in 1996 will be as weak if not weaker than 1995.
During the fourth quarter of 1995, Rhone-Poulenc Basic Chemicals
(Rhone), one of the Company's largest retail electric customers, announced its
decision to cease operating its Montana plant. Rhone was receiving power
under a contract that was scheduled to end in June 1996. The termination had
been anticipated in the Company's resource plan for the last few years.
Advanced Silicon Materials, Inc. has selected Montana as the site for a
new silicon processing plant. The Company will provide electricity to this
plant commencing in 1998. The load for the new plant is expected to exceed
the load lost due to Rhone's shutdown. The negotiated rate for this customer
reflects competitive market conditions prevalent in the Northwest.
The Company is facing increased competition for its large industrial and
wholesale customers who are beginning to consider other sources for their
energy needs. To respond to this competition, the Company is realigning its
businesses into two divisions. An energy supply division will be responsible
for coal, oil and natural gas, and power generation including marketing,
brokering and wholesale business development. An energy services and
communications division will engage in the transmission and distribution of
electricity and gas as well as telecommunications, energy management services
and retail business development. The Company believes this structure will
accommodate its businesses, yet be flexible enough to fit anticipated federal
and state mandates. The new structure is being put in place in 1996 and
contemplates a five to ten year transition period before open-access will be
available to all customers. At the end of the transition period, power
generation and natural gas supply would be fully deregulated.
Summary of Significant Regulatory Matters:
On April 25, 1995, the PSC approved an electric increase of $13,900,000,
on an annual basis, effective May 1, 1995. This increase affirmed a settlement
with intervenors and included $7,700,000 which had been previously authorized
on an interim basis.
On September 21, 1995, the Company filed a request with the PSC to
increase both electric and natural gas rates. The Company also offered a
preferred three-year `alternative' rate plan. The filing, as adjusted,
requests an additional $27,500,000 (7.80%) for electric revenues and $9,200,000
(7.34%) for natural gas revenues, based upon a 12.0% return on equity.
Requested interim increases were $11,100,000 for electricity and $4,400,000 for
natural gas. On February 14, 1996, the PSC granted interim increases of
$5,800,000 for electricity and $3,100,000 for natural gas, effective March 1,
1996.
The 'alternative' plan would establish rates for the next three years
thus eliminating conventional filings until 1998. This plan is intended to
allow the Utility to maintain financial integrity while providing time for
parties usually involved in rate proceedings, including the Company, the PSC
and intervenors, to deal with issues related to changes in the utility
industry.
Electric Utility:
The following table shows year-to-year changes for the previous two
years, in millions of dollars, in the various classifications of electric
revenues (excluding intersegment revenues) and the related percentage changes
in volumes sold and prices received:
1995 1994
General business - revenue $ 12 $ 11
- volume (1)% 3 %
- price/kWh 4 % -
Other utilities - revenue $ (16) $ (9)
- volume (5)% (6)%
- price/kWh (17)% (5)%
Miscellaneous - revenue $ (2) $ (1)
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
the large industrial customer discussed previously.
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:
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 Megawatt Hours
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 84,939 99,147
Total Power Supply Expenses $ 148,240 $ 178,927
Cents per Kilowatt-Hour 1.360 1.612
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&2 and the Corette Plant. This price decrease was retroactive to July
1991, and current period expenses include 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.
Selling, general and administrative 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 is due to increased
property taxes resulting from property additions.
Depreciation and amortization expense increased as a result of additional
plant and property in service.
1994 Compared to 1993
Income from electric operations decreased due primarily to the less
favorable hydroelectric generation and wholesale market conditions partially
offset by higher rates and growth in customers.
Revenues:
Electric sales from general business customers increased $11,500,000
including an increase of $5,800,000 in revenues from industrial customers.
Industrial revenues increased due to a 5% increase in volumes sold, primarily
the result of additional equipment installed by several customers and demand
for irrigation because of dry summer weather. Growth in residential and
commercial customers and higher rates also contributed to the increase in
revenues. These increases were moderated by volume decreases resulting from
the warmer winter weather.
Electric revenues from sales to other utilities decreased $5,100,000 due
to a reduction in volumes and $4,300,000 due to a decrease in average price.
The decreases resulted from wholesale market conditions returning to near-
normal compared with better than average conditions experienced during the
first and fourth quarters of 1993.
Miscellaneous electric revenues decreased primarily due to reduced
wheeling revenues resulting from the previously discussed change in wholesale
market conditions.
Intersegment revenues decreased primarily due to lower volumes sold to
the IPG.
Expenses:
The following table shows the Company's sources of electricity and power
supply expenses (operation, fuel for electric generation, and maintenance) for
1994 and 1993.
1994 1993
Sources Megawatt Hours
Hydroelectric 2,999,396 3,560,915
Steam 4,909,852 4,542,100
Purchases and Other 3,193,522 3,186,025
Total Power Supply 11,102,770 11,289,040
Expenses Thousands of Dollars
Hydroelectric $ 18,395 $ 18,092
Steam 61,385 57,876
Purchases and Other 99,147 96,222
Total Power Supply Expenses $ 178,927 $ 172,190
Cents per Kilowatt-Hour 1.612 1.525
Steam generation and related fuel expense increased as a result of
improved performance at the Colstrip units which experienced outages in 1993.
Purchased power costs increased as a result of a 3% increase in average price
paid. Total power supply cost increased as a result of this price increase and
a change in the mix of the Utility's sources of energy. In 1994, a larger
portion of power supply was provided by steam generation which is incrementally
more expensive than hydroelectric generation.
The increase in selling, general and administrative results primarily
from a $1,800,000 increase associated with the recognition of postretirement
benefit expense in accordance with SFAS No. 106 commensurate with the approval
of rate treatment for this expense by the PSC in April 1994, a $500,000
increase related to insurance for postemployment disability-related benefits
and a $600,000 increase due to the costs associated with Colstrip housing
damages.
The increase in taxes other than income taxes is principally due to
increased property taxes resulting from property additions and higher mill
levies.
Depreciation and amortization expense increased as a result of
depreciation of additional plant and property in service.
Natural Gas Utility:
The following table shows year-to-year changes for the previous two
years, in millions of dollars, in the various classifications of natural gas
revenues (excluding intersegment revenues) and the related percentage changes
in volumes sold and prices received:
1995 1994
Revenues (other than gas
supply cost revenues)
Full requirement
customers -revenue $ 4 $ (3)
-volume 6 % (13)%
-price/Mcf - (11)%
Transportation -revenue $ - $ 3
-volume 16 % 33 %
-price/Mcf 3 % (3)%
Miscellaneous -revenue $ - $ 1
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 4% in the residential and commercial markets and
temperatures 6% 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.
Interruptible transportation revenues are fixed by the most recent rate
case. Amounts in excess of, or lower than, amounts considered in the rate
case, are deferred for treatment in a future rate filing. Transportation
volumes fluctuate with customer demand.
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 is due to increased
property taxes resulting from higher mill levies and property additions.
1994 Compared to 1993
Income from natural gas operations decreased primarily due to decreased
volumes resulting from warmer weather and increases in expenses other than gas
supply costs, the effects of which were moderated by higher rates.
Revenues:
Effective September 1, 1993 natural gas customers who consume more than
60,000 Mcfs annually (non full-requirements customers) are no longer required
to purchase any portion of their natural gas supply from the Company. All
eligible customers have chosen to convert their volumes to transportation
service only and have secured their own supply. The resulting decline in
natural gas revenue has been offset by revenues from transportation fees and
lower purchased gas costs.
Natural gas revenues (other than gas supply costs) increased $1,300,000.
Growth in the number of residential and commercial customers, higher rates and
increased transportation fees contributed $13,200,000. This increase was
mostly offset by an approximately $11,800,000 decrease due to warmer weather
and the previously discussed switch by eligible customers to transportation
service only.
Gas supply cost revenues consist of the amount authorized by the PSC to
be collected in rates from full requirement customers to cover the cost of
supplying the gas. The decrease in gas supply cost revenues is the result of
reduced volumes sold due to warmer weather and a supply cost rate reduction for
overcollections of supply costs in prior years. Gas supply cost revenues and
gas supply cost expenses are always equal due to rate and accounting
procedures.
Expenses:
The decrease in gas supply costs results from the reasons mentioned in
the gas supply cost revenue discussion.
The increase in taxes other than income taxes is principally due to
increased property taxes resulting from property additions and higher mill
levies.
Interest Expense and Other Income, and Income Taxes:
The change in interest expense from 1993 to 1995 is primarily the result
of refinancing long-term debt at lower interest rates partially offset by
increased average borrowings.
Other income increased in 1995 and 1994 due to separate non-recurring
events.
Income taxes changed due primarily to changes in pre-tax income.
<TABLE>
<CAPTION>
ENTECH OPERATIONS
Year Ended December 31
1995 1994 1993
Thousands of Dollars
COAL OPERATIONS:
<S> <C> <C> <C>
REVENUES
Revenues $ 207,517 $ 252,507 $ 225,155
Intersegment revenues 25,659 42,201 39,637
233,176 294,708 264,792
EXPENSES
Cost of sales 155,329 169,259 152,300
Selling, general and administrative 28,211 29,463 24,988
Taxes other than income taxes 27,210 37,733 34,221
Depreciation, depletion and amortization 11,187 12,649 10,193
Writedowns of long-lived assets 55,102
277,039 249,104 221,702
INCOME (LOSS) FROM COAL OPERATIONS (43,863) 45,604 43,090
OIL AND NATURAL GAS OPERATIONS:
REVENUES
Revenues 100,198 97,994 114,431
Intersegment revenues 241 254 741
100,439 98,248 115,172
EXPENSES
Cost of sales 60,526 54,283 71,311
Selling, general and administrative 9,320 8,514 8,549
Taxes other than income taxes 2,334 3,340 4,239
Depreciation, depletion and amortization 17,569 18,464 19,327
Writedowns of long-lived assets 19,194
108,943 84,601 103,426
INCOME (LOSS) FROM OIL AND NATURAL
GAS OPERATIONS (8,504) 13,647 11,746
OTHER OPERATIONS:
REVENUES
Revenues 26,308 24,164 24,252
Intersegment revenues 662 787 700
26,970 24,951 24,952
EXPENSES
Cost of sales 17,127 16,787 17,090
Selling, general and administrative 5,537 4,717 4,719
Taxes other than income taxes 343 287 473
Depreciation, depletion and amortization 1,745 1,945 2,133
24,752 23,736 24,415
INCOME FROM OTHER OPERATIONS 2,218 1,215 537
INTEREST EXPENSE AND OTHER INCOME:
Interest 4,596 1,425 2,284
Other (income) deductions-net (6,978) (3,517) (11,364)
(2,382) (2,092) (9,080)
INCOME (LOSS) BEFORE INCOME TAXES (47,767) 62,558 64,453
INCOME TAXES (27,248) 14,670 17,263
ENTECH NET INCOME (LOSS) $ (20,519) $ 47,888 $ 47,190
</TABLE>
ENTECH OPERATIONS:
Coal Operations:
1995 Compared to 1994
The net loss from coal operations resulted from the writedown of
Entech's investment in Basin, the implementation of SFAS No. 121, the results
of the Colstrip Units 1 & 2 arbitration decision, the expiration of a
Midwestern coal contract and decreased sales to Colstrip Units 3 & 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 & 2 and the Company's
Corette Plant decreased $27,000,000 as a result of the Colstrip Units 1 & 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 & 4 due to the
displacement of generation by lower cost hydroelectric generation. Revenues
decreased $11,600,000 due to the Midwestern contract expiration and $8,300,000
from Colstrip Units 3 & 4. Revenues decreased $5,000,000 due to the conclusion
of coal brokering agreements in December 1994. Brokered coal was sold at
cost. A second Midwestern contract that expired in December was not renewed,
and in 1996, revenues and volumes will be reduced by approximately $16,000,000
and 1,100,000 tons, respectively. At the Jewett Mine, revenues increased
$1,000,000 as a net result of $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.
Operating expenses at the Rosebud Mine in 1996 will decrease by
approximately $9,000,000 due to the loss of the second Midwestern contract.
Entech 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, Basin terminated the coal sales
agreement and ceased production at the end of 1995. The Mine will be
permanently closed at the end of the first quarter 1996 unless a viable buyer
is identified. To date, efforts to sell the Mine have been unsuccessful. In
the fourth quarter of 1995, Entech wrote down its investment in the Mine by
$46,500,000 before taxes. See Item 8, "Financial Statements and Supplementary
Data - Note 11 to the Consolidated Financial Statements" for further
discussion of asset impairment.
1994 Compared to 1993
Income from coal operations increased $2,500,000 as a result of increased
coal volumes sold.
Revenues:
Overall coal revenues, including intersegment revenues, increased
$30,000,000 over 1993 due to a 13% increase in volumes sold. Prices per ton
were substantially unchanged. Coal revenues increased $14,200,000 at the
Rosebud Mine due to increased volumes sold to the Colstrip units as compared to
1993 which were lower due to unplanned outages, and increased volumes sold to
the SynCoal demonstration plant. At the Jewett Mine, coal revenues increased
$3,300,000 due to increased volumes delivered to the mine-mouth plant.
Increased revenues of $12,900,000 at the Golden Eagle Mine resulted from
increased volumes sold to supply coal for a long-term supply contract and for
spot market sales. In July, the Mine began delivering coal under a long-term
contract to supply up to 1,200,000 tons of coal annually to a southeastern
utility.
Expenses:
Cost of sales increased $15,000,000 at the Golden Eagle Mine due to
increased volumes sold and higher costs per ton including those related to
unanticipated production problems in both the mining and the wash plant
operations. Also, cost of sales increased $2,000,000 at the Rosebud Mine as a
result of increased volumes sold. Selling, general and administrative expenses
increased $4,500,000 from legal fees incurred relating to coal contract price
arbitration and leasehold interest litigation, from the implementation of an
accounting pronouncement pertaining to postemployment benefits and from the use
of outside consultants. Taxes other than income taxes increased $3,500,000 due
to increased coal revenues. Depreciation and depletion increased $2,400,000
principally due to increased volumes sold and increased investment in the
operation at the Golden Eagle Mine.
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
(excluding intersegment revenues) and the related percentage changes in volumes
sold and prices received:
1995 1994
Oil -revenue $ 1 $ (7)
-volume (8)% (19)%
-price/bbl 17 % (11)%
Natural gas -revenue $ (10) $ -
-volume (8)% 7 %
-price/Mcf (23)% (4)%
Natural gas marketing -revenue $ 11 $ (9)
-volume 27 % (13)%
-price/Mcf (2)% (11)%
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 because
of low market prices. Revenues from natural gas marketing 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.
1994 Compared to 1993
Income from oil and natural gas operations increased $1,900,000 due to
higher profit margins realized on the natural gas marketing activity.
Revenues:
Oil revenues decreased $7,000,000 from both lower volumes sold due to
natural declining production and lower market prices received. Natural gas
revenues in Canada increased $3,500,000 from higher volumes sold as a result of
1993 development drilling and from higher market prices received. However,
natural gas revenues in the U.S. decreased $3,900,000 from lower market prices
received. Natural gas marketing revenues decreased $12,000,000 due to the
expiration of a short-term supply contract in 1993. The operating revenue
decrease was partially offset by the absence of losses of $3,200,000 as a
result of a marketing joint venture that was sold in December 1993.
Expenses:
Cost of sales decreased $17,000,000. This amount is comprised of
$14,700,000 decreased costs of natural gas purchased for resale because of
lower spot market prices and decreased natural gas marketing volumes sold in
the U.S., and $2,300,000 decreased operating costs resulting from the sale of a
non-strategic asset in the fourth quarter of 1993. The decrease of $900,000 in
taxes other than income taxes reflects lower revenues.
Other Operations:
1995 Compared to 1994
Income from other operations increased from telecommunications
operations and land sales.
Revenues:
Additional leased network capacity sold to private businesses and a 26%
increase in minutes sold to long-distance customers increased revenues from
Entech's other operations by $2,500,000. Additionally, revenues from land
sales increased $400,000. The increased revenues from telecommunications and
real estate were partially offset by $900,000 decreased revenues due to the
1995 completion of automated control systems contracts.
1994 Compared to 1993
Income from other operations increased $700,000 due to expanded
telecommunications services.
Revenues:
Revenues from Entech's other operations decreased $3,500,000 because of
the sale of the waste management operations in May 1993. This decrease was
offset by $3,000,000 increased revenues from telecommunications operations due
to increased services provided to common carriers and expanded operations in
three western states, and by $500,000 increased revenues from land sales.
Expenses:
The operating expenses of Entech's other operations decreased $3,600,000
due to the sale of the waste management operations mentioned above. This
decrease was offset by $2,900,000 increased costs of telecommunications
operations and land sales.
Interest Expense and Other Income, and Income Taxes:
1995 Compared to 1994
The increase in interest expense was a result of $2,000,000 non-
recurring interest paid to the Utility Division pursuant to the arbitration
decision discussed above and increased borrowings. Other income increased
approximately $3,500,000 due to Oil Division property sales and non-recurring
interest income.
Lower pre-tax net income from operations decreased income taxes
$41,900,000.
1994 Compared to 1993
The decrease in interest expense is due to lower levels of outstanding
debt. The $7,800,000 decrease in other income resulted from the 1993 sales of
a non-strategic asset and the waste management operations.
Income taxes decreased $3,700,000 due to income tax credits utilized and
lower pre-tax net income.
<TABLE>
<CAPTION>
INDEPENDENT POWER GROUP OPERATIONS
Year Ended December 31
1995 1994 1993
Thousands of Dollars
<S> <C> <C> <C>
REVENUES:
Revenues $ 79,095 $ 93,647 $ 119,189
Earnings from unconsolidated investments 2,622 2,080 3,117
Intersegment revenues 796 1,461 5,528
82,513 97,188 127,834
EXPENSES:
Operation and maintenance 68,300 75,080 114,923
Selling, general and administrative 3,557 4,088 9,605
Taxes other than income taxes 1,831 1,916 1,767
Depreciation and amortization 3,176 3,112 2,887
76,864 84,196 129,182
INCOME (LOSS) FROM OPERATIONS 5,649 12,992 (1,348)
INTEREST EXPENSE AND OTHER INCOME:
Interest 21 22 211
Other (income) deductions - net (3,413) (4,711) (1,011)
(3,392) (4,689) (800)
INCOME (LOSS) BEFORE INCOME TAXES 9,041 17,681 (548)
INCOME TAXES 4,775 7,386 (507)
IPG NET INCOME (LOSS) $ 4,266 $ 10,295 $ (41)
</TABLE>
INDEPENDENT POWER GROUP OPERATIONS:
In November 1992, the IPG acquired 100% of North American Energy Services
Company (NAES) and their operations were included in the Company's financial
statements on a consolidated basis in 1993. In August 1994, the IPG sold a 50%
interest in NAES and, as a result of the sale, NAES has been included in the
Company's operations on the equity basis of accounting as of January 1, 1994.
1995 Compared to 1994
The 1995 net income of IPG decreased primarily as a result of the
anticipated decline in the number of 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 NAES and the 1995 loss on the
withdrawal from another investment. IPG 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 IPG 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 IPG 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.
Interest Expense and Other Income:
Other income decreased primarily as a result of the absence in 1995 of
the gain on the sale of 50% of NAES in 1994, which was partially offset by an
increase in interest income.
1994 Compared to 1993
Income from IPG operations increased $14,300,000 primarily due to
increased revenues from independent power project development activity, a gain
on the sale of NAES and improved performance by the Colstrip generating plant.
Revenues:
IPG revenues decreased $43,600,000 due to the accounting change for the
IPG's investment in NAES as mentioned above. The decrease was partially offset
by increases in independent power project development revenues of $12,600,000,
management fees of $500,000 and a $4,900,000 increase in revenues from long-
term power sales from the Colstrip plant due to a 13% increase in volumes sold.
The decrease in earnings from unconsolidated investments resulted
primarily from lower earnings from operating projects. The decrease in
intersegment revenues resulted primarily from the sale of NAES and the
resulting change in accounting.
Expenses:
The NAES sale and corresponding accounting change resulted in decreases
of $41,500,000 in operation and maintenance expense and $5,300,000 in selling,
general and administrative. Operation and maintenance expense was also
impacted by a $2,100,000 decrease in wheeling expense, a $2,100,000 decrease in
purchased power costs and a $3,000,000 increase in fuel costs due to increased
generation at the Colstrip units. Expenses associated with project development
increased by $1,600,000 primarily due to the development of two power projects.
Interest Expense and Other Income:
Other income increased $3,700,000 due principally to increases in
interest income and the gain on the sale of 50% of NAES.
LIQUIDITY AND CAPITAL RESOURCES:
Net cash provided by operating activities was $268,890,000 in 1995
compared to $203,886,000 in 1994 and $185,809,000 in 1993. Cash from operating
activities less dividends paid provided 76% of capital expenditures in 1995,
54% in 1994 and 54% in 1993.
The Company's long-term debt as a percentage of capitalization was 37%,
36% and 36% in 1995, 1994 and 1993, 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:
Years Utility Entech IPG Total
Thousands of Dollars
1993 $112,178 $ 66,832 $ 4,542 $ 183,552
1994 150,903 50,253 6,154 207,310
1995 163,238 63,681 4,168 231,087
The following table sets forth the Company's estimated capital
expenditures for the years 1996-2000 (Projections have been adjusted from 1994
reporting to reflect changes in the Company's electric resource plan, lower
spending for gas transmission projects, and overall reductions in the
construction budget):
Years Utility Entech IPG Total
Thousands of Dollars
1996 $117,000 $ 56,000 $ 28,000 $ 201,000
1997 108,000 48,000 27,000 183,000
1998 73,000 50,000 26,000 149,000
1999 76,000 53,000 26,000 155,000
2000 71,000 54,000 26,000 151,000
In addition, $203,000,000 of long-term debt will mature during the years
1996-2000. See Item 8 "Financial Statements and Supplementary Data - Note 7 to
the Consolidated Financial Statements" for details on maturities of long-term
debt.
For the years 1996-2000, the Company estimates that, by business unit,
internally-generated funds will average 103% of its utility construction
program, 106% of Entech's capital expenditures and 29% of IPG investments. 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 $93,600,000 in 1995,
$92,009,000 in 1994 and $85,822,000 in 1993. During 1995, 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. While the declaration
of future dividends is at the discretion of the Board of Directors, the Company
does not anticipate that the 1995 writedown of a coal mining investment and the
adoption of SFAS No. 121 will affect the common stock dividend.
The Company and Entech have Revolving Credit and Term Loan Agreements in
the amount of $60,000,000 and $75,000,000, respectively. These businesses also
have short-term borrowing facilities with commercial banks that provide both
committed and uncommitted lines of credit, and the ability to sell commercial
paper. See Item 8, "Financial Statements and Supplementary Data - Notes 7
and 8 to the Consolidated Financial Statements for further information."
In April 1995, the Company sold $20,000,000 of Secured Medium-Term Notes,
7.33% series due 2025. The proceeds were used to finance construction and to
repay short-term debt. In November 1995, the Company sold $20,000,000 of
Secured Medium-Term Notes, $10,000,000 of a 5.75% series due 1997 and
$10,000,000 of a 5.9% series due 1998. The proceeds were used to finance
construction and to retire $10,000,000 of Unsecured Medium-Term Notes, 8.87%
series due 1995.
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 1996-2000.
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, 1995, the Company's ratio of
earnings to fixed charges was 1.96 times. Excluding the effects of the
implementation of SFAS No. 121 and the writedown of a coal mining investment,
discussed in Note 11 to the Consolidated Financial Statements, the ratio of
earnings to fixed charges would have been 2.84 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 are not impacted because a gas cost
tracking procedure annually balances gas costs collected from customers with
the costs of supplying gas.
Entech's long-term coal and co-generation natural gas supply contracts
and the IPG's long-term power sales contracts provide for the adjustment of
prices either through indices, fixed escalations and/or direct pass-through of
costs.
The Company believes that the effects of inflation, at currently
anticipated levels, will not significantly affect results of operations.
STOCK BASED COMPENSATION:
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. See Item 8, "Financial Statements and Supplementary Data -
Note 5 to the Consolidated Financial Statements" for further discussion of the
accounting standard.
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 almost all federal, state and local environmental laws and regulations
relating to pollution control and prevention and environmental remediation. The
primary 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. To comply with
these laws and to maintain compliance requires a significant commitment of
resources and a comprehensive planning effort.
Some of these environmental laws and regulations, primarily CERCLA and
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 past or present Company sites or at sites where these substances
were disposed. The Company currently participates in several such remediation
efforts and may, in the future, be involved in additional site remediation
activities. The total amount of costs associated with future sites remediation
is unknown both because (1) the Company may not know of all sites for which it
has all or some responsibility and (2) for those sites which the Company does
have responsibility, it does not have enough information to estimate future
costs with reasonable certainty. However, as the Company gains information
regarding its obligations and in accordance with accounting guidelines, it will
continually refine and update its estimates of future costs associated with
site remediation.
The Clean Air Act Amendments of 1990 (Act) should have no major effects
on the Company's electric generation facilities. All units have been
designated as Phase II Units under Title IV (Acid Rain) of the 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 intends to exercise this option.
The Company will not exercise this option for its Corette Plant because,
due to improvements in the plant's emissions which will not be completed until
1997, the level of nitrogen oxide emissions at the plant cannot be determined
with the precision necessary to make this election.
The costs associated with any modifications that ultimately may be
required to comply with Phase II nitrogen oxide standards cannot be determined
because they have not been promulgated.
In 1988, the United States Environmental Protection Agency advised the
Company that it, along with certain other parties, is a potentially responsible
party (PRP) for the release of certain toxic substances which have come to rest
behind the dam at the Company's Milltown Hydroelectric Plant. Because of
federal legislation specifically relating to Milltown, the Company believes it
has no responsibility for any of the alleged releases. If the Company should
have some responsibility, it would have to share, together with other
responsible parties, the costs related to the handling of these toxic
substances. While these costs have not been determined, the Company believes
that any portion which it might bear would not have a significant impact upon
its earnings.
The Company, along with others, has been named a PRP with respect to the
Silver Bow Creek/Butte Area Superfund Site. The alleged contamination is soil
and groundwater contamination, for the most part, associated with decades of
copper mining in the area. The PRPs have cooperated to summarize the data that
currently exists, to evaluate the usability of this existing data and to
determine additional data needs. Studies to determine the extent of the
alleged contamination, and a proposal for removal or remediation of the alleged
contamination are not complete.
Regarding this superfund site, the Company has focused on its property
ownership and alleged contamination that may be attributed to that ownership.
It has spent approximately $500,000 to investigate its property within the
site, collect data, evaluate studies and monitor its property. Costs to clean
up this contamination, including sums spent in the studies mentioned above, are
not expected to exceed $1,000,000.
Other contamination at the Company's property within the site involves
heavy metals and substances which may be attributed to mining and activities of
others within the greater area of the site. Consultants employed by the PRPs
to compile and analyze previously prepared study data regarding the greater
area of this superfund site have made preliminary estimates indicating that
clean-up costs could range from $20,000,000 to $60,000,000. While the Company
denies any responsibility for costs associated with this contamination, if the
Company should have some responsibility, it would have to share a portion of
the costs ultimately related to the handling of the contamination.
The Company or its predecessors owned and operated manufactured gas
plants on three sites. To gather information necessary to learn about the
nature of contamination at one of these sites, the Company voluntarily began
work in 1995. The assessment accomplished to date indicates that the cost of
cleanup may range from $1,100,000 to $2,200,000. The Company has not yet taken
extensive action to characterize the potential for pollution at the other two
sites.
The Company has accrued the estimated minimum costs associated with the
matters discussed above. The Company does not expect these costs to materially
impact the results of its operations.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA
Page
Management's Responsibility for Financial Statements 52
Report of Independent Accountants 53
Consolidated Financial Statements:
Consolidated Statements of Income for the Years Ended
December 31, 1995, 1994 and 1993 54
Consolidated Balance Sheets as of December 31, 1995 and 1994 55-56
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1995, 1994 and 1993 57
Consolidated Statements of Common Shareholders' Equity for the
Years Ended December 31, 1995, 1994 and 1993 58
Notes to Consolidated Financial Statements 59-86
Supplementary Data (Unaudited)
Financial Statement Schedules for the Years Ended December 31,
1995, 1994 and 1993 87-95
Schedule II - Valuation and Qualifying Accounts and Reserves 100
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.
/s/ Daniel T. Berube /s/ J. P. Pederson
Daniel T. Berube J. P. Pederson
Chairman of the Board and Vice President and
Chief Executive Officer Chief Financial Officer
Report of Independent Accountants
February 9, 1996
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, 1995
and 1994, and the results of their operations and of their cash flows for each
of the three years in the period ended December 31, 1995, 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 11 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
CONSOLIDATED STATEMENT OF INCOME
The Montana Power Company and Subsidiaries
<TABLE>
<CAPTION>
Year Ended December 31
1995 1994 1993
Thousands of Dollars
<S> <C> <C> <C>
REVENUES $ 953,539 $1,005,970 $1,024,285
EXPENSES:
Operations 424,443 440,472 480,382
Maintenance 68,286 75,357 70,029
Selling, general and administrative 98,327 103,127 101,251
Taxes other than income taxes 89,858 99,200 92,430
Depreciation, depletion and amortization 86,976 86,711 82,696
Writedowns of long-lived assets 74,297
842,187 804,867 826,788
INCOME FROM OPERATIONS 111,352 201,103 197,497
INTEREST EXPENSE AND OTHER INCOME:
Interest 43,788 42,817 48,023
Other (income) deductions - net (10,947) (10,532) (11,857)
32,841 32,285 36,166
INCOME TAXES 21,574 55,226 54,120
NET INCOME 56,937 113,592 107,211
DIVIDENDS ON PREFERRED STOCK 7,227 7,227 4,353
NET INCOME AVAILABLE FOR COMMON STOCK $ 49,710 $ 106,365 $ 102,858
AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING (000) 54,121 53,125 52,040
NET INCOME PER SHARE OF COMMON STOCK $ 0.92 $ 2.00 $ 1.98
The accompanying notes are an integral part of these statements.
</TABLE>
CONSOLIDATED BALANCE SHEET
The Montana Power Company and Subsidiaries
ASSETS
<TABLE>
<CAPTION>
December 31,
1995 1994
Thousands of Dollars
<S> <C> <C>
PLANT AND PROPERTY IN SERVICE:
Utility plant (includes $57,095 and $79,510 plant
under construction):
Electric $1,713,133 $1,608,615
Natural gas 492,431 463,134
2,205,564 2,071,749
Less - accumulated depreciation and depletion 663,215 619,195
1,542,349 1,452,554
Entech property (includes $12,716 and $3,030
property under construction) 559,722 530,167
Less - accumulated depreciation and depletion 232,947 189,926
326,775 340,241
Independent Power Group property (includes $3,171
and $671 property under construction) 72,179 70,132
Less - accumulated depreciation 19,666 17,560
52,513 52,572
1,921,637 1,845,367
MISCELLANEOUS INVESTMENTS (at cost):
Independent power investments 57,013 54,518
Other 46,966 49,713
103,979 104,231
CURRENT ASSETS:
Cash and temporary cash investments 15,541 21,564
Accounts receivable 152,386 159,975
Materials and supplies (principally at
average cost) 42,194 47,937
Prepayments and other assets 62,071 65,154
272,192 294,630
DEFERRED CHARGES:
Advanced coal royalties 20,175 22,939
Regulatory assets related to income taxes 148,350 146,844
Regulatory assets - other 68,637 49,880
Other deferred charges 51,121 48,806
288,283 268,469
$2,586,091 $2,512,697
The accompanying notes are an integral part of these statements.
LIABILITIES
December 31
1995 1994
Thousands of Dollars
CAPITALIZATION:
Common shareholders' equity:
Common stock (120,000,000 shares without par
value authorized; 54,614,481 and 53,578,737
shares issued) $ 691,043 $ 667,344
Retained earnings and other shareholders' equity 285,000 320,756
Unallocated stock held by trustee for Deferred
Savings and Employee Stock Ownership Plan (30,565) (32,580)
945,478 955,520
Preferred stock 101,416 101,416
Long-term debt 616,574 588,876
1,663,468 1,645,812
CURRENT LIABILITIES:
Short-term borrowing 96,348 113,989
Long-term debt-portion due within one year 24,804 16,980
Dividends payable 23,668 23,249
Income taxes 9,937 9,210
Other taxes 43,302 46,521
Accounts payable 63,920 50,788
Interest accrued 12,341 11,785
Other current liabilities 63,488 40,546
337,808 313,068
DEFERRED CREDITS:
Deferred income taxes 320,736 322,835
Investment tax credit 47,001 48,729
Accrued mining reclamation costs 122,008 110,035
Other deferred credits 95,070 72,218
584,815 553,817
CONTINGENCIES AND COMMITMENTS (Notes 2 and 3)
$2,586,091 $2,512,697
The accompanying notes are an integral part of these statements.
</TABLE>
CONSOLIDATED STATEMENT OF CASH FLOWS
The Montana Power Company and Subsidiaries
<TABLE>
<CAPTION>
Year Ended December 31
1995 1994 1993
Thousands of Dollars
<S> <C> <C> <C>
NET CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 56,937 $ 113,592 $ 107,211
Noncash charges (credits) to net income:
Depreciation, depletion and amortization 86,976 86,711 82,696
Writedowns of long-lived assets 74,297
Mining reclamation costs expensed 15,970 19,527 19,410
Amortization of loss on long-term
sales of power (3,264) (4,226) (5,251)
Deferred income taxes (11,819) 4,792 16,324
Other-net 21,055 31,447 16,176
Accounts receivable 7,589 (1,622) (15,367)
Materials and supplies 5,743 (5,209) (975)
Accounts payable 13,132 (5,007) 6,922
Payment of mining reclamation costs (8,559) (11,309) (9,481)
Changes in other assets and liabilities 10,833 (24,810) (31,856)
Net Cash Flows From Operating
Activities 268,890 203,886 185,809
NET CASH FLOWS FROM INVESTING ACTIVITIES:
Gross additions to property and plant (213,440) (187,213) (166,050)
Investments in other operations (3,953) (6,344) (6,161)
Sales of property 13,987 27,729 24,924
Additional investments (16,334) (12,610) (7,327)
Net Cash Flows From Investing
Activities (219,740) (178,438) (154,614)
NET CASH FLOWS FROM FINANCING ACTIVITIES:
Sales of common stock 23,465 24,380 24,917
Issuance of long-term debt 50,758 52,094 294,149
Retirement of long-term debt (18,155) (45,078) (316,714)
Short-term debt (17,641) 45,125 5,565
Dividends on common and preferred stock (93,600) (92,009) (85,822)
Issuance of preferred stock 49,435
Net Cash Flows From Financing
Activities (55,173) (15,488) (28,470)
Change in Cash Flows (6,023) 9,960 2,725
Cash and cash equivalents at beginning
of year 21,564 11,604 8,879
Cash and cash equivalents at end of year $ 15,541 $ 21,564 $ 11,604
SUPPLEMENTAL DISCLOSURES OF CASH
FLOW INFORMATION:
Cash Paid During Year For:
Income taxes $ 32,666 $ 45,875 $ 46,533
Interest 46,141 45,990 53,541
The accompanying notes are an integral part of these statements.
</TABLE>
CONSOLIDATED STATEMENT OF COMMON SHAREHOLDERS' EQUITY
The Montana Power Company and Subsidiaries
<TABLE>
<CAPTION>
Year Ended December 31
1995 1994 1993
Thousands of Dollars
<S> <C> <C> <C>
COMMON STOCK:
Balance at beginning of year $ 667,344 $ 642,926 $ 618,009
Issuances (1,035,744; 1,079,841;
and 949,951 shares) 23,699 24,418 24,917
Balance at end of year 691,043 667,344 642,926
RETAINED EARNINGS AND OTHER SHAREHOLDERS'
EQUITY:
Balance at beginning of year 320,756 302,725 284,980
Net income 56,937 113,592 107,211
Dividends on common stock ($1.60;
$1.60; and $1.585 per share) (86,791) (85,193) (82,701)
Dividends on preferred stock (7,227) (7,227) (4,353)
Other 1,325 (3,141) (2,412)
Balance at end of year 285,000 320,756 302,725
UNALLOCATED STOCK HELD BY TRUSTEE FOR
DEFERRED SAVINGS AND EMPLOYEE STOCK
OWNERSHIP PLAN:
Balance at beginning of year (32,580) (34,419) (36,098)
Distributions 2,015 1,839 1,679
Balance at end of year (30,565) (32,580) (34,419)
TOTAL COMMON SHAREHOLDERS' EQUITY AT
END OF YEAR $ 945,478 $ 955,520 $ 911,232
The accompanying notes are an integral part of these statements.
</TABLE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - Summary of significant accounting policies:
The Company's accounting policies conform to generally accepted
accounting principles. With respect to utility operations, such policies are
in accordance with the accounting requirements and ratemaking practices of the
regulatory authorities having jurisdiction.
Preparing financial statements requires the use of estimates. Future
events and their effects cannot be perceived with certainty; estimating,
therefore, requires the exercise of judgment. Management makes appropriate
estimates and judgments based upon available information. Accounting estimates
may change as new events occur, additional information is obtained or more
experience is acquired. Actual results may differ from accounting estimates.
Principles of consolidation:
The Consolidated Financial Statements include the accounts of the Company
and its subsidiaries, all of which are wholly-owned. The Independent Power
Group (IPG) includes the Company's Colstrip Unit 4 operations. All material
intercompany sales and purchases between the Utility, Entech and the IPG have
been eliminated from revenues and expenses in the Consolidated Statement of
Income. All other significant intercompany items have also been eliminated.
See Note 10 for details.
Plant and property:
Additions to and replacements of plant and property are recorded at
original cost, which includes material, labor, overhead and contracted
services. Cost includes interest capitalized and, with respect to Utility
plant, also includes an allowance for funds used during construction. Gas in
underground storage is included in natural gas Utility plant. Maintenance and
repairs of plant and property, and replacements and renewals of items
determined to be smaller than established units of plant, are charged to
operating expenses. The cost of units of Utility plant retired or otherwise
disposed of, adjusted for removal costs and salvage, is charged to the
accumulated provision for depreciation and depletion, and the cost of related
replacements and renewals is added to Utility plant. Gain or loss is
recognized upon the sale or other disposition of Entech property, IPG property
and Utility land.
Provisions for depreciation and depletion are recorded at amounts
substantially equivalent to calculations made on straight-line and
unit-of-production methods by application of various rates based on useful
lives of properties determined from engineering studies. For 1995, 1994 and
1993, the provisions for utility depreciation and depletion approximated 2.7%
of the depreciable and depletable utility plant at the beginning of the year.
The Company and its subsidiaries have adopted two methods of accounting
for oil and gas exploration and development costs. Entech's Oil Division uses
the successful efforts method. The regulated natural gas utility capitalizes
all costs associated with the successful development of a natural gas well and
expenses those costs incurred on an unsuccessful well.
The Company is a joint-owner of Colstrip Units 1, 2 and 3 and of
transmission facilities serving these Units. At December 31, 1995, 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 $ 182,380 $ 284,017 $ 51,147
Plant under construction 235 1,648 9
Accumulated depreciation 85,572 93,022 11,847
*This is an approximate ownership percentage. The ownership
percentages are generally based on capacity rights on the various
segments of the transmission system.
The Company also owns $35,739,000 and $33,151,000 of the Colstrip Unit 4
share of common production plant and transmission plant that had related
accumulated depreciation of $13,311,000 and $6,315,000, respectively.
Each joint-owner provides its own financing. The Company's share of
direct expenses associated with the operation and maintenance of these joint
facilities is included in the corresponding operating expenses in the
Consolidated Statement of Income.
Utility revenue and expense recognition:
Operating revenues are recorded on the basis of service rendered. Costs
of service are recognized on the accrual basis and charged to expense currently
except for natural gas costs deferred pursuant to PSC-approved deferred gas
accounting procedures. 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:
As a rate regulated utility, the Company follows SFAS No. 71, "Accounting
for the Effects of Certain Types of Regulation." Pursuant to the
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.
1995 1994
Assets Liabilities Assets Liabilities
Thousands of Dollars
Income taxes $ 147,388 $ 145,623
Conservation programs 40,640 31,214
Other 33,298 $ 12,623 24,173 $ 10,330
Subtotal 221,326 12,623 201,010 10,330
Less:
Current portions 4,339 3,675 4,286 426
Total $ 216,987 $ 8,948 $ 196,724 $ 9,904
Income taxes represent the expected future tax consequences that will
result from the reversal of temporary differences between the recorded book
basis and the tax basis of assets and liabilities. These amounts reverse in
future periods when the taxes are paid and reflected in rates.
Conservation programs represent the Company's Demand Side Management
(DSM) programs that are in rate base and are being charged 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.
Historically, all costs of this nature that are determined to have been
reasonable and prudently incurred have been recoverable through rates and the
Company believes these costs will be afforded similar treatment.
In order to defer incurred costs under SFAS No. 71, a regulated entity
must be regulated in a manner which allows recovery of costs and rates so
established can be charged to and collected from customers. Certain events
could cause the Company to not meet the criteria of SFAS No. 71. These include
a change in the method of regulation, a change in the competitive environment
where the Company may be forced to establish rates which are insufficient to
recover incurred costs or any other event that could cause the recovery of
costs through rates to become uncertain. 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 be eliminated from the
balance sheet and included in income in the period when the discontinuation
occurred. The financial effects of such an occurrence could be significant.
Cash and cash equivalents:
For the purposes of these financial statements, the Company considers all
liquid investments with original maturities of three months or less to be cash
equivalents.
Allowance for funds used during construction:
The Company capitalizes, as a part of the cost of utility plant, an
allowance for the cost of equity and borrowed funds required to finance
construction work in progress. The rate used to compute the allowance is
determined in accordance with a formula established by the FERC and was an
average of 8.1% for 1995, 7.9% for 1994 and 6.5% for 1993. The Company
capitalized an allowance for borrowed funds used during construction of
$4,250,000, $2,402,000 and $1,372,000 for 1995, 1994 and 1993, respectively.
Allowance for funds used for conservation expenditures:
The Company has been allowed by the PSC to capitalize, as part of its
conservation expenditures, an allowance for the cost of equity and borrowed
funds required to finance DSM expenditures. The rate used to capitalize the
allowance is the Company's overall rate of return allowed by the PSC. The
Company capitalized an allowance for borrowed funds used to finance DSM
expenditures of $872,000, $635,000 and $561,000 for 1995, 1994 and 1993,
respectively.
Environmental remediation costs:
The estimated costs of environmental remediation obligations for the
Utility Division are charged against established, regulator approved operating
reserves when such losses are probable and reasonably estimable. Consequently,
the Company does not experience large fluctuations in environmental costs from
year to year. The reserves are adequate to provide for all known obligations
and may be increased, if appropriate, by adjusting the annual accrual rate. The
annual accruals are recovered through rates.
Employee termination benefits:
The Company has performed a strategic analysis of certain business
functions, to determine what is needed in those areas to meet changing
conditions in the utility industry. Study teams developed methods to be more
efficient and changes are being implemented in the Utility's organizational
structure. The changes, which began in 1994, are anticipated to be largely
completed in 1997. The following table shows the total number of employees
terminated and estimated to be terminated and the associated termination costs
by operations:
Number of Regulated Colstrip Unit 4
Year Employees Operations Operations
1994 59 $ 2,460,577
1995 121 3,445,348 $ 104,908
1996 88 2,450,515 226,000
1997 97 2,236,352 212,000
Total 365 $10,592,792 $ 542,908
For the regulated operations, the Company has accrued an estimated
$8,100,000 of severance benefits for years 1995 through 1997. Offsetting these
benefit costs are savings realized through 1995 of $1,700,000. The 1994 costs
were charged to income through operating and selling, general and
administrative expenses. The net cost of the program since 1995 is being
deferred as authorized by an accounting order from the PSC and is not reflected
in income. The Company believes this cost will be recovered through rates.
Total termination costs for 1995 through 1997 for Colstrip Unit 4
operations have been charged against income through operating expenses.
Income taxes:
The Company and its U.S. subsidiaries file a consolidated U.S. income tax
return. Consolidated U.S. income taxes are allocated to Utility, Entech and
IPG operations as if separate U.S. income tax returns were filed. Deferred
income taxes are provided for the temporary differences between the financial
reporting basis and the tax basis of the Company's assets and liabilities. For
further information on income taxes see "Regulatory assets and liabilities" in
this note and also Note 4 - Income taxes.
Net income per share of common stock:
Net income per share of common stock is computed for each year based upon
the weighted average number of common shares outstanding. The effect of
options outstanding under the Company's Long-Term Incentive Plan is not
significant (see Note 5 - Common stock).
Financial instruments:
In October 1994, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 119, "Disclosure about
Derivative Financial Instruments and Fair Value of Financial Instruments,"
effective for fiscal years ending after December 15, 1994. This statement
requires disclosure about derivative financial instruments - futures, forwards,
swap and option contracts, and other financial instruments with similar
characteristics.
To manage price risk, Entech uses oil and natural gas swap agreements and
oil collar agreements to hedge revenue from anticipated production and sales of
oil and natural gas. Under swap agreements, Entech receives or makes payments
based on the differential between a specified price and the market price of oil
or natural gas when the hedged production is sold. Under collar agreements,
Entech makes or receives monthly payments when the actual price of oil exceeds
the ceiling or drops below the floor established in the agreement. At
December 31, 1995, Entech had swap agreements to hedge approximately
400,000 barrels of oil, or 44%, of its expected production through November
1996, and for approximately 806,000 Mmcf of natural gas, or 22%, of its
expected production through March 1996. In addition, Entech had swap
agreements to hedge approximately 2,675,000 Mmcf of natural gas, or 23%, of its
delivery obligations under long-term natural gas sales contracts through
February 1997. At December 31, 1995, the Company had no material deferred
gains or losses from these transactions.
The IPG has investments in independent power partnerships, some of which
have entered into derivative financial instruments to hedge against interest
rate exposure on floating rate debt and foreign currency and gas price
fluctuations. At December 31, 1995, the Company believes it would not
experience any materially adverse impacts from the risks inherent in these
instruments.
Statement of Financial Accounting Standards No. 107, "Disclosure about
Fair Value of Financial Instruments," requires disclosure of the fair value of
certain financial instruments. The estimated fair value amounts have been
determined by the Company using available market information and appropriate
valuation methodologies. However, considerable judgment is required in
interpreting market data to develop the estimates of fair value. Accordingly,
the estimates presented herein are not necessarily indicative of the amounts
that could be realized in a current market exchange. The use of different
market assumptions and/or estimation methodologies could result in different
estimated fair value amounts.
Cash and temporary cash investments, accounts receivable, current assets,
short-term borrowings, accounts payable and accrued liabilities are reflected
in the financial statements at fair value because of the short-term maturity of
these instruments.
The carrying amounts and estimated fair value of the Company's other
significant financial instruments were as follows:
1995 1994
Carrying Fair Carrying Fair
Amount Value Amount Value
Thousands of Dollars
Assets:
Independent power investments $ 7,868 $ 2,169 $ 9,566 $ 5,482
Other investments 33,558 34,575 31,690 31,875
Liabilities:
Long-term debt $616,574 $656,476 $588,876 $548,358
The following methods and assumptions were used to estimate fair value:
Independent power investments - The fair value represents the Company's
assessment of the present value of net future cash flows embodied in these
investments, discounted to reflect current market rates of return. This
represents only those investments accounted for on the cost basis. The
investments accounted for on the equity basis are not presented.
Other investments - The carrying value of most of the investments
approximates fair value as the investments have short maturities or the
carrying value equals their cash surrender value. Other investments' fair
value was estimated based on the discounted value of the future cash flows
expected to be received using a rate of return expected on similar current
investments.
Long-term debt - The fair value was estimated using quoted market rates
for the same or similar instruments. Where quotes were not available the fair
value was estimated using the Company's year-end incremental borrowing rate.
Reclassifications:
Certain reclassifications have been made to the prior year amounts to
make them comparable to the 1995 presentation. These changes had no impact on
previously reported results of operations or shareholders' equity.
NOTE 2 - Contingencies:
In 1990, pursuant to a FERC license obligation, the Company proposed a
plan to protect fish and wildlife habitat affected by the operation of the Kerr
hydroelectric project, which would cost the Company $15,500,000 initially and,
thereafter, $1,000,000 annually. FERC and the Department of the Interior have
proposed alternatives which would cost $48,000,000 initially and, thereafter,
$1,300,000 annually and would require baseload as opposed to load following
operation.
In November 1992, the Company applied to FERC to relicense nine Madison
and Missouri River hydroelectric projects, with generating capacity of
292 megawatts. The total cost of relicensing, including physical improvements,
is estimated at $151,000,000. In addition, operating changes associated with
environmental protection are expected to decrease project capability by
26 megawatts.
The Company has brought an action against Puget Sound Power & Light
Company (Puget) in the Federal District Court for the Western District of
Montana seeking a determination that the Company is 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 had breached the
agreement by failing to provide a firm transmission path for the power, thereby
entitling Puget to terminate the agreement. The Company and Puget have agreed
that, should it be determined that Puget is entitled to terminate the
agreement, the Company would reimburse Puget for the excess, if any, of the
cost of power purchased under the agreement after February 1995, over the cost
which Puget may demonstrate it would have paid for such power elsewhere. Also,
the Company would be obligated to reimburse Puget for the amount (estimated at
$40,000,000, excluding interest, by which Puget's payments through February
1995 have exceeded its projected avoided cost. In addition, the Company's
future revenues would be reduced by the difference, if any, between sales at
prices under the agreement, approximately $30,000,000 per year, and prices it
might receive from alternative sales. In accordance with SFAS No. 121, the
Company could be required to writedown assets related to the agreement by
approximately $24,000,000, before taxes. The Company believes that Puget's
intention is to reduce its purchase power costs. The price of power under the
agreement is in excess of current market rates. While confident of its
position, the Company cannot be certain of the decisions in the proceedings,
which are not expected to conclude before the fourth quarter of 1996.
In March 1995, an arbitration decision resolved a pricing dispute
between Western Energy Company (Western), a subsidiary of the Company, and
Puget regarding the Colstrip Units 1 and 2 Coal Supply Agreement which is
between Puget and the Company's Utility Division, as co-owners of the units,
and Western, as coal supplier. Excluding production taxes and royalties, the
contract price was reduced, effective July 1991, by approximately $1.20 per
ton. As a result, the Company's 1995 consolidated pre-tax income decreased
approximately $6,000,000. Cash flow was not materially affected because Puget
had paid less than invoiced amounts for coal delivered after April 1992. In
addition, Western refunded approximately $11,700,000, including interest, with
respect to coal sold to the Company's Utility Division since July 1991. This
refund did not affect either consolidated income or cash flow. On an annual
basis, the new contract price is estimated to result in a pre-tax reduction of
consolidated income of approximately $3,500,000 per year.
Western is also a party in an arbitration initiated by the non-operating
owners of the Colstrip Units 3 and 4 (i.e., Puget, Washington Water Power
Company, Portland General Electric Company and PacifiCorp -- collectively, the
"Buyers") to resolve a variety of disputes arising under the contracts with
Western for the supply and transportation of coal for these Units. The
principal issues are the amounts of and prices for coal that the Buyers are
obligated to purchase in excess of 600,000 tons monthly, 6,000,000 tons yearly
and 170,000,000 tons over the contract life, Western's obligation to mine in a
manner dictated by the Buyers, and Western's obligation to place reclamation
funds received in a trust account. The Buyers are seeking prospective relief
regarding the volumes and the amount to be paid for any volumes that exceed the
above-stated amounts. Damages sought by the Buyers regarding Western's alleged
failure to have mined in accordance with their proposed mine plan and the
refund of certain transportation charges are approximately $7,000,000. And,
the amount Western would be obligated to place in the trust account would be
approximately $36,000,000, including interest. A decision of the arbitrator is
expected in the second quarter of 1996. While confident of Western's
positions, the Company cannot be certain of the outcome of the arbitration.
Continental Energy Services, Inc., a wholly-owned subsidiary of the
Company, is a general partner in a partnership (the Partnership) formed to
construct and own a 248 megawatt Tenaska power plant at Frederickson,
Washington. The Partnership contracted in 1994 to sell the output of this
plant to the Bonneville Power Administration (BPA) over a 20-year period. In
May of 1995, BPA informed the Partnership that it would not purchase the power.
BPA alleged that decreases in demand for power and increasing constraints in
protection of endangered species have frustrated its purposes for entering into
the power purchase contract and, consequently, have excused it from
performance. The Partnership halted construction of the plant and has sued BPA
seeking damages, including lost future profits. This matter has been referred
to binding arbitration by the United States Court of Federal Claims. The
Company does not believe this dispute will adversely affect its financial
performance.
The Company and its subsidiaries are party to various other legal claims,
actions and complaints arising in the ordinary course of business. Management
does not expect disposition of these matters to have a material adverse effect
on the Company's consolidated results of operations.
NOTE 3 - Commitments:
The Company purchases approximately 600 million kWh annually under an
Exchange Agreement with the Washington Public Power Supply System and the BPA
which expires in 1996. The rate is 4.9 cents per kWh. In 1993, the Company
entered into a contract to purchase 98 megawatts of seasonal capacity from
Basin Electric Power Cooperative beginning in 1996. The rate will be
approximately 3.3 cents per kWh in the contract year beginning in November 1996
and will increase each subsequent year to approximately 7.1 cents per kWh in
the final contract year which begins in November 2009.
The Company also has long-term purchase contracts with certain
independent power producers and natural gas producers. The purchased power
contracts provide for capacity payments subject to a facility meeting certain
operating standards, and payments based on energy received. The purchased gas
contracts provide for take-or-pay payments. The Entech Oil Division has
various natural gas transportation contracts with terms that expire beginning
in 1998.
Total payments under these contracts for the prior three years were as
follows:
Thousands of Dollars
Years Electric Natural Gas Entech
1993 $ 18,434 $ 11,633 $ 2,460
1994 19,242 11,072 3,302
1995 21,830 9,873 3,023
The present value of future minimum payments, at an assumed discount rate
of 8%, under the above agreements are estimated as follows:
Thousands of Dollars
Years Electric Natural Gas Entech
1996 $ 8,829 $ 7,393 $ 2,954
1997 12,035 6,346 2,420
1998 11,999 3,075 2,873
1999 11,791 2,607 3,188
2000 11,606 2,275 2,951
Remainder 152,223 4,289 11,587
Total $ 208,483 $ 25,985 $ 25,973
Under a joint 50-year license with the Confederated Salish and Kootenai
Tribes (Tribes), the Company will own and operate the 180 megawatt Kerr
hydroelectric project until September 2015. The Tribes may take over the
project anytime between 2015 and 2025 on one year's written notice in return
for payment equal to the Company's remaining net investment. The Company pays
the Tribes an annual rental fee that is adjusted yearly to reflect changes in
the Consumer Price Index.
An Entech Coal Division coal lease purchase agreement requires minimum
annual payments, beginning in 1991 in the amount of $1,125,000 escalated
quarterly by the Gross National Product implicit price deflator. The payments
will continue until the equivalent of $18,750,000, in 1986 dollars, has been
paid. At December 31, 1995, the remaining payments under this agreement were
$11,791,000. Under current mine plans, these payments should be recovered
through coal sales.
The Entech Oil Division has agreed to supply approximately 126,000 Mmcf
of natural gas to four co-generation facilities through mid-2011. The Oil
Division has proven, developed and undeveloped reserves sufficient to supply
all of the remaining natural gas required by these agreements.
Rental expense for the prior three years was as follows:
1995 1994 1993
Thousands of Dollars
Colstrip Unit 4 $ 31,680 $ 32,226 $ 32,226
Kerr project 12,498 12,172 11,837
Other 11,780 12,530 11,917
$ 55,958 $ 56,928 $ 55,980
In addition, operating expenses include delay rentals paid by the Company
to retain mineral rights before development of leased acreage. Delay rentals
were $2,960,000, $1,015,000 and $1,021,000 in 1995, 1994 and 1993,
respectively.
Leases:
The Company classifies leases as operating or capitalized leases.
Capitalized leases are not material and are included in other long-term debt.
On December 30, 1985, the Company sold its 30% share of Colstrip Unit 4 and is
leasing back this share under a net lease. The transaction has been accounted
for as an operating lease with semiannual lease payments of approximately
$16,000,000 over the remaining term of the 25-year lease.
At December 31, 1995, the Company's future minimum operating lease
payments were as follows:
Thousands of
Year Dollars
1996 $ 33,430
1997 32,971
1998 32,769
1999 32,757
2000 32,542
Remainder 322,064
Total $ 486,533
NOTE 4 - Income tax expense:
Income before income taxes for the years ended December 31, 1995, 1994
and 1993 was as follows:
1995 1994 1993
Thousands of Dollars
United States $ 75,458 $ 155,978 $ 150,290
Canada 111 9,144 8,791
Brazil 2,942 3,696 2,250
$ 78,511 $ 168,818 $ 161,331
The provision for income taxes differs from the amount of income tax
determined by applying the applicable U.S. statutory federal income tax rate to
pretax income as a result of the following differences:
1995 1994 1993
Thousands of Dollars
Computed "expected" income tax expense $ 27,479 $ 59,086 $ 56,466
Adjustments for tax effects of:
Statutory depletion in
coal mining operations (6,508) (4,983) (3,775)
General business and nonconventional
fuel tax credits (5,331) (5,130) (4,496)
State income tax, net 3,327 4,772 4,704
Reversal of excess of U.S. Utility
income tax depreciation over
financial accounting
depreciation on utility plant
additions 2,552 3,236 2,281
Other 55 (1,755) (1,060)
Actual income tax expense $ 21,574 $ 55,226 $ 54,120
Income tax expense as shown in the Consolidated Statement of Income
consists of the following components:
1995 1994 1993
Thousands of Dollars
Current
United States $ 25,119 $ 38,519 $ 31,039
Canada 1,510 3,093 3,235
Brazil 548 1,080
State 6,216 7,742 3,522
33,393 50,434 37,796
Deferred
United States (8,648) 4,426 13,664
Canada (1,124) 850 374
State (2,047) (484) 2,286
(11,819) 4,792 16,324
$ 21,574 $ 55,226 $ 54,120
Deferred tax liabilities (assets) are comprised of the following at
December 31:
1995 1994
Thousands of Dollars
Plant related $ 377,741 $ 379,401
Investment in nonutility generation projects 23,896 21,752
Other 25,724 21,309
Gross deferred tax liabilities 427,361 422,462
Coal reclamation (42,438) (40,509)
Amortization of gain on sale/leaseback (15,962) (17,026)
Investment tax credit amortization (30,542) (31,665)
Other (33,582) (20,392)
Gross deferred tax assets (122,524) (109,592)
Net deferred tax liabilities (assets) 304,837 312,870
Plus current deferred tax assets-net 15,899 9,965
Total noncurrent deferred tax liabilities
(assets) $ 320,736 $ 322,835
The change in net deferred tax liabilities differs from current year
deferred tax expense as a result of the following:
Thousands of
Dollars
Increase (decrease) in total noncurrent deferred tax
liabilities (assets) $ (2,099)
Regulatory assets related to income taxes (1,506)
Current deferred tax assets-net (5,934)
Amortization of investment tax credits (1,728)
Other (552)
Deferred tax expense $ (11,819)
NOTE 5 - Common stock:
At December 31, 1995 and 1994, the Company had 120,000,000 shares of
authorized common stock. The Company has a Shareholder Protection Rights Plan
which provides one preferred share purchase right (Right) on each outstanding
common share of the Company. Each Right entitles the registered holder, upon
the occurrence of certain events, to purchase from the Company one
one-hundredth of a share of Participating Preferred Shares, A Series, without
par value. If it should become exercisable, each Right would have economic
terms similar to one share of common stock of the Company. The Rights trade
with the underlying shares and will, except under certain circumstances
described in the Plan, expire on June 6, 1999, unless earlier redeemed or
exchanged by the Company.
The Company's Dividend Reinvestment and Stock Purchase Plan allows owners
of common and preferred stock, employees, Montana utility customers and certain
others to reinvest the dividends paid on their common and preferred stock to
purchase shares of common stock. Participants in the plan may also elect to
invest by purchasing up to $15,000 of common stock per quarter. Beginning in
1996, shares issued under these plans will be purchased in the open market.
The Company has a Deferred Savings and Employee Stock Ownership
Plan (Plan) that covers all regular eligible employees. The Company, on behalf
of the employee, contributes a percentage of the amount contributed to the Plan
by the employee. In 1990, the Company borrowed $40,000,000 at an interest rate
of 9.2% to be repaid in equal annual installments over 15 years. The proceeds
of the loan were lent on similar terms to the Plan Trustee, which purchased
1,922,297 shares of Company common stock. The loan, which is reflected as
long-term debt, is offset by a similar amount in common shareholders' equity as
unallocated stock. Company contributions plus the dividends on the shares held
under the Plan are used to meet principal and interest payments on the loan.
Shares acquired with loan proceeds are allocated to Plan participants. As
principal payments on the loan are made, long-term debt and the offset in
common shareholders' equity are both reduced. At December 31, 1995,
738,371 shares had been allocated to the participants' accounts.
Expense for the Plan is recognized using the Shares Allocated Method, and
consists of the following for the three years ended December 31:
1995 1994 1993
Thousands of Dollars
Principal allocated.................... $ 2,663 $ 2,663 $ 2,663
Interest incurred...................... 2,939 3,114 3,275
Dividends.............................. (3,033) (3,046) (3,028)
Additional contribution................ 3,041 2,952 2,310
Total expense..................... $ 5,610 $ 5,683 $ 5,220
The Company's amount of Plan costs funded, which currently is less than
the aforementioned expense amounts, is included in utility rates. Accordingly,
the difference of $746,000, $968,000 and $758,000 for the years ending
December 31, 1995, 1994 and 1993, respectively, were recorded as a reduction of
Plan expense.
Under the Long-Term Incentive Plan, options have been issued to Company
employees. Options issued to Utility employees are not reflected in balance
sheet accounts until exercised, at which time (i) authorized, but unissued
shares are issued to the employee, (ii) the capital stock account is credited
with the proceeds and (iii) no charges or credits to income are made. Options
issued to Entech and IPG employees are not reflected in balance sheet accounts.
Rather, upon exercise, outstanding shares are purchased at current market
prices and compensation expense is charged with the excess of the market price
over the option price.
Option activity is summarized below:
Number Option Price
Of Shares Per Share
Outstanding
December 31, 1992 536,085 $14.25 - 26.50
Granted -
Exercised (118,243) 14.25 - 26.50
Cancelled (5,532) 14.25 - 26.50
Outstanding
December 31, 1993 412,310 $14.25 - 26.50
Granted 117,100 22.625 - 25.625
Exercised (43,884) 14.25 - 26.50
Cancelled (4,540) 14.25 - 26.50
Outstanding
December 31, 1994 480,986 $17.25 - 26.50
Granted 116,730 21.125 - 22.50
Exercised (19,034) 17.25 - 26.50
Cancelled (8,700) 22.125 - 22.625
Outstanding
December 31, 1995 569,982 $17.25 - 26.50
Options Exercisable at
December 31, 1995 569,982
Options were granted at 100% of the closing price on the New York Stock
Exchange on the date granted, and expire ten years from that date. Options
granted prior to January 1, 1987 must be exercised in the order granted.
In 1995 and 1994, restricted stock awards of 2,100 and 64,235,
respectively, were issued to certain Entech employees under the Long-Term
Incentive Plan. Upon the achievement of performance and passage of time
constraints, restrictions will be lifted and participants will retain, at no
cost, the unrestricted shares. As they are earned, the awards are reflected as
common stock and compensation expense on the Balance Sheet and Income
Statement, respectively.
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. Companies electing not to recognize compensation
expense are required to disclose what net income and earnings per share would
have been if the expense were recognized. While the Company does on occasion
issue equity instruments to its key employees, the total value is not material.
At this time, the Company expects to elect the disclosure option of SFAS No.
123 rather than recognition of compensation expense.
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:
Shares Amount
Issued and Thousands of
Series Outstanding Dollars
$6.875 500,000 $ 50,000
6.00 159,589 15,959
4.20 60,000 6,025
2.15 1,200,000 30,000
1,919,589 $ 101,984
The stated value and liquidation price of preferred shares is $100 for
the $6.875 series, the $6.00 series and the $4.20 series and $25 for the
$2.15 series, plus accumulated dividends. The preferred stock is redeemable at
the option of the Company upon the written consent or affirmative vote of the
holders of a majority of the common shares on thirty days notice at $110 per
share for the $6.00 series, $103 per share for the $4.20 series and $25.25 per
share for the $2.15 series, plus accumulated dividends. The $6.875 series is
redeemable in whole or in part, at anytime on or after November 1, 2003 for a
price beginning at $103.438 per share with annual decrements through October
2013, after which the redemption price is $100 per share. At the annual
meeting of shareholders in May 1994, shareholders approved a proposal
permitting the redemption of the $2.15 series.
NOTE 7 - Long-term debt:
Long-term debt consists of the following:
December 31
1995 1994
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 128,000 88,000
Pollution Control Revenue Bonds:
City of Forsyth, Montana
6 1/8% series, due 2023 90,205 90,205
5.9% series, due 2023 80,000 80,000
Sinking Fund Debentures:
7 1/2%, due 1998 16,500 17,000
ESOP Notes Payable, due 2004 29,861 31,943
Unsecured Medium-Term Notes, Series A 38,250 48,250
Revolving Credit Agreements - Entech 10,000
Other 17,696 19,847
Unamortized Discount and Premium (4,134) (4,389)
641,378 605,856
Less: Portion due within one year 24,804 16,980
$ 616,574 $ 588,876
First Mortgage Bonds:
The Company's Mortgage and Deed of Trust imposes a first mortgage lien on
all physical properties owned, exclusive of subsidiary company assets, and
certain property and assets specifically excepted. The obligations
collateralized are First Mortgage Bonds, including those First Mortgage Bonds
designated as Secured Medium-Term Notes and those securing Pollution Control
Revenue Bonds set forth above, in the aggregate principal amount of
$533,205,000 at December 31, 1995.
At December 31, 1995 and 1994, the Company had outstanding $128,000,000
and $88,000,000 principal amount of Secured Medium-Term Notes, respectively,
maturing from 2 to 30 years with interest rates varying between 5.75% and
8.11%.
In April 1995, the Company sold $20,000,000 of Secured Medium-Term Notes,
7.33% series due 2025. The proceeds of which were used to finance construction
and repay short-term debt. In November 1995, the Company sold $20,000,000 of
Secured Medium-Term Notes, $10,000,000 of a 5.75% series due 1997 and
$10,000,000 of a 5.9% series due 1998. The proceeds were used to finance
construction and retire $10,000,000 of Unsecured Medium-Term Notes, 8.87%
series due 1995.
ESOP Notes Payable:
In 1990, the Company borrowed $40,000,000 at an interest rate of 9.2% in
a 15-year loan to be repaid in equal annual installments. The proceeds of the
loan were used to purchase shares of the Company's stock to pre-fund a portion
of the Company's matching requirements under the Deferred Savings and Employee
Stock Ownership Plan. See Note 5 - Common stock for further information.
Unsecured Medium-Term Notes, Series A:
At December 31, 1995 and 1994, the Company had outstanding $38,250,000
and $48,250,000 principal amount of Unsecured Medium-Term Notes, respectively,
maturing from 1 to 27 years with interest rates varying between 8.68% and
8.90%.
Revolving Credit Agreements:
The Company has a Revolving Credit Agreement that allows it to borrow up
to $60,000,000, all of which was unused at December 31, 1995. Under the
agreement, borrowings outstanding at October 27, 1998, must be repaid at that
time.
Entech has a Revolving Credit and Term Loan Agreement with a group of
banks that allows it to borrow up to $75,000,000, of which $65,000,000 was
unused at December 31, 1995. Under the agreement, borrowings outstanding at
September 30, 1997 must be repaid at that time. After recording the
SFAS No. 121 adjustment, the fourth quarter coverage ratio did not meet the
requirements of the Agreement. The Company requested and expects to receive a
waiver from the banks with respect to the coverage ratio for the fourth
quarter.
Fixed or variable interest rate options are available under the
facilities, with commitment fees on the unused portions.
During the period 1996 through 2000, the Company is required to make the
following maturity and sinking fund payments on long-term debt:
1996 1997 1998 1999 2000
Thousands of Dollars
7.7% First Mortgage Bonds.. $ 55,000
Secured Medium-Term Notes.. $ 20,000 $ 20,000 $ 20,000
7 1/2% Sinking Fund
Debentures............... $ 500 500 15,500
Revolving Credit
Agreement - Entech....... 10,000
ESOP Notes Payable......... 2,274 2,483 2,712 2,961 3,234
Unsecured Medium-Term
Notes.................... 8,750 7,500 2,500 2,500 10,000
Other...................... 13,280 969 1,030 636 672
$ 24,804 $ 41,452 $ 41,742 $ 61,097 $ 33,906
NOTE 8 - Short-term borrowing:
The Company is authorized by the PSC to incur short-term debt not to
exceed $150,000,000. The Company and Entech have short-term borrowing
facilities with commercial banks that provide both committed, as well as
uncommitted lines of credit, and the ability to sell commercial paper. Bank
borrowings either bear interest at the lender's floating base rate and may be
repaid at any time, or have fixed rates of interest and maturities. Commercial
paper has fixed rates of interest and maturities.
At December 31, 1995, the Company had lines of credit consisting of
$65,000,000 committed and $70,400,000 uncommitted, and Entech had lines of
credit consisting of $15,000,000 committed and $20,000,000 uncommitted. There
is a commitment fee on the unused portion of some of these facilities which is
not significant. The Company has the ability, subject to the previously
mentioned PSC limitation, to issue up to $125,000,000 of commercial paper and
Entech up to $50,000,000 of commercial paper based on the total of unused
committed lines of credit and revolving credit agreements.
At December 31, 1995 and 1994, the Company's and Entech's short-term
borrowing included the following:
1995 1994
Thousands of Dollars
Notes payable to banks
MPC.......................... $ 53,000 $ 90,000
Entech....................... 25,400 14,000
Commercial paper
Entech....................... 17,948 9,989
$ 96,348 $ 113,989
NOTE 9 - Retirement plans:
The Company maintains trusteed, noncontributory retirement plans covering
substantially all employees. Retirement benefits are based on salary, years of
service and social security integration levels.
In 1995, 1994 and 1993, pension costs funded were less than SFAS No. 87
pension expense by $1,501,000, $2,770,000 and $1,887,000, respectively and the
difference was recorded as a deferred charge. The amount of Utility pension
costs funded are included in rates. At December 31, 1995, the cumulative
amount by which SFAS No. 87 pension expense exceeded pension costs funded was
$2,909,000.
The assets of the plans consist primarily of domestic and foreign
corporate stocks, domestic corporate bonds and U.S. Government securities.
The Company also has an unfunded, nonqualified benefit plan for senior
management executives and directors that provides for defined benefit payments
upon retirement over the life of the participant or to their beneficiary for a
minimum fifteen-year period. Life insurance payable to the Company is carried
on plan participants as an investment. Utility nonqualified benefit plan
expense is not included in rates.
Net pension and benefit expense includes the following components:
1995 1994 1993
Thousands of Dollars
Service cost benefits earned during
the period.......................... $ 6,204 $ 8,442 $ 6,746
Interest cost on projected benefit
obligation.......................... 14,594 13,430 12,077
Actual return market value of assets.. (13,090) (13,051) (18,701)
Net amortization and deferral......... 1,718 3,788 10,891
Total net periodic pension and
benefit expense................... $ 9,426 $ 12,609 $ 11,013
The funded status of the pension and benefit plans is as follows:
<TABLE>
<CAPTION>
December 31
1995 1994
Thousands of Dollars
<S> <C> <C>
Actuarial present value of accumulated plan
benefits:
Vested...................................... $ 149,787 $ 119,298
Nonvested................................... 17,799 13,066
Accumulated benefit obligation.................. 167,586 132,364
Effect of projected future compensation levels.. 53,514 40,474
Projected benefit obligation.................... 221,100 172,838
Plan assets at fair value....................... 197,389 153,916
Plan assets less than projected
benefit obligation............................ (23,711) (18,922)
Unrecognized net loss (gain) from past
experience different from that assumed and
effects of changes in assumptions............. (7,137) (9,402)
Prior service cost not yet recognized in net
periodic pension expense...................... 10,466 11,498
Unrecognized initial obligation................. 2,852 3,261
Prepaid (Accrued) benefits expense............ $ (17,530) $ (13,565)
</TABLE>
The following assumptions were used in the determination of actuarial
present values of the projected benefit obligations:
<TABLE>
<CAPTION>
December 31
1995 1994
<S> <C> <C>
Assumed discount rates:
Active service and vested terminations........ 7.00% 8.25%
Retired employees............................. 7.00% 8.25%
Long-term rate of average compensation increase. 4.00%-4.90% 4.25%-5.20%
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. Until 1993, the cost of retiree health care and
life insurance benefits was recognized as expense on a pay-as-you-go (cash)
basis. The cost of these benefits in 1993 was $1,387,000.
In 1994, the Company established a pre-funding plan for postretirement
benefits for Utility employees retiring after January 1, 1993. Funding costs
for the plan for 1995 and 1994 were $2,077,000 and $1,487,000, respectively.
The assets of the plan consist primarily of domestic and foreign corporate
stocks, domestic corporate bonds and U.S. Government securities.
The Company adopted SFAS No. 106 effective January 1, 1993. SFAS No. 106
requires accrual of the expected cost of these postretirement benefits during
the employees' years of service rather than when the costs are paid.
In accordance with an Accounting Order issued by the PSC in 1992, the
Company recorded as a deferred expense $600,000 and $2,100,000 representing the
increased costs in 1994 and 1993, respectively, from adopting SFAS No. 106 for
the Utility Division. In its April 28, 1994 Order, the PSC allowed the Company
to include in rates the full OPEB cost on the accrual basis provided by SFAS
No. 106, including the amortization of the amounts previously deferred under a
PSC Accounting Order from January 1, 1993 to April 27, 1994. Consequently, as
of April 28, 1994, the Company commenced recognition of these Utility
postretirement benefits in expense in accordance with SFAS No. 106. The
incremental increase in 1994 consolidated expenses due to the Utility SFAS
No. 106 expense recognition was approximately $1,500,000.
The cost of SFAS No. 106 adoption for the years ended December 31, 1995
and 1994, portions of which have been deferred or capitalized, includes the
following components:
December 31
1995 1994
Thousands of Dollars
Service cost on benefits earned
during the year $ 1,221 $ 1,455
Interest cost on projected benefit
obligation 2,482 2,323
Actual return market value of assets (219) (38)
Net amortizations 1,299 1,535
Total postretirement benefit cost $ 4,783 $ 5,275
The funded status of the postretirement benefit plans other than pensions is as
follows:
December 31
1995 1994
Thousands of Dollars
Accumulated benefit obligation:
Fully eligible active employees $ 1,939 $ 2,253
Other active employees 22,856 19,857
Retirees 11,909 8,751
Accumulated benefit obligation 36,704 30,861
Plan assets at fair value 3,714 1,479
Plan assets less than projected
benefit obligation (32,990) (29,382)
Unrecognized net transition obligation 24,728 25,560
Unrecognized net loss (gain) from past
experience different from that
assumed and effects of changes
in assumptions 542 (2,417)
Prepaid (accrued) benefits expense $ (7,720) $ (6,239)
In 1995, the Company accrued the estimated expected postretirement
benefit obligation for the plan curtailment at Basin Resources, Inc. during
1996 as part of the writedown of long-lived assets (see Note 11 - Asset
impairment).
The assumed 1995 health care cost trend rates used to measure the
expected cost of benefits covered by the plans are 8.50% and 10% for the
utility and non-utility operations, respectively. The trend rates decrease
through 2004 to 5%. The trend rates are for pre-65 benefits since most of the
plans provide a fixed dollar annual benefit for retirees over age 65. One
Entech subsidiary's plan used a trend rate of 9% decreasing through 2003 to an
ultimate rate of 5% for post-65 benefits. The effect of a 1% increase in each
future year's assumed health care cost trend rates increases the service and
interest cost from $3,700,000 to $4,100,000 and the accumulated postretirement
benefit obligation from $24,700,000 to $28,000,000.
On January 1, 1994, the Company adopted Statement of Financial Accounting
Standards No. 112, "Employers' Accounting for Postemployment Benefits," (SFAS
No. 112) with respect to disability related benefits up to age 65. SFAS
No. 112 requires the accrual of a liability or loss contingency for the
estimated obligation for postemployment benefits. At December 31, 1993, the
postemployment benefit liability for regulated utility operations was estimated
to be $9,300,000, of which $2,400,000 had been accrued and included in rates.
The remaining $6,900,000 was recorded in 1994 as a deferred charge and will be
expensed and included in rates over the next ten years. The estimated
December 31, 1993 postemployment benefit liability of $1,300,000 for non-
utility operations 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 as previously discussed.
NOTE 10 - Information on industry segments:
The Company's principal business includes regulated utility operations
involving the generation, purchase, transmission and distribution of
electricity and the production, purchase, transportation and distribution of
natural gas. The Company, through Entech, engages in nonutility operations
principally involving the mining and sale of coal, exploration for, and the
development, production, processing and sale of oil and natural gas and the
sale of telecommunication equipment and services. The Company, through IPG,
manages long-term power sales, develops and invests in independent power
projects and other energy-related businesses.
Substantially all of the natural gas produced by the Company's Canadian
utility operations has been sold to the Company's United States utility
operations.
Pre-tax operating income for the Utility, Entech and IPG segments
represents revenues excluding earnings from unconsolidated investments less all
costs and expenses except interest and other (income) deductions-net.
Immaterial intersegment sales are not disclosed.
Identifiable assets of each industry segment are those assets used in the
Company's operations in such industry segments. Corporate assets are
principally miscellaneous special funds, cash and temporary cash investments,
other investments and unallocable property. The assets of the Company's
Canadian operations were $77,282,000, $79,337,000 and $80,553,000 at
December 31, 1995, 1994 and 1993, respectively.
Operations Information:
<TABLE>
<CAPTION>
Year Ended
December 31, 1995
Thousands of Dollars
<S> <C> <C>
UTILITY Electric Natural Gas
Sales to unaffiliated customers $ 422,019 $ 115,120
Intersegment sales 5,793 862
Pre-tax operating income 124,916 30,933
Earnings from unconsolidated investments
Depreciation, depletion and amortization 42,506 10,793
Capital expenditures 127,917 35,091
Identifiable assets 1,503,619 410,267
<CAPTION>
Oil and
ENTECH Coal* Natural Gas Other
<S> <C> <C> <C>
Sales to unaffiliated customers $ 210,377 $ 100,198 $ 26,238
Intersegment sales 25,659 241 662
Writedown of long-lived assets 55,102 19,194
Pre-tax operating income (loss) (41,003) (8,504) 2,148
Earnings (loss) from unconsolidated
investments (2,860) 70
Depreciation, depletion and amortization 11,187 17,569 1,745
Capital expenditures 19,230 34,780 8,681
Identifiable assets 250,132 177,744 39,624
<CAPTION>
INDEPENDENT POWER GROUP
<S> <C>
Sales to unaffiliated customers $ 79,095
Intersegment sales 796
Pre-tax operating income 3,027
Earnings from unconsolidated investments 2,622
Depreciation, depletion and amortization 3,176
Capital expenditures 4,168
Identifiable assets 161,602
<CAPTION>
CORPORATE
<S> <C>
Sales to unaffiliated customers
Intersegment sales
Pre-tax operating income
Earnings from unconsolidated investments
Depreciation, depletion and amortization
Capital expenditures $ 1,220
Identifiable assets 43,103
* Sales under one coal contract with Houston Light and Power Company amounted to
$102,844,000.
</TABLE>
Operations Information:
<TABLE>
<CAPTION>
Year Ended
December 31, 1994
Thousands of Dollars
UTILITY Electric Natural Gas
<S> <C> <C>
Sales to unaffiliated customers $ 427,686 $ 107,105
Intersegment sales 5,924 917
Pre-tax operating income 98,070 29,576
Earnings from unconsolidated investments
Depreciation, depletion and amortization 40,699 9,842
Capital expenditures 108,933 41,969
Identifiable assets 1,430,516 368,320
<CAPTION>
Oil and
ENTECH Coal* Natural Gas Other
<S> <C> <C> <C>
Sales to unaffiliated customers $ 255,247 $ 97,994 $ 24,096
Intersegment sales 42,201 254 787
Pre-tax operating income 48,344 13,647 1,147
Earnings (loss) from unconsolidated
investments (2,740) 68
Depreciation, depletion and amortization 12,649 18,464 1,945
Capital expenditures 16,115 32,417 492
Identifiable assets 291,224 179,261 33,769
<CAPTION>
INDEPENDENT POWER GROUP
<S> <C>
Sales to unaffiliated customers $ 93,647
Intersegment sales 1,461
Pre-tax operating income 10,912
Earnings from unconsolidated investments 2,080
Depreciation, depletion and amortization 3,112
Capital expenditures 6,154
Identifiable assets 159,138
<CAPTION>
CORPORATE
<S> <C>
Sales to unaffiliated customers
Intersegment sales
Pre-tax operating income
Earnings from unconsolidated investments
Depreciation, depletion and amortization
Capital expenditures $ 1,231
Identifiable assets 50,469
* Sales under one coal contract with Houston Light and Power Company amounted to
$101,845,000.
</TABLE>
Operations Information:
<TABLE>
<CAPTION>
Year Ended
December 31, 1993
Thousands of Dollars
UTILITY Electric Natural Gas
<S> <C> <C>
Sales to unaffiliated customers $ 426,746 $ 110,696
Intersegment sales 7,532 778
Pre-tax operating income 112,530 30,942
Earnings from unconsolidated investments
Depreciation, depletion and amortization 39,151 9,006
Capital expenditures 83,308 28,871
Identifiable assets 1,338,560 359,223
<CAPTION>
Oil and
ENTECH Coal* Natural Gas Other
<S> <C> <C> <C>
Sales to unaffiliated customers $ 227,285 $ 117,659 $ 24,429
Intersegment sales 39,637 741 700
Pre-tax operating income 45,220 14,974 714
Loss from unconsolidated investments (2,130) (3,228) (177)
Depreciation, depletion and amortization 10,193 19,327 2,133
Capital expenditures 26,253 38,547 1,875
Identifiable assets 276,158 169,310 36,374
<CAPTION>
INDEPENDENT POWER GROUP
<S> <C>
Sales to unaffiliated customers $ 119,189
Intersegment sales 5,528
Pre-tax operating loss (4,465)
Earnings from unconsolidated investments 3,117
Depreciation, depletion and amortization 2,887
Capital expenditures 4,542
Identifiable assets 163,550
<CAPTION>
CORPORATE
<S> <C>
Sales to unaffiliated customers
Intersegment sales
Pre-tax operating income
Earnings from unconsolidated investments
Depreciation, depletion and amortization
Capital expenditures $ 156
Identifiable assets 42,852
* Sales under one coal contract with Houston Light and Power Company amounted to
$98,569,000.
</TABLE>
NOTE 11 - 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, an impairment test is required to determine whether the carrying
amount of long-lived and certain intangible assets may be recoverable through
future undiscounted cash flows. Based upon tests performed as prescribed by
SFAS No. 121, the Company recorded a before tax charge against income of
$74,300,000.
The impairment includes a $46,500,000 before tax charge to record the
writedown of the assets and to recognize the closure liabilities of Entech's
subsidiary, Basin Resources, Inc. (Basin), which owns and operated the Golden
Eagle Mine in Colorado. Basin has been unable to operate without losses
because of operating problems and a market where prices continue to be low. On
December 29, 1995, Basin announced that all coal sales agreements had been
terminated, that underground production would cease immediately, and that the
Mine would be permanently closed by March 31, 1996, unless a viable buyer is
identified. To date, efforts to sell the Mine have been unsuccessful. In
addition to the Basin impairment, Entech's Coal Division recorded impairment
charges of approximately $8,600,000 before tax for certain non-producing
leaseholds and other investments. Based upon management's evaluation, these
assets were not expected to generate sufficient undiscounted cash flows to
cover their carrying values.
Entech's Oil Division properties were also affected by the adoption of
SFAS No. 121. The Oil Division recorded an impairment charge of $19,200,000
before tax. Based upon updated reserve studies and tests performed under SFAS
No. 121, the expected undiscounted cash flows from reserves in certain fields
were not sufficient to recover the carrying value of those properties.
Expected depreciation and depletion reductions in 1996 will be
approximately $2,000,000 after taxes.
SUPPLEMENTARY DATA
OIL AND NATURAL GAS PRODUCING ACTIVITIES
<TABLE>
<CAPTION>
For the years ended December 31, 1995, 1994 and 1993 net recoverable oil and
natural gas reserves, excluding royalty volumes and volumes controlled under purchase
contract, of the Utility and Entech operations were estimated as follows:
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
ENTECH 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
1995
U.S. CANADA
PROVED DEVELOPED RESERVES:
UTILITY OPERATIONS:
Natural Gas (Mmcf):
Ending Balance 74,630 103,475
ENTECH 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
PROVED DEVELOPED AND UNDEVELOPED RESERVES:
<S> <C> <C> <C>
UTILITY OPERATIONS:
Natural Gas (Mmcf):
Beginning Balance 80,070 98,871 56,318
Production (4,742) (3,350)
Additions 87 570 230
(Sales) and Purchases of Reserves in Place
Revisions - Other 5,147 480
Revisions - Price
Ending Balance 80,562 96,571 56,548
ENTECH OPERATIONS:
Natural Gas (Mmcf):
Beginning Balance 140,923 59,071
Production (9,444) (7,785)
Additions 4,683 13,830
(Sales) and Purchases of Reserves in Place 2,250 5,866
Revisions - Other 14,385 4,987
Revisions - Price 365 3,314
Ending Balance 153,162 79,283
Natural Gas
Liquids (Bbls):
Beginning Balance 3,682,700 1,508,100
Production (376,650) (172,600)
Additions 103,300 365,300
(Sales) and Purchases of Reserves in Place (116,298) 81,184
Revisions - Other (199,552) 217,216
Revisions - Price 16,800 300
Ending Balance 3,110,300 1,999,500
Oil (Bbls):
Beginning Balance 6,238,700 4,511,600
Production (440,040) (709,248)
Additions 77,800 1,497,400
(Sales) and Purchases of Reserves in Place 821,276 (215,042)
Revisions - Other (740,736) (135,310)
Revisions - Price 122,700 (14,400)
Ending Balance 6,079,700 4,935,000
1994
U.S. CANADA
PROVED DEVELOPED RESERVES:
UTILITY OPERATIONS:
Natural Gas (Mmcf):
Ending Balance 79,731 96,571
ENTECH OPERATIONS:
Natural Gas (Mmcf):
Ending Balance 89,305 65,454
Natural Gas Liquids (Bbls):
Ending Balance 2,588,700 1,634,200
Oil (Bbls):
Ending Balance 3,194,600 3,437,600
</TABLE>
<TABLE>
<CAPTION>
1993
U.S. CANADA STORAGE
PROVED DEVELOPED AND UNDEVELOPED RESERVES:
<S> <C> <C> <C>
UTILITY OPERATIONS:
Natural Gas (Mmcf):
Beginning Balance 83,264 101,220 59,075
Production (5,587) (3,927)
Additions 788 (2,757)
(Sales) and Purchases of Reserves in Place
Revisions - Other 2,393 790
Revisions - Price
Ending Balance 80,070 98,871 56,318
ENTECH OPERATIONS:
Natural Gas (Mmcf):
Beginning Balance 133,421 41,620
Production (10,740) (6,735)
Additions 24,414 17,758
(Sales) and Purchases of Reserves in Place (130) 1,024
Revisions - Other (4,937) (74)
Revisions - Price (1,105) 5,478
Ending Balance 140,923 59,071
Natural Gas
Liquids (Bbls):
Beginning Balance 1,071,700 907,500
Production (143,059) (134,509)
Additions 597,100 452,766
(Sales) and Purchases of Reserves in Place (861,059) (8,353)
Revisions - Other 3,030,018 236,058
Revisions - Price (12,000) 54,638
Ending Balance 3,682,700 1,508,100
Oil (Bbls):
Beginning Balance 3,877,900 4,793,400
Production (528,408) (917,992)
Additions 3,157,100 1,208,328
(Sales) and Purchases of Reserves in Place 55,811 (115,014)
Revisions - Other (127,288) (373,231)
Revisions - Price (196,415) (83,891)
Ending Balance 6,238,700 4,511,600
1993
U.S. CANADA
PROVED DEVELOPED RESERVES:
UTILITY OPERATIONS:
Natural Gas (Mmcf):
Ending Balance 79,239 98,871
ENTECH OPERATIONS:
Natural Gas (Mmcf):
Ending Balance 89,372 51,437
Natural Gas Liquids (Bbls):
Ending Balance 3,088,600 1,314,300
Oil (Bbls):
Ending Balance 3,190,000 4,265,400
</TABLE>
SUPPLEMENTARY DATA
Oil and Natural Gas Producing Activities (Cont.)
As determined by engineers, Utility natural gas reserves were revised
during 1995, 1994 and 1993 due to a change in projected performance or a change
in the Company's ownership interest in specific fields.
In 1995, Entech's 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 Entech's 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, Entech's U.S. oil and natural gas reserves increased as a result
of the acquisition of oil interests in Kansas and the drilling of 25
development wells and 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.
In 1993, Entech's U.S. oil and natural gas reserves increased as a result
of the drilling of 55 development wells and 10 exploratory wells in Colorado,
North Dakota, Wyoming, Oklahoma and Kansas. Natural gas liquid reserves
increased due to the startup of the Fort Lupton, Colorado gas processing plant
in September 1993. Lower oil market prices contributed to downward revisions
in U.S. reserves. The Canadian companies participated in 26 development and 13
exploratory wells. Significant gas reserves were added from discoveries in the
exploratory wells. Additions in oil reserves were the result of two successful
secondary recovery schemes completed in the Manyberries area in Southern
Alberta during 1993. Revisions due to price and performance resulted in a net
increase in natural gas liquid reserves and a net decrease in oil reserves.
The following table presents information for 1995, 1994 and 1993 on the
capitalized costs relating to utility natural gas producing activities, costs
incurred in utility natural gas property acquisition, exploration and
development activities and certain utility natural gas production costs
reflected in results of operations. As a regulated public utility, the Company
is authorized to earn a rate of return on its utility natural gas plant rate
base. The Company's cost of acquiring utility natural gas reserves and the net
cost of natural gas in underground storage are included in the natural gas
plant which is a part of the utility rate base. Due to the commingling of
produced natural gas with purchased and royalty natural gas for sale to utility
customers and application of the ratemaking process to the utility natural gas
producing activities, the Company is unable to identify revenues resulting
solely from utility natural gas producing activities. Accordingly, the
information on revenues, income taxes, results of operations and estimated
future net cash flows and changes therein relating to proved utility natural
gas reserves are not presented for the Company's utility natural gas producing
activities.
<TABLE>
<CAPTION>
1995 1994 1993
U.S. Canada U.S. Canada U.S. Canada
UTILITY OPERATIONS Thousands of Dollars
<S> <C> <C> <C> <C> <C> <C>
At December 31:
Capitalized costs relating
to natural gas producing
activities $ 89,520 $ 37,683 $ 95,713 $ 36,904 $ 90,711 $ 35,786
Accumulated depreciation,
depletion and valuation
allowances 50,377 19,812 48,913 19,386 44,516 18,815
Net capitalized costs $ 39,143 $ 17,871 $ 46,800 $ 17,518 $ 46,195 $ 16,971
For the year ended
December 31:
Costs incurred in natural
gas property acquisition,
exploration and
development activities:
Acquisition of
properties $ 48 $ 170 $ 414 $ 259 $ 46 $ 27
Exploration 70 198 358 231 386 244
Development 1,753 1,240 5,158 1,203 1,528 496
Costs reflected in results
of operations:
Production costs $ 5,710 $ 1,592 $ 4,795 $ 1,348 $ 4,958 $ 1,391
Exploration expenses 70 198 128 231 148 244
Development expenses 165 416 165 197 90 59
Depreciation, depletion
and valuation
provisions 2,716 586 2,607 487 2,564 283
</TABLE>
The following table presents information for 1995, 1994 and 1993 on the
capitalized costs relating to Entech oil and natural gas producing activities,
costs incurred in Entech oil and natural gas property acquisition, exploration
and development activities and results of Entech operations for oil and natural
gas producing activities:
<TABLE>
<CAPTION>
1995 1994 1993
U.S. Canada U.S. Canada U.S. Canada
ENTECH OPERATIONS Thousands of Dollars
At December 31:
<S> <C> <C> <C> <C> <C> <C>
Capitalized costs relating
to oil and natural gas
producing activities $171,795 $83,457 $145,639 $ 78,667 $136,949 $ 88,596
Accumulated depreciation,
depletion and valuation
allowances 60,329 39,834 39,534 27,247 36,725 34,426
Net capitalized costs $111,466 $43,623 $106,105 $ 51,420 $100,224 $ 54,170
For the year ended
December 31:
Costs incurred in oil and
natural gas property
acquisition, exploration
and development
activities:
Acquisition of
properties $ 13,024 $ 4,407 $ 8,134 $ 5,866 $ 1,700 $ 2,638
Exploration 4,592 1,642 2,513 1,924 2,838 2,711
Development 11,244 4,298 11,514 4,068 26,279 5,721
Results of operations for
oil and natural gas
producing activities:
Revenues $ 20,461 $19,022 $ 25,319 $ 22,542 $ 30,713 $ 23,435
Production costs 7,298 6,812 7,261 7,404 9,459 7,629
Exploration expenses 2,460 1,517 1,610 1,426 2,123 2,184
Depreciation, depletion
and valuation
provisions 21,079 15,371 10,533 7,669 10,386 8,707
(10,376) (4,678) 5,915 6,043 8,745 4,915
Income tax expenses (5,708) (2,087) 25 2,679 978 2,179
Results of operations from
producing activities
(excluding corporate
overhead and interest
cost) $ (4,668) $(2,591) $ 5,890 $ 3,364 $ 7,767 $ 2,736
</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.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS AND CHANGES THEREIN RELATING TO
PROVED OIL AND NATURAL GAS RESERVES
<TABLE>
<CAPTION>
December 31
1995 1994
U.S. Canada U.S. Canada
Thousands of Dollars
<S> <C> <C> <C> <C>
Future cash inflows $ 523,563 $ 148,140 $ 603,543 $ 185,877
Future production and
development costs 197,073 57,455 200,004 69,043
Future income tax expenses 89,726 18,033 114,953 29,952
Future net cash flows 236,764 72,652 288,586 86,882
10% annual discount for
estimated timing
of cash flows 98,831 16,163 122,835 23,382
Standardized measure of
discounted future net
cash flows $ 137,933 $ 56,489 $ 165,751 $ 63,500
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 (a) $ (33,013) $ (24,585) $ (33,342) $ (19,556)
Net changes in prices,
development and production
costs (24,122) (7,886) 1,939 (15,010)
Extensions, discoveries, and
improved recovery, less
related costs 8,100 1,728 13,454 18,687
Revisions of previous quantity
estimates (12,950) 4,860 12,868 3,449
Accretion of discount 20,816 7,483 18,839 8,198
Net change in income taxes 10,948 6,315 (4,683) 1,895
Other (a) 2,403 5,074 6,008 (2,928)
(a) Certain reclassifications have been made to the prior year amounts to make them
comparable to the 1995 presentation.
</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 1995 and 1994, 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 1995 and 1994
are shown in the tables below. Operating revenues and income include
intersegment sales and expenses. Due to the seasonal nature of the utility
business, the annual amounts are not generated evenly by quarter during the
year.
<TABLE>
<CAPTION>
Quarter Ended
Dec. 31, Sept. 30, June 30, Mar. 31,
1995 1995 1995 1995
<S> <C> <C> <C> <C>
Utility Operating Revenues $ 165,281 $ 110,254 $ 108,150 $ 160,109
Utility Operating Income 61,213 19,218 16,084 59,334
Utility Net Income 32,204 6,251 3,768 30,967
Entech Operating Revenues 95,880 95,601 85,754 83,350
Entech Operating Income (Loss) (60,429) 8,172 2,628 (520)
Entech Net Income (Loss) (33,547) 8,216 3,143 1,669
IPG Operating Revenues 21,244 21,616 18,113 21,540
IPG Operating Income 1,113 1,940 406 2,190
IPG Net Income 226 1,685 659 1,696
Consolidated Net Income (Loss) (1,117) 16,152 7,570 34,332
Net Income (Loss) Per Share of
Common Stock (0.05) 0.26 0.11 0.60
Quarter Ended
Dec. 31, Sept. 30, June 30, Mar. 31,
1994 1994 1994 1994
Utility Operating Revenues $ 166,711 $ 110,394 $ 104,315 $ 160,212
Utility Operating Income 55,546 8,670 10,728 52,702
Utility Net Income 27,843 130 1,162 26,274
Entech Operating Revenues 109,503 107,796 91,379 109,229
Entech Operating Income 15,715 15,574 12,141 17,036
Entech Net Income 13,896 12,393 9,772 11,827
IPG Operating Revenues 27,070 27,404 20,740 21,974
IPG Operating Income (Loss) 6,555 5,573 (905) 1,769
IPG Net Income (Loss) 3,686 5,758 (225) 1,076
Consolidated Net Income 45,425 18,281 10,709 39,177
Net Income Per Share of Common
Stock 0.82 0.31 0.17 0.70
</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 1996 Annual Meeting of Shareholders and
Proxy Statement, pages 1-3.
ITEM 11. EXECUTIVE COMPENSATION
Incorporated by reference from Notice of 1996 Annual Meeting of
Shareholders and Proxy Statement, pages 6-15.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Incorporated by reference from Notice of 1996 Annual Meeting of
Shareholders and Proxy Statement, pages 4-5.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Incorporated by reference from Notice of 1996 Annual Meeting of
Shareholders and Proxy Statement, page 15.
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 24, 1995 Item 5 Other Events. Discussion of Third
Quarter Net Income.
Item 7 Exhibits. Consolidated Statements of
Income for the Quarters Ended September 30,
1995 and 1994, Nine Months Ended September 30,
1995 and 1994, and for the Twelve Months Ended
September 30, 1995 and 1994. Utility
Operations Schedule of Revenues and Expenses
for the Quarters Ended September 30, 1995 and
1994, Nine Months Ended September 30, 1995 and
1994 and for the Twelve Months Ended
September 30, 1995 and 1994. Entech
Operations Schedule of Revenues and Expenses
for the Quarters Ended September 30, 1995 and
1994, Nine Months Ended September 30, 1995 and
1994 and for the Twelve Months Ended
September 30, 1995 and 1994. Independent
Power Group Operations Schedule of Revenues
and Expenses for the Quarters Ended
September 30, 1995 and 1994, Nine Months
Ended September 30, 1995 and 1994 and for the
Twelve Months Ended September 30, 1995 and
1994.
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
3(b) By-laws, as adopted
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
Incorporation by Reference
Previous
Previous Exhibit
Filing Designation
10(a)(iii) Long-Term Incentive Stock 1-4566 10(a)(iii)
Ownership Plan 1992
Form 10-K
10(a)(iv) The Montana Power Company 33-28096 4(c)
Employee Stock Ownership Plan
(Revised)
10(a)(v) Termination Compensation
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>
<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, 1995
Reserves deducted
in balance sheet
from assets to
which they apply:
Doubtful accounts
Utility $ 808 $ 1,065 $ 1,005 $ 868
Entech 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
Entech 643 156 $ (9) 174 616
Total $ 1,391 $ 937 $ (9) $ 895 $ 1,424
December 31, 1993
Reserves deducted
in balance sheet
from assets to
which they apply:
Doubtful accounts
Utility $ 688 $ 764 $ 704 $ 748
Entech 529 391 $ 17 294 643
Total $ 1,217 $ 1,155 $ 17 $ 998 $ 1,391
NOTES:
(a) Deductions are of the nature for which the reserves were created. In the
case of the reserve for doubtful accounts, deductions from this reserve are
reduced by recoveries of amounts previously written off.
</TABLE>
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 22, 1996
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 22, 1996
(Chief Executive Officer)
/s/ J. P. Pederson Principal Financial
J. P. Pederson and Accounting Officer March 22, 1996
(Vice President and Chief and Director
Financial Officer)
/s/ Director March 22, 1996
Tucker Hart Adams
/s/ Alan F. Cain Director March 22, 1996
Alan F. Cain
/s/ R. D. Corette Director March 22, 1996
R. D. Corette
/s/ Robert P. Gannon Director March 22, 1996
Robert P. Gannon
/s/ Kay Foster Director March 22, 1996
Kay Foster
/s/ Beverly D. Harris Director March 22, 1996
Beverly D. Harris
/s/ Chase T. Hibbard Director March 22, 1996
Chase T. Hibbard
/s/ John R. Jester Director March 22, 1996
John R. Jester
/s/ Daniel P. Lambros Director March 22, 1996
Daniel P. Lambros
/s/ Carl Lehrkind, III Director March 22, 1996
Carl Lehrkind, III
/s/ James P. Lucas Director March 22, 1996
James P. Lucas
/s/ Arthur K. Neill Director March 22, 1996
Arthur K. Neill
/s/ George H. Selover Director March 22, 1996
George H. Selover
/s/ N. E. Vosburg Director March 22, 1996
N. E. Vosburg
EXHIBIT INDEX
Exhibit 3(a)(1)
Articles of Amendment to the Restated Articles of Incorporation
Exhibit 3(b)
By-laws, as adopted
Exhibit 10(a)(v)
Termination Compensation Agreements with Senior Management Executives
Exhibit 12
Statement Re Computation of Ratio Earnings to Fixed Charges
Exhibit 21
Subsidiaries of the Registrant
Exhibit 23
Consent of Independent Accountants
Exhibit 27
Financial Data Schedule
- -1-
- -19-
- -28-
- -29-
- -33-
-59-
- -67-
-104-
SIGNATURES (Continued)
- -106-
Exhitit 3(a)(1)
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 30, 1995, in the manner prescribed by the Montana Business
Corporation Act.
Article V of the Restated Articles of Incorporation of the corporation
is amended so that the following paragraph is added at the end thereof:
"Notwithstanding anything contained in these Articles (including
Article VIII hereof) or in the Bylaws of the Corporation to the
contrary (and notwithstanding the fact that a lesser percentage may be
specified by law, these Articles or the Bylaws of the Corporation),
any amendment, alteration, change or repeal of, or the adoption of any
provision inconsistent with, this Article V or Section 11 of the
Bylaws of the Corporation by shareholders shall require the
affirmative vote of the holders of at least two-thirds of the shares
of the Corporation entitled to vote thereon."
THIRD: The number of Common shares of the corporation outstanding at
the record date was 53,819,717 common shares; and the number of such shares
entitled to vote on the amendment was 53,819,717. 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 46,452,016 Preferred 1,625,787
FIFTH: The vote on the Amendment was as follows:
For Against
Common and Preferred Total: 37,635,330 5,941,380
DATED: June _________, 1995.
THE MONTANA POWER COMPANY
\s\P. K. Merrell
Vice President
(SEAL)
R. M. Ralph
Assistant Secretary
STATE OF MONTANA )
ss.
County of Silver Bow )
I, the undersigned Notary Public, do hereby certify that on this 9th
day of June, 1995, personally appeared before me P. K. Merrell, who, being
by me first duly sworn, declared that she is a Vice President of THE MONTANA
POWER COMPANY, that she signed the foregoing document as Vice President of
the Corporation, and that the statements therein contained are true.
\s\Jessica G. Eyde
Notary Public for the State of Montana
(SEAL) Residing at Butte, Montana
My Commission expires 10/29/98
Exhibit 3(b)
BYLAWS
OF
THE MONTANA POWER COMPANY
Adopted on : August 22, 1995
THE MONTANA POWER COMPANY
AMENDMENTS TO BYLAWS
Article Amendment Date of Amendment
11 (A) Establishment of the August 22, 1995
number of Directors as
sixteen (16).
11 (A)(1) The Directors shall be divided August 22, 1995
into three groups, each as
nearly equal 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;
provided, however, that at the
annual meeting of shareholders
to be held in May 1996, seven
(7) Directors shall be elected
with six Directors serving a
term of three (3) years and
one (1) Director serving a
term of two (2) years.
21 Corporate Acquisition August 22, 1995
of its Own Shares.
The Company may acquire its own
shares, and shares so acquired
shall constitute authorized and
issued shares.
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 22, 1995 and that
said Resolution is in full force and effect as of the date of this
certificate.
RESOLVED, that the Board hereby amends the Bylaws of the Company
as proposed and set forth at this meeting.
IN WITNESS WHEREOF, I have hereunto set my hand and the Seal of said
Corporation this 26th day of February 1996.
\s\R. M. Ralph, Assistant Secretary
(SEAL)
1.02
As Adopted August 22, 1995
BYLAWS
OF
THE MONTANA POWER COMPANY
SECTION 1. Principal Office. The principal office of the corporation
is 40 East Broadway, Butte, State of Montana. The Corporation may also have
offices at such other places within or without the State of Montana as the
Board of Directors shall from time to time determine.
SECTION 2. Location of Shareholders Meetings. Meetings of the
shareholders and meetings of the Board of Directors shall be held in Butte,
Montana, or, upon resolution by the Board of Directors, may be held at another
place, within or without the State of Montana.
SECTION 3. Shareholder Meetings.
(A) Annual Meeting of Shareholders.
(1) The annual meeting of the shareholders of the Corporation for
the election of Directors and such other business as shall properly
come before such meeting shall be held on (a) the second Tuesday in May
in each year, unless that date is a legal holiday, in which case such
meeting shall be held on the first day thereafter which is not a legal
holiday, or (b) at such other date and/or time as may be fixed by
resolution of the Board of Directors. Nominations of persons for
election to the Board of Directors of the Corporation and the proposal
of business to be considered by the shareholders may be made at an
annual meeting of shareholders (a) pursuant to the Corporation's notice
of meeting delivered pursuant to Section 5 of these Bylaws, (b) by the
Board of Directors pursuant to a resolution duly adopted or (c) by any
shareholder of the Corporation who is entitled to vote at the meeting,
who complied with the notice procedures set forth in clauses (2) and
(3) of paragraph (A) of this Bylaw and who was a shareholder of record
at the time such notice is delivered to the Secretary of the
Corporation.
(2) For nominations or other business to be properly brought
before an annual meeting by a shareholder pursuant to clause (c) of
paragraph (A) (1) of this Bylaw, the shareholder must have given timely
notice thereof in writing to the Secretary of the Corporation. To be
timely, a shareholder's notice shall be delivered to the Secretary at
the principal executive offices of the Corporation not less than 120
days in advance of the anniversary date of the release of the
Corporation's proxy statement made in connection with the previous
annual meeting; provided, however, that in the event that the date of
the annual meeting is advanced by more than twenty days, or delayed by
more than seventy days, from the anniversary date of the previous
annual meeting, notice by the shareholder to be timely must be so
delivered not later than the close of business on the later of the
120th day prior to such annual meeting or the tenth day following the
day on which public announcement of the date of such meeting is first
made. Such shareholder's notice shall set forth (a) as to each person
whom the shareholder proposes to nominate for election or reelection as
a Director, all information relating to such person that is required to
be disclosed in solicitations of proxies for election of Directors, or
is otherwise required, in each case pursuant to Regulation 14A under
the Securities Exchange Act of 1934, as amended (the "Exchange Act"),
including such person's written consent to being named in the proxy
statement of the nominator as a nominee and to serving as a Director if
elected; (b) as to any other business that the shareholder proposes to
bring before the meeting, a brief description of the business desired
to be brought before the meeting, the reasons for conducting such
business at the meeting and any material interest in such business of
such shareholder and the beneficial owner, if any, on whose behalf the
proposal is made; and (c) as to the shareholder giving the notice and
the beneficial owner, if any, on whose behalf the nomination or
proposal is made (i) the name and address of such shareholder, as they
appear on the Corporation's books, and of such beneficial owner and
(ii) the class and number of shares of the Corporation which are owned
beneficially and of record by such shareholder and such beneficial
owner.
(3) Notwithstanding anything in the second sentence of paragraph
(A) (2) of this Bylaw to the contrary, in the event that the number of
Directors to be elected to the Board of Directors is increased and the
public announcement naming all of the nominees for Director or
specifying the size of the increased Board of Directors is not made by
the Corporation at least ten days prior to the date by which
shareholders proposals and nominations must be received by the
Corporation, a shareholder's notice required by this Bylaw shall also
be considered timely, but only with respect to nominees for any new
positions created by such increase, if it shall be delivered to the
Secretary at the principal executive offices of the Corporation not
later than the close of business on the tenth day following the day on
which such public announcement is first made by the Corporation.
(B) Special Meeting of Shareholders. Only such business shall be
conducted at a special meeting of shareholders as shall have been brought
before the meeting pursuant to the Corporation's notice of meeting pursuant to
Section 5 of these Bylaws. Nominations of persons for election to the Board
of Directors may be made at a special meeting of shareholders at which
Directors are to be elected pursuant to the Corporation's notice of meeting
(i) by or at the direction of the Board of Directors or (ii) by any
shareholder of the Corporation who is entitled to vote at the meeting, who
complies with the notice procedures set forth in this Bylaw and who is a
shareholder of record at the time such notice is delivered to the Secretary of
the Corporation. Nominations by shareholders of persons for election to the
Board of Directors may be made at such a special meeting of shareholders if a
shareholder's notice as described in the third sentence of paragraph (A) (2)
of this Section 3 of the Bylaws shall be delivered to the Secretary at the
principal executive offices of the Corporation not later than the close of
business on the later of the seventieth day prior to such special meeting or
the tenth day following the day on which public announcement is first made of
the date of the special meeting and of the nominees proposed by the Board of
Directors to be elected at such meeting.
(C) General.
(1) Only persons who are nominated in accordance with the
procedures set forth in this Bylaw shall be eligible to serve as
Directors and only such business shall be conducted at a meeting of
shareholders as shall have been brought before the meeting in
accordance with the procedures set forth in this Bylaw. Except as
otherwise provided by the laws of the State of Montana, the Restated
Articles of Incorporation of the Corporation or these Bylaws, the
chairman of the meeting shall have the power and duty to determine
whether a nomination or any business proposed to be brought before the
meeting was made in accordance with the procedures set forth in this
Bylaw and, if any proposed nomination or business is not in compliance
with this Bylaw, to declare that such defective proposal or nomination
shall be disregarded.
(2) For purposes of this Bylaw, "public announcement" shall mean
disclosure in a press release reported by the Dow Jones News Service,
Associated Press or comparable national news service or in a document
publicly filed by the Corporation with the Securities and Exchange
Commission pursuant to Section 13, 14 or 15(d) of the Exchange Act.
(3) Notwithstanding the foregoing provisions of this Bylaw, a
shareholder shall also comply with all applicable requirements of the
Exchange Act and the rules and regulations thereunder with respect to
the matters set forth in this Bylaw. Nothing in this Bylaw shall be
deemed to affect any rights of shareholders to request inclusion of
proposals in the Corporation's proxy statement pursuant to Rule 14a-8
under the Exchange Act.
SECTION 4. Call of Special Meetings of Shareholders. Special meetings
of the shareholders of the Corporation may be held upon the call of the Board
of Directors, Chairman of the Board, Vice Chairman of the Board, Chief
Executive Officer, President, or holders of at least ten percent (10%) of the
number of shares outstanding and entitled to vote thereat, in Butte, Montana.
SECTION 5. Notice of Shareholders Meetings. Notice of every meeting of
shareholders shall be mailed by the Secretary at least ten (10) days before
the meeting, to each holder of record of shares entitled to vote thereat,
tothe last known post office address appearing upon the records of the
Corporation (unless there is provided under the laws of the State of Montana a
different provision for notice of meeting) provided, however, that if a
shareholder waives notice thereof in writing before or after the meeting,
notice of the meeting to such shareholder is unnecessary and that notice to
employee shareholders may be sent to their work addresses through intercompany
mail.
SECTION 6. Shareholder Meeting Quorum. The holders of a majority of the
number of shares of the Corporation entitled to vote, present in person or by
proxy, shall constitute a quorum, but less than a quorum shall have power to
adjourn any meeting from time to time, or to a day certain.
SECTION 7. Shareholder Voting. At every meeting of shareholders, each
holder of shares entitled to vote thereat shall be entitled to one vote for
each share held and may vote and otherwise act in person or by proxy.
SECTION 8. List of Shareholders. Not less than two (2) business days
after notice has been given of a meeting of the shareholders, a full list of
the holders of shares entitled to vote at such meeting, arranged in
alphabetical order, with the residence of each and the number of such shares
held by each, shall be prepared by the Secretary or Officer designated by the
Board of Directors and filed in the principal office of the Corporation, which
shall, at all times during the usual hours of business and during the meeting
or vote, be kept open to the examination of any shareholder.
SECTION 9. Form of Certificates. Share certificates shall be of such
form and device as the Board of Directors may determine, and shall be signed
by the Chairman of the Board of Directors, Vice Chairman, Chief Executive
Officer, President or a Vice President and the Secretary or an Assistant
Secretary, and sealed with the seal of the Corporation, but where such
certificates are signed by a transfer agent or an assistant transfer agent and
a registrar, the signatures of the Chairman of the Board of Directors, Vice
Chairman of the Board, the Chief Executive Officer, President, Vice President,
Secretary or Assistant Secretary and the seal of the Corporation may be
facsimiles.
SECTION 10. Share Transfer. The shares of the Corporation shall be
transferable or assignable on the books of the Corporation by the holders in
person or by attorney on the surrender of the certificates therefor. The
Board of Directors may appoint one or more transfer agents and registrars of
the shares. The Books for the transfer of the shares may be closed for such
period before and during any meeting of shareholders, the payment of any
dividend, the allotment of rights or the date when any change or conversion or
exchange of shares shall go into effect, not to exceed seventy (70) days at
any one time, as the Board of Directors may from time to time determine.
SECTION 11. Directors
(A) Number and Terms. The affairs of the Corporation shall be managed
by a Board of sixteen (16) Directors.
(1) 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; provided, however, that at the annual meeting of
shareholders to be held in May 1996, seven (7) Directors shall be
elected with six Directors serving a term of three (3) years and one
(1) Director serving a term of two (2) years.
(2) The number of Directors may be increased or decreased from
time to time by amendment to these Bylaws duly adopted by the
Directors, but no increase or decrease shall exceed thirty percent
(30%) of the number provided for immediately before the change if that
number was fixed by the shareholders. No decrease in the number of
Directors shall have the effect of shortening the term of any incumbent
Director. The classification and term of Directors may be changed from
time to time by amendment to the Bylaws duly adopted by the Directors,
but no such change shall affect the term of any incumbent director.
B. Removal by Shareholders. The shareholders at any meeting, by the
vote of two-thirds of the number of shares outstanding and entitled to vote
for the election of Directors, may remove any Director and fill the vacancy.
If less than the entire Board is to be removed, no Director may be removed if
the votes cast against the Director's removal would be sufficient to elect
the Director if then cumulatively voted at an election of the class of
Directors of which the Director is a part.
C. Vacancies. Vacancies in the Board of Directors may be filled by the
Board at any meeting at which a quorum is present. If the Directors remaining
in office are fewer than a quorum, the vacancy may be filled by the vote of a
majority of the Directors remaining in office. Any Director appointed by the
Board to fill a vacancy created in the Board of Directors by virtue of an
increase in the number of Directors shall hold office until the next regular
annual meeting of the shareholders at which time the shareholders shall elect
a person to fill such office.
D. Indemnification. The Company shall indemnify each present or future
Director and Officer of the Company in the manner provided in Sections 35-1-
451 through 35-1-459, M.C.A. The foregoing right of indemnification shall not
exclude or restrict any other rights or actions which any Director or Officer
may have, and shall be available whether or not the Director or Officer
continues to hold such office at the time of incurring such expense or
discharging such liability.
SECTION 12. Director Meetings. Meetings of the Board of Directors
shall be held at the times fixed by resolution of the Board or upon call of
the Chairman of the Board, Vice Chairman of the Board, the Chief Executive
Officer, the President or any two Directors. The Secretary shall give
reasonable notice (which need not exceed two days) of all meetings of
Directors, provided that a meeting may be held without notice immediately
after the annual election, and notice need not be given of regular meetings
held at times fixed by resolution of the Board. Meetings may be held at any
time without notice if all the Directors are present or if those not present
waive notice in writing either before or after the meeting. Notice by mail,
facsimile or telegraph to the usual business or residence address of the
Director not less than the time above specified before the meeting shall be
sufficient. A majority of the Board shall constitute a quorum, but any number
less than a quorum may adjourn the meeting from time to time, or to a day
certain.
SECTION 13. Designation of Officers. The Board of Directors, as soon as
may be convenient after the election of Directors in each year, shall elect
one of their number Chairman of the Board and may elect one of their number as
Vice Chairman of the Board. The Board shall also elect a President. The
Board shall either designate any one of these Officers as Chief Executive
Officer of the Corporation, or elect a Chief Executive Officer separately.
The Board shall also elect a Secretary, a Treasurer, a Controller, one
or more Vice Presidents, one or more Assistant Secretaries, one or more
Assistant Treasurers, one or more Assistant Controllers, and such other
Officers as they deem proper.
Any two or more offices may be held by the same person. The term of
office of all Officers shall be until the next election of Directors and until
their respective successors are chosen and qualified, but any Officer may be
removed from office and any office may be abolished at any time by the Board
of Directors. Vacancies in the offices shall be filled by the Board of
Directors, save that the Chairman of the Board, the Chief Executive Officer or
the President may from time to time appoint one or more Assistant Secretaries
and one or more Assistant Treasurers, or may remove such officers; provided
that the Board shall be notified of such appointments or removals at the next
following meeting of the Board.
SECTION 14. Duties of Officers. The powers and duties of the Officers
of the Corporation shall be as follows:
A. Chief Executive Officer. The person designated by the Board to be
the Chief Executive Officer of the Corporation, under the direction of the
Board of Directors, shall have general authority over all the affairs of the
Corporation, and over all other Officers, agents and employees of the Company.
In the event of the absence or disability of the Chief Executive Officer; a)
if the Chief Executive Officer is also Chairman of the Board, then the
provision made for that office shall govern, and b) if the Chief Executive
Officer is separately elected, then the Chairman of the Board shall perform
the duties of that office until the absence ceases, the disability is removed
or the Board of Directors has named a successor.
B. Chairman of the Board. The Chairman of the Board shall preside at
all meetings of the shareholders and at all meetings of the Board of
Directors, and shall also have authority to call special meetings of the Board
of Directors, of the Executive Committee, and of any other standing or special
committee appointed by or upon the authority of the Board of Directors. The
Chairman of the Board shall call meetings of the Executive Committee when
requested by two of its members, and shall do and perform all acts and things
incident to the position of Chairman. At the request of the Chairman, in the
case of absence, or upon a determination of temporary disability of the
Chairman by the Board of Directors, the duties of that office will be
performed by the following officers, selected in the following order:
1) Chief Executive Officer, 2) Vice Chairman of the Board, and 3) President.
C. Vice Chairman. A Vice Chairman of the Board shall have such duties
and authority as may be assigned by the Board of Directors or the Chief
Executive Officer.
D. President. The President shall have such duties and authority as may
be assigned by the Board of Directors or the Chief Executive Officer.
E. Vice President. Each Vice President shall have such authority and
shall perform such duties as shall from time to time be assigned by the Board
of Directors or the Chief Executive Officer.
F. Treasurer. The Treasurer shall have custody of all moneys and funds
of the Corporation, and shall cause to be kept full and accurate records of
receipts and disbursements of the Corporation. The Treasurer shall deposit
all moneys and other valuables of the Corporation in the name and to the
credit of the Corporation in such depositaries as may be designated by the
Board of Directors, and shall disburse such funds of the Corporation as have
been duly approved for disbursement. The Treasurer shall perform such other
duties as may from time to time be prescribed by the Board of Directors or the
Chief Executive Officer.
G. Assistant Treasurer. The Assistant Treasurers shall perform such
duties as may be assigned from time to time by the Chief Executive Officer or
by the Treasurer. In the absence or disability of the Treasurer, the duties
of that office shall be performed by the Assistant Treasurer designated by the
Chief Executive Officer.
H. Controller. The Controller shall be the Administrative Officer in
charge of accounting functions of the Corporation. The Controller shall
perform such other duties as may from time to time be prescribed by the Board
of Directors, or by the Chief Executive Officer.
I. Assistant Controller. The Assistant Controllers shall perform such
duties as may be assigned from time to time by the Chief Executive Officer or
by the Controller. In the absence or disability of the Controller, the duties
of that office shall be performed by the Assistant Controller designated by
the Chief Executive Officer.
J. Secretary. The Secretary shall attend all meetings of the Board of
Directors and of the Executive Committee and all meetings of the shareholders,
and shall record the minutes of all proceedings in books to be kept for that
purpose. The Secretary shall be responsible for maintaining a proper share
register and stock transfer books for all classes of shares issued by the
Corporation and shall give, or cause to be given, all notices required either
by law or by the Bylaws. The Secretary shall keep the seal of the Corporation
in safe custody and shall affix the seal of the Corporation to any instrument
requiring it and shall attest the same. The Secretary shall have such other
duties as may be prescribed by the Board of Directors or the Chief Executive
Officer.
K. Assistant Secretary. The Assistant Secretaries shall perform such
duties as may be assigned from time to time by the Chief Executive Officer or
by the Secretary. In the absence or disability of the Secretary, the duties
of that office shall be performed by the Assistant Secretary designated by the
Chief Executive Officer.
L. Other. Such other Officers as may from time to time be appointed by
the Board of Directors shall have such duties and authority as may be assigned
to them from time to time by the Board or by the Chief Executive Officer.
SECTION 15. Board Committees.
A. Executive Committee. The Board of Directors, as soon as may be
convenient after the election of Directors in each year, may by a resolution
passed by a majority of the whole Board appoint three or more of their number
to constitute an Executive Committee which, subject to the provisions of the
charter of the Corporation and of the Bylaws, shall have and may exercise
during the intervals between the meetings of the Board all of the powers
vested in the Board in the management of the business, affairs and property of
the Corporation, except as limited by these Bylaws, the Articles of
Incorporation, the laws of the State of Montana, or a resolution of the Board
of Directors. The Board shall have the power at any time to change the
membership of such Committee and to fill vacancies in it. The Executive
Committee may make rules for the conduct of its business and may appoint such
committees and assistants as it may deem necessary. A majority of the members
of said Committee shall constitute a quorum.
B. Other Committees. The Board of Directors, by resolution adopted by a
majority of the full Board of Directors, may designate, from time to time,
from among its members one or more committees, in addition to the Executive
Committee, each of which, to the extent provided by resolution adopted by a
majority of the full Board of Directors, shall have and may exercise all of
the authority of the Board of Directors, except to the extent that the
authority of any such committee expressly shall be limited by the provisions
of these Bylaws, of the Articles of Incorporation or of the laws of the State
of Montana.
SECTION 16. Miscellaneous Board Authority. The Board of Directors is
authorized:
(A) Banking. To select such depositaries as they shall deem proper for
the funds of the Corporation. All checks, drafts or orders for the payment of
money against such deposited funds and all notes and acceptances shall be
signed and countersigned by persons to be specified by the Board of Directors
or the Executive Committee.
(B) Director Compensation. To authorize the payment of
compensation to the Directors for services to the Corporation, including fees
for attendance at meetings of the Board of Directors and of the Executive
Committee and all other committees and to determine the amount or basis of
such compensation and fees;
(C) Record Dates. To fix (in lieu of closing the stock transfer books,
as authorized by Section 10) in advance a date, not exceeding seventy (70)
days before and during any meetings of shareholders, the payment of any
dividend, the allotment of rights, or the date when any change or conversion
or exchange of shares shall go into effect, as a record date for the
determination of the shareholders entitled to notice of and to vote at any
such meeting, or entitled to receive payment of any such dividend, or any such
allotment of rights, or exercise such rights, as the case may be,
notwithstanding any transfer of any shares on the books of the Corporation
after any such record date fixed as aforesaid.
SECTION 17. Corporate Seal. The corporate seal of the corporation shall
be in such form as the Board of Directors shall prescribe.
SECTION 18. Amendment of Bylaws. Either the Board of Directors or the
shareholders entitled to vote for the election of Directors may alter or amend
these Bylaws at any meeting duly held as above provided, the notice of which
includes notice of the proposed amendment. Any such alteration or amendment
shall be made in accordance with Section 35-1-234, M.C.A.
SECTION 19. Disposition of Assets.
A. Disposition in Ordinary Course of Business. The Board of Directors
shall have authority to sell, lease, exchange or otherwise dispose of, the
whole or any part of the property and assets of every kind and description of
the Corporation in the ordinary and usual course of business, for property,
cash, or for the whole or any part of the capital stock of any other corpora-
tion, whether domestic or foreign, or otherwise, as the Board may determine,
and upon such terms and conditions as the Board may determine. Said Board
shall have plenary powers in carrying out the authority herein granted.
B. Mortgage or Pledge. The Board may mortgage or pledge any or all the
property and assets of the Corporation, whether or not in the usual and
regular course of business, upon such terms and conditions, and for such
consideration, which may consist in whole or in part of money or property,
real or personal, including shares of any other corporation, domestic or
foreign, as shall be authorized by the Board of Directors.
C. Disposition of All or Substantially All Assets. The Board may, by
resolution, recommend the sale, lease, exchange or other disposition of all or
substantially all the property and assets of the Corporation, and direct the
submission of the resolution to a vote of the shareholders at either a regular
or special meeting. Written notice shall be given each shareholder, whether
or not entitled to vote at such meeting, at least thirty (30) days before such
meeting, and shall state that the purpose, or one of the purposes, is to
consider the proposed sale, lease, exchange, or other disposition. At such
meeting, the affirmative vote of holders of two-thirds (2/3) of the shares
entitled to vote thereat is required to authorize such sale, lease, exchange
or other disposition. Nevertheless, the Board may thereafter abandon such
sale, lease, exchange or other disposition without further shareholder action.
SECTION 20. Office of the Corporation. There is an administrative
organization within the corporation called the Office of the Corporation,
consisting of such persons as the Chief Executive Officer may designate. The
function of the Office of the Corporation is to provide supervision, policy
direction and corporate services for all branches of the business of the
Company and its subsidiaries.
SECTION 21. Corporate Acquisition of its Own Shares.
The Company may acquire its own shares, and shares so acquired shall
constitute authorized and issued shares.
Exhibit 10(a)(v)
January 1, 1996
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:
Tier1.let
1
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. 33-56739, 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. 33-43655, to the incorporation by reference in the Prospectus
constituting part of the Registration Statement on Form S-8 No. 33-64576, to
the incorporation by reference in the Prospectus constituting part of the
Registration Statement on Form S-8 No. 33-24952, to the incorporation by
reference in the Prospectus constituting part of the Registration Statement on
Form S-8 No. 33-28096, to the incorporation by reference in the Prospectus
constituting part of the Registration Statement on Form S-3 No. 33-32275 and to
the incorporation by reference in the Prospectus constituting part of the
Registration Statement on Form S-3 No. 33-55816 of our report dated February 9,
1996 appearing on page 53 of The Montana Power Company's Annual Report on
Form 10-K for the year ended December 31, 1995.
/s/ PRICE WATERHOUSE LLP
Portland, Oregon
March 22, 1996
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED BALANCE SHEET AT 12/31/95, THE CONSOLIDATED INCOME STATEMENT AND
CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE 12 MONTHS ENDED 12/31/95 AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-START> JAN-01-1995
<PERIOD-END> DEC-31-1995
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,542,349
<OTHER-PROPERTY-AND-INVEST> 483,267
<TOTAL-CURRENT-ASSETS> 272,192
<TOTAL-DEFERRED-CHARGES> 288,283
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,586,091
<COMMON> 691,043
<CAPITAL-SURPLUS-PAID-IN> 2,271
<RETAINED-EARNINGS> 252,164
<TOTAL-COMMON-STOCKHOLDERS-EQ> 945,478
0
101,416
<LONG-TERM-DEBT-NET> 614,351
<SHORT-TERM-NOTES> 96,348
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 23,529
0
<CAPITAL-LEASE-OBLIGATIONS> 2,223
<LEASES-CURRENT> 1,275
<OTHER-ITEMS-CAPITAL-AND-LIAB> 801,471
<TOT-CAPITALIZATION-AND-LIAB> 2,586,091
<GROSS-OPERATING-REVENUE> 953,539
<INCOME-TAX-EXPENSE> 21,574
<OTHER-OPERATING-EXPENSES> 842,187
<TOTAL-OPERATING-EXPENSES> 863,761
<OPERATING-INCOME-LOSS> 89,778
<OTHER-INCOME-NET> 10,947
<INCOME-BEFORE-INTEREST-EXPEN> 100,725
<TOTAL-INTEREST-EXPENSE> 43,788
<NET-INCOME> 56,937
7,227
<EARNINGS-AVAILABLE-FOR-COMM> 49,710
<COMMON-STOCK-DIVIDENDS> 86,791
<TOTAL-INTEREST-ON-BONDS> 37,885
<CASH-FLOW-OPERATIONS> 268,890
<EPS-PRIMARY> 0.92
<EPS-DILUTED> 0.92
</TABLE>
SUBSIDIARIES OF REGISTRANT Exhibit 21
Percentage of Voting
Securities Owned
by Registrant
Canadian-Montana Gas Company Limited
An Alberta Corporation 100
Canadian-Montana Pipe Line Company
An Alberta Corporation 100
Glacier Gas Company
A Montana Corporation 100
Colstrip Community Services Company
A Montana Corporation 100
Continental Energy Services, Inc.
A Montana Corporation 100
EMPECO, Inc.
A Montana Corporation
(A wholly-owned subsidiary of Continental
Energy Services, Inc.) 100
EMPECO II, Inc.
A Montana Corporation
(A wholly-owned subsidiary of Continental
Energy Services, Inc.) 100
EMPECO III, Inc.
A Montana Corporation
(A wholly-owned subsidiary of Continental
Energy Services, Inc.) 100
EMPECO IV, Inc.
A Montana Corporation
(A wholly-owned subsidiary of Continental
Energy Services, Inc.) 100
EMPECO V, Inc.
A Montana Corporation
(A wholly-owned subsidiary of Continental
Energy Services, Inc.) 100
EMPECO VI - TE, Inc.
A Montana Corporation
(A wholly-owned subsidiary of Continental
Energy Services, Inc.) 100
EMPECO VII - TX3, Inc.
A Montana Corporation
(A wholly-owned subsidiary of Continental
Energy Services, Inc.) 100
MP 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
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
Intercontinental Energy Corporation
A Texas 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
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 12
THE MONTANA POWER COMPANY
Computation of Ratio Earnings to Fixed Charges
(Dollars in Thousands)
Twelve Months
Ended
December 31, 1995
Net Income $ 59,053
Income Taxes 21,573
$ 80,626
Fixed Charges:
Interest $ 47,330
Amortization of Debt Discount,
Expense and Premium 1,567
Rentals 35,300
$ 84,197
Earnings Before Income Taxes
and Fixed Charges $164,823
Ratio of Earning to Fixed Charges 1.96 x
